Despite The Challenges, Renewed Interest in Oil and Gas Development Focuses on Alaska

The United States is highly dependent on imported oil – a fact driven home in 2008, and only partly obscured last fall by the return of the $40 barrel. During last year’s campaign, President-Elect Obama called for a two part strategy: foster alternatives to oil and gas, particularly in the electric power and transportation sectors, but also encourage more domestic oil and gas exploration and development.[1] Alaska has perhaps the greatest potential of any state for bringing new oil and gas supplies to the U.S. market, and there is renewed interest in overcoming the challenges – both physical and regulatory – of finding those resources and bringing them to market.

The permitting and environmental challenges of energy development in Alaska are formidable, and environmental groups have famously opposed drilling as threatening endangered polar bears and other species. This article sets out the permitting and regulatory challenges facing energy development companies who seek to develop Alaska’s oil and gas reserves, and summarizes key findings of the federal and state courts.

I. Background:

• Oil Production

Oil production from Arctic Alaska, North of the Brooks Range – commonly called the “North Slope” – peaked in 1989 at 2.1 million barrels a day, and at that time was about one quarter of U.S. production. Today, average production from the North Slope fields is between 700,000 and 800,000 barrels a day.[2] Increasing, or simply maintaining, this production will require development of new fields on the North Slope, or offshore in Arctic waters.

Expanding onshore exploration in Alaska is controversial, and not just when it comes to the coastal plain of the Arctic National Wildlife Refuge (“ANWR”). ANWR is to the east of existing North Slope oil & gas development, which is almost exclusively on state-owned lands. To the west of the existing fields is the National Petroleum Reserve-Alaska (“NPR-A”), a 23 million-acre area of federal lands. During the recently concluded election campaign, President-Elect Obama called for concerted efforts to explore and produce oil from several areas in the United States, including NPR-A.[3] But efforts to open up new areas of NPR-A also have faced opposition in the courts.

States own the submerged lands beneath the territorial sea, which extends out three miles from the ocean shore. The State of Alaska has opened up much of the territorial sea offshore from Prudhoe Bay, and even ANWR, to oil and gas exploration, and there are several satellite fields producing oil from State waters off Prudhoe Bay. New fields continue to be developed from these State waters,[4] but their untapped potential appears to be dwarfed by that of the adjacent federal lands.

The federal government owns the submerged lands that extend from the outer edge of the territorial sea out to 200 miles, called the outer continental shelf (“OCS”), and the mineral rights for those lands are managed under the federal Outer Continental Shelf Lands Act.[5] The OCS lands from Point Barrow eastward to the Canadian border are beneath the Beaufort Sea. Estimates are that the federal OCS lands beneath the waters of the Beaufort may contain 8 billion barrels of oil and nearly 30 trillion cubic feet of natural gas.[6] (The Canadian portion of the Beaufort Sea, off the mouth of the Mackenzie River, also has substantial oil and gas potential).[7]

The lands beneath the Chukchi Sea, off Alaska’s northwest coast west of Point Barrow, are believed to hold up to 15 billion barrels of recoverable oil reserves, and 77 trillion cubic feet of recoverable natural gas reserves.[8] Five wells were drilled in the Chukchi Sea in the 1980s, but the region received little attention after that, until quite recently, as discussed below.

• Natural Gas Potential

Alaska also has significant known natural gas reserves, enough to supply 4 to 4.5 billion cubic feet of gas a day to a proposed Alaska gas pipeline for approximately 15 years.[9] MMS has estimated that Arctic Alaska, and nearby offshore areas in the Arctic Ocean, may contain as much as six times the currently known natural gas reserves.[10]

Two major oil companies, ConocoPhillips and BP, have created a joint venture, which they have named “Denali – The Alaska Pipeline LLC,” to advance their pipeline project.[11] These two companies, along with Exxon, are the holders of North Slope leases giving them rights to most of the known natural gas reserves in the Prudhoe Bay area. They propose a 2000-mile pipeline from the North Slope to existing oil fields in Alberta, Canada.[12] From there, the line may connect to existing pipelines, or they may build an additional 1500 miles of pipeline to U.S. markets in the Chicago area.[13]

A similar pipeline has been proposed by TransCanada, owner of a major natural gas pipeline network in Canada, including pipelines extending from existing natural gas fields in Alberta to U.S. markets in Chicago. TransCanada proposes a 1700-mile pipeline from the North Slope to the Alberta Hub, where it would connect with the company’s existing pipeline network.[14] The TransCanada pipeline would deliver 4.5 billion cubic feet per day.

TransCanada was the sole qualified applicant under the Alaska Gasline Inducement Act (“AGIA”), a law backed by Alaska’s Governor Palin to encourage development of the gas line. In August, 2008, the State of Alaska granted a license to TransCanada under AGIA, which among other things entitles the company to receive up to $500 million from the State to support its development of the gas line project.

Both of these pipeline projects (of which only one is likely to be built) are premised on the discovery of additional natural gas on Alaska’s North Slope. In 2001, the federal Minerals Management Service (“MMS”) estimated that an additional 165 tcf remained to be discovered in the region, onshore on the North Slope and offshore in the Beaufort and Chukchi Seas.[15] This represents about 30 percent of the natural gas that MMS then estimated to be present, but not yet discovered, in the United States.

II. Permitting Energy Projects in Alaska

Oil and gas projects in Alaska must satisfy requirements that may be grouped into several categories: federal land access; environmental permits; and potential natural resource impacts (principally marine mammals and threatened and endangered species). In addition to other environmental requirements, State and local authorities also may exercise their authority under the federal Coastal Zone Management Act[16] to impose conditions that ultimately are incorporated into federally and state-issued permits, beyond what may be required under other federal or state laws.

A. Federal Land Access

1. Exploring Federal Lands for Oil & Gas

Members of Congress, backed by a Government Accountability Office (“GAO”) study, have criticized federal land managers for not encouraging more domestic oil & gas exploration and production on some 68 million acres of federal lands (40 million of which are under coastal waters) that already have been leased for that purpose.[17] But delays in exploring and developing existing leases are common – as the experience in Alaska amply demonstrates.

There has been a steady stream of litigation over federal proposals to lease Alaska lands for oil and gas, as well as over lease development, for several decades.[18] Much of it has concerned the adequacy of federal NEPA compliance, as the decision to lease these federal lands, as well as federal approval of major steps in lease development, may trigger environmental impact analysis requirements. In fact, for OCS lands, some form of NEPA review is required at four stages of the process: approval of lease sale program plans; offering of individual lease sales; approval of plans to explore individual leases; and approval of production and development plans.[19]

Shell Oil’s recent experience in Alaska illustrates the importance of carefully planning and preparing environmental impact documents that satisfy NEPA requirements, which is likely to require intensive coordination with federal land managers. It also highlights one of the most difficult choices project developers face in complying with NEPA: whether to wait the 18 months or two years it may take to complete an environmental impact statement (“EIS”), or to rely on existing environmental impact documents prepared at some earlier stage in federal review of the project – such as a programmatic EIS – supplemented by a more simple environmental assessment (“EA”) specific to the federal permit or decision currently needed for the project to proceed. It is often much quicker to rely on an EA that relies on, or “tiers to,” existing documents, but, as Shell has found, that course risks delays as well.

In February, 2007, Shell Oil received approval from MMS to drill up to 12 wells on OCS lands it had leased in the Beaufort Sea.[20] But Shell’s drilling plans were put on hold after a successful challenge under NEPA to the EA supporting federal approval of its drilling plan.[21]

MMS had prepared an EIS for its five-year lease sale plan in 2002, including the planned sale of leases of Beaufort Sea OCS lands.[22] It then held Beaufort Sea lease sales in 2003, 2004, and 2005.[23] Shell was a major participant in the lease sales, marking its return to the Alaska Arctic after a decade-long absence.[24] The individual MMS lease sales were supported by NEPA findings of no significant impact (“FONSI”), based on EAs that were tiered to the analysis in the original 2002 EIS that supported the five-year lease plan.[25]

In the summer of 2007, Shell planned to drill three wells on leases it obtained in one of these lease sales, at a site about 16 miles offshore that had previously been explored in the 1980s. MMS’s approval of this exploratory drilling plan also was supported by an EA, tiered to the original 2002 EIS.[26] It was this agency decision that drew the legal challenge, focused on whether the NEPA analysis of site-specific impacts on bowhead whales and oil spill risks was adequate. In the summer of 2007, Shell had drill ships and crews in position, but the Ninth Circuit issued a preliminary injunction that stopped the drilling program until the NEPA challenge was resolved.[27]

The Ninth Circuit heard argument on this appeal in December, 2007, and did not issue its decision until November, 2008.[28] When it did rule, the Ninth Circuit remanded for further evaluation of the potential impact of drilling on whale migration and other factors.[29] The Ninth Circuit found that, even though the EIS prepared for the five-year lease plan in 2002 had considered the potential impacts of drilling operations in the Beaufort, it had not considered the impacts of drilling occurring at the actual location planned by Shell, and the supplemental analysis contained in the EA was insufficient to satisfy NEPA.

The wait for a decision on the adequacy of the NEPA document cost Shell two drilling seasons and at least 200 million dollars.[30] Shell recently announced cancelation of all 2009 operations in the Beaufort while it waits for reconsideration of the 9th Circuit decision, and while the further analysis is completed.[31] Thus, the decision to rely on an EA to support approval of its drilling plans rather than prepare a site-specific EIS, has so far cost Shell three operating seasons in the Beaufort.

The choice between preparing an EA or an EIS ultimately is made by the federal agency, as it is their decision that triggers NEPA’s requirements (although the cost of a project-specific analysis is usually borne by the project developer). Still, the project developer must independently consider which path is likely to satisfy NEPA requirements, and must be prepared to advocate for that path with the agency. As Shell’s experience demonstrates, ultimately the project developer bears the burden of any problems with the environmental review process.

The potential for renewed exploration of the Chukchi Sea floor also has proved controversial. In the summer of 2008, environmental groups, joined by a local community, sued to block Shell from conducting seismic surveys. Seismic data indicates the underlying rock strata, and so is a necessary precursor to selecting drilling locations. After initially granting a temporary restraining order, the district court denied a preliminary injunction and allowed seismic surveys to proceed during the 2008 open-ice season.[32] The district court ruled that the environmental analysis supporting a federal permit to disturb walrus and whales satisfied NEPA requirements.[33]

The adverse legal result in the Beaufort apparently is not holding up Shell’s future plans in the Chukchi Sea. They currently plan additional field work in 2009, and may begin drilling wells in 2010.[34] However, they are understandably concerned that the precedent set in the Beaufort may also be used against the adequacy of the NEPA analysis supporting their Chukchi plans.[35]

NEPA also has come into play in federal efforts to lease onshore lands on Alaska’s North Slope. In 2002, environmental groups unsuccessfully challenged the adequacy of the Environmental Impact Statement prepared for a lease sale in NPR-A’s Northwest Planning Area, which covers about 8 million acres.[36] Environmental concerns include the extensive network of wetlands and tundra ponds in NPR-A, which provide nesting grounds for a wide variety of migratory birds. Despite the agency’s success in defending its EIS, the Shell experience in the Beaufort suggests that any company planning to explore leases in NPR-A, particularly in the more environmentally sensitive areas, must carefully evaluate the adequacy of the existing environmental review documents, and the extent to which additional site-specific analysis is needed to support their drilling plans.

The Bureau of Land Management has held five lease sales in NPR-A, and is currently administering more than 300 leases, totaling over 3 million acres.[37] The most recent lease-sale, on September 24, 2008, drew bids of $35 million on 150 tracts totaling 1.6 million acres. There is no oil production from NPR-A today, but 25 exploratory wells have been drilled since 2000.[38]

2. Pipeline and Infrastructure Development

The proposed Alaska natural gas pipeline faces a different federal land access issue: obtaining a right-of-way across several hundred miles of federal lands. The criteria for pipeline rights-of-way across federal lands are contained in the Federal Land Policy and Management Act (“FLPMA”).[39] A grant of a federal right-of-way must contain conditions assuring compliance with air and water quality standards, minimizing damage to fish and wildlife habitat, and requiring compliance with applicable state standards.[40] Any right-of-way also requires a commitment to restoration at the end of the useful life of the project, financial assurance, and no-fault liability for damages or claims stemming from use of the right-of-way.[41] Similar requirements apply in obtaining a right-of-way across the State of Alaska’s lands.[42]

B. Environmental Permits

Any significant development project requires a daunting list of permits and approvals. The following are a selection of the most significant requirements, including one new set that are expected to come into play in the near future: climate change-related restrictions on air emissions.

1. Air

Exploratory drilling operations, as well as oil and gas production facilities, require permitting under the federal Clean Air Act (“CAA”)[43] and its Alaska state law counterpart.[44] Exploratory drilling operations are, by their nature, relatively mobile. They also occur over relatively short time periods, and a company may plan to use a rig at several locations during a single drilling season. The State of Alaska has responded to this need by permitting exploratory rigs as temporary sources, allowing operations at multiple locations within a single permit.[45]

In Alaska, the pumps, compressors, and other equipment needed to produce oil, or to move it by pipeline, are commonly powered by gas turbines, and electric power is provided by turbines or large diesel engines. These combustion sources also require CAA permitting. Many of the combustion sources on the North Slope operate on natural gas, which is a very clean fuel. As a result, the major pollutant of concern is usually nitrogen oxides. Exploratory operations, or facilities more remote from the natural gas available around Prudhoe Bay, are more likely to use diesel fuel. Limiting factors in air permits for these facilities are more likely to be sulfur or particulate emissions.

Because of the significant size of the turbines and diesel engines used in the oil and gas fields, any new production facility, or any major modification to an existing facility, may exceed the emission thresholds that trigger the need for a Prevention of Significant Deterioration (“PSD”) air permit.[46] Two requirements come into play in PSD permitting: a pollution control technology standard, and ambient air quality impacts. Emissions for the permitted equipment must be controlled using the best available control technology (“BACT”).[47] Determining BACT requires a survey of the types of controls in place on similar equipment elsewhere, ranking them by control efficiency, and determining the most efficient control level that is achievable at the proposed project.

Before ambient impact analysis can be performed, local meteorological information is needed to support this computer modeling exercise. Under the regulations, up to a year may be needed to collect meteorological data.[48] But for most areas of the North Slope, existing meteorological data is available, or results may be interpolated from existing data, thus avoiding this permitting delay. The most significant issue in conducting ambient impact analysis on Alaska’s North Slope is the cumulative impact of any proposed new sources when combined with the permitted emissions from the existing North Slope facilities. This may be a constraint on a new project, particularly if located near the main existing production and transportation facilities.

2. Wetlands Fill

Land in Alaska is notoriously wet. This is particularly true for the North Slope, which due to the permafrost found at no great depth under the surface, is covered with a network of tundra and small ponds. The permafrost also presents an engineering challenge: if melted, the ice contained in the permafrost takes up less space, causing settling. Similarly, a melt/freeze cycle can cause what is called “jacking” – literally lifting of pilings and other buried structures out of the ground. The common response to the engineering challenge posed by permafrost has been to build all permanent structures on gravel pads placed upon the tundra, and to place most structures on pilings. Similarly, most pipelines are elevated on structures that are designed to avoid transmitting heat from the oil pipelines down into the frozen soil of the ground.

The construction of gravel pads on the North Slope, as well as roads and other permanent structures, invariably involves the filling of wetlands, which requires a permit under section 404 of the Clean Water Act (“CWA”),[49] under a program administered by the U.S. Army Corps of Engineers. Recent agency guidance may have an impact on whether 404 permits are required, at least in some areas of the North Slope.

In 2006, in Rapanos v. United States,[50] the U.S. Supreme Court considered the limits of federal jurisdiction over the filling of wetlands. The result was a somewhat confusing decision, due to the multiple opinions produced by the Court. However, a plurality rule emerged that the Corps has jurisdiction under the CWA over wetlands that “alone or in combination with similarly situated lands in the region, significantly affect the chemical, physical, and biological integrity of other waters more readily understood as ‘navigable.’”[51]

On December 3, 2008, the Corps of Engineers and the Environmental Protection Agency issued final guidance implementing the Rapanos decision.[52] They determined that CWA jurisdiction extends to: (1) wetlands adjacent to traditional navigable waters (those that actually support, or are capable of supporting, navigation); (2) wetlands abutting relatively permanent non-navigable tributaries; and (3), on a case-by-case basis, wetlands adjacent to seasonal tributaries, or adjacent to but not abutting relatively permanent tributaries.[53]

Under this guidance, the isolated wetlands that exist in many areas of the North Slope may no longer be subject to CWA jurisdiction, and so could be filled without obtaining a 404 permit. However, this guidance has not yet been applied to Alaska, and so its potential impact on future North Slope development remains uncertain.

3. Wastewater Discharge

The discharge of wastewater generated during drilling operations and oil and gas production activities requires a national pollution discharge elimination system (“NPDES”) permit under section 402 of the federal CWA.[54] In Alaska, the NPDES program has long been administered by the EPA. In late 2008, EPA agreed to delegate administration of the program to the State of Alaska,[55] and has begun a three-year transition process.[56] Responsibility for permits for oil and gas facilities will be among the last categories transferred to the State.

EPA has issued several general permits that authorize discharge from oil and gas activities in different areas of Alaska. Discharges from exploratory drilling operations in the Beaufort and Chukchi Seas are authorized by the Arctic General Permit.[57] This permit does not cover development and production facilities, which would require individual permits.

For North Slope onshore facilities, the wastewater directly produced by drilling operations is normally disposed of through injection into the well annulus or into injection wells. However, EPA has issued a general permit for wastewater discharges resulting from a variety of North Slope oil field operations, including domestic wastewater, gravel pit dewatering, construction dewatering, hydrostatic test water, stormwater, and mobile oil spill response.[58] This general permit expired on January 2, 2009, and has been administratively extended. EPA is currently working on renewal of the permit.

One other major general NPDES permit has been issued for oil and gas activity in Alaska’s Cook Inlet. The first Cook Inlet oil and gas platforms were installed in the 1960s, and operations in that region have been subject to general NPDES permits since the 1980s. The Cook Inlet general permit authorizes discharge of drilling muds and cuttings from existing development and production facilities, as well as the discharge of produced water.[59] It authorizes limited discharges from exploration activities, and does not authorize new development and production discharges. The most recent version of the Cook Inlet general permit took effect July 2, 2007. An appeal of the permit is pending before the Ninth Circuit.[60] A new production facility, the Osprey Platform, was added in Cook Inlet several years ago, and is subject to an individual NPDES permit.[61]

4. Coastal Zone Management

The federal Coastal Zone Management Act[62] directs states to develop coastal management programs that define the uses (including priority of uses) allowed in the coastal zone, establish guidelines and enforceable policies for coastal development, including energy facilities, and provide a process for state review of projects in the coastal zone.[63] These state programs are subject to approval by the Department of Commerce. All federal projects and federally issued permits must be “consistent to the maximum extent practicable with the enforceable policies” of approved state coastal management programs.[64]

The Alaska Coastal Management Program (“ACMP”) is administered by the State Department of Natural Resources, Office of Project Management and Permitting. That agency has produced a handbook that contains the applicable state and federal coastal zone regulations and statutes, which is available on line.[65]

Any federal project, or federally issued permit, in Alaska’s coastal zone must go through an ACMP consistency review. That consistency review process is governed by state regulations, which include an administrative appeal process called an “elevation.”[66] During this process, the proposed activity is evaluated under statewide standards,[67] as well as the applicable local coastal district’s enforceable policies.[68] Local districts also may identify “areas meriting special attention”[69] and develop “special area management plans.”[70] The local coastal district plans are subject to state and federal approvals, but once in place they add an additional layer of environmental requirements that must be satisfied.

Through the consistency review process, state and local district enforceable policies are translated into permit conditions and stipulations. These conditions are then incorporated into the permits or approvals issued by state and federal agencies, such as federal leases and rights-of-way, air permits, or wastewater discharge permits. Thus, the Coastal Zone Management Act and the ACMP are an additional source of environmental requirements, but do not themselves require any additional state or federal permits.

5. Oil Spill Prevention & Planning

Following the Exxon Valdez incident in 1989, the State of Alaska adopted stringent oil pollution prevention and planning requirements.[71] These requirements include pre-placement of spill response equipment, detailed spill response plans, financial assurance (bonding or other financial guarantees), and pre-approval of all such arrangements by the State.[72] The federal Oil Pollution Act of 1990 imposes similar requirements.[73] As oil exploration pushes out farther from the established base in the Prudhoe Bay area, spill planning and prevention becomes a significant logistical challenge, particularly when projects move beyond the exploration phase to the production of oil.[74]

6. Climate Change

Concern about climate change is adding another layer of complexity to future project development in Alaska and elsewhere, and not just because the signs of a changing climate are becoming visible in Alaska.[75] The infrastructure for producing oil and gas and transporting it from Alaska to market is powered by fossil fuels. If a national cap-and-trade system is adopted to control greenhouse gas emissions, that will increase operating costs, and could affect the economics of a major project like the proposed natural gas pipeline.

Alaska’s oil fields may also offer opportunities for carbon sequestration. In Texas and other older oil and gas provinces, carbon dioxide already is being used for enhanced oil recovery, and there are proposals to use EOR as a form of sequestration of anthropogenic CO2.[76] The remote location of Alaska’s fields make any transport of CO2 to Alaska for sequestration unlikely. However, there may be opportunities for sequestration of CO2 from sources in Alaska, including carbon produced in using Alaska’s large, and relatively untouched, coal reserves.[77]

C. Natural Resources

Probably the most significant natural resource-related concern on the North Slope is the potential impact of oil and gas operations on marine mammals, such as bowhead whales, walrus, and polar bears. The recent listing of the polar bear as a “threatened” species[78] under the Endangered Species Act (“ESA”)[79] is only the latest twist in long-running battles over the impact of Alaska oil and gas exploration on wildlife resources. There also have been – and continue to be – disputes over potential impacts on bowhead whales and other animals,[80] not only for their wildlife value, but also as subsistence food resources for the local Alaska Native communities.

Recently, the ESA listing of the polar bear, and their pre-existing protection under the Marine Mammal Protection Act,[81] have been used to try to block oil and gas activity in Arctic Alaska, both because of direct impacts on the polar bear, and based on the indirect impacts of global warming on Arctic sea ice. For example, the Center For Biological Diversity filed suit on July 11, 2008, challenging regulations allowing “incidental take” of polar bear and walrus during oil and gas exploration activities in the Chukchi Sea.[82] Litigation also is pending over the scope of protection afforded by the rule issued under section 4(d) of the ESA in conjunction with the polar bear listing.[83]

So far, these challenges have not been successful, primarily because federal agencies have rejected the premise that industry activities are a threat to polar bears, walrus, or bowhead whales. The substantial efforts that companies have made to mitigate those impacts certainly are important, but the deference that the courts grant to administrative agencies has favored this outcome. It remains to be seen whether officials of the incoming Obama administration will take the same position.

III. Conclusion

The demand for oil and natural gas in the United States far outstrips domestic supplies. Estimates are that the federal OCS and federal lands in Alaska and other states contain substantial amounts of oil and gas, which, if actually located and developed, could lessen U.S. reliance on energy imports – or at a minimum, maintain our existing production. But many of the most promising areas are very remote, like the Chukchi Sea in the Arctic Ocean, off Alaska’s northwest coast. Exploring these areas is physically challenging, and developing new fields in these areas will be as well. Nor will it be easy to bring Alaska natural gas to market, completing 1700-2000 miles or more of new, large diameter pipeline. In addition to the logistical hurdles, our environmental laws pose their own obstacles.

The process of obtaining access to federal lands, acquiring all required environmental permits, and satisfying regulators that impacts on sensitive wildlife and other natural resources will be avoided or minimized takes several years to complete. Litigation over permits and environmental impacts also can add years to the process – and an adverse ruling can derail a company’s whole exploration or development program, at enormous cost. But the continued strong demand for new energy sources will drive companies to pursue the opportunities that oil and gas prospects offer in Alaska, and to complete projects like the Alaska natural gas pipeline, to bring those resources to market. Before new exploration projects can succeed, and actually find developable oil and gas, they must first thread the needle of regulatory requirements, so that they are given the opportunity to look. The same is true for the proposed Alaska natural gas pipeline.

For more information on energy development generally, and particularly in Alaska, please contact Svend Brandt-Erichsen.