Executive Summary

• The first gas production from northern Alaska will focus on the proven, low-cost reserves at Prudhoe Bay (26 tcf).

• The most likely scenario for exports of northern Alaska gas is a gas pipeline down existing highways from Prudhoe Bay to Alberta, Canada. No decision has yet been announced. The State of Alaska, Yukon Territory, and most stakeholders advocate a highway route. Existing regulatory permits and international treaties, subject to review, authorize the highway route.

• Phillips Alaska estimates that prices above $3.50/mcf at Chicago city gate are needed for economic success. Chicago city gate prices were approximately $8/mcf in January 2001.

• Gas delivery to U.S. via gas pipeline from Prudhoe Bay is not expected before years 2007-2010. Regulatory delays or litigation could delay it.

• The gas pipeline will be sized for efficient transportation of the known gas reserves at Prudhoe Bay. For a 4.0 billion cubic feet per day pipeline, excess capacity would become available in year 2023 (assuming a 2007 start up).

• Cook Inlet remaining natural gas reserves (2.56 tcf) will be depleted by year 2012. New gas sources must be located soon to supply the majority of the State’s population which lives in the area around Cook Inlet.

• The most attractive gas province in the Bering Sea is North Aleutian basin, which is closed by moratorium until year 2012.

• LNG export models are required for future Bering Sea gas production. Potential gas resources cannot be taken to the U.S. West Coast because there are no LNG receiving facilities. The most likely LNG export models deliver gas to Japan or other Asian Pacific Rim countries.

• Alaska has a huge resource base of discovered and undiscovered gas (217.91 tcf), but 88 percent of this gas is undiscovered. Expensive and time-consuming exploration programs will be required to identify new commercial gas fields.

Alaska contains 39.88 trillion cubic feet (tcf) of gas remaining in developed and known undeveloped fields. Some of this gas is in fields too small or remote to justify economic development. Of the known gas reserves, 26.92 tcf may be considered available for export at appropriate market prices and pending construction of new gas transportation systems. Most of this gas is in onshore fields and mostly beneath State of Alaska surface or submerged lands. No Federal offshore gas reserves are considered to be readily available for export at present.

Three percent (0.92 tcf) of Alaska’s exportable gas reserves occur within fields in the Cook Inlet basin of southern Alaska and are at present dedicated to future LNG exports to Japan. Cook Inlet has 2.56 tcf in total remaining gas reserves, most of which is used locally or converted to fertilizer feedstock. At present rates of consumption, all Cook Inlet gas reserves will be depleted by year 2012.

Ninety-seven percent (26 tcf) of Alaska’s exportable gas reserves occur within fields in or near the Prudhoe Bay field in northern Alaska. The Prudhoe Bay area gas reserve base totals 30.90 tcf (developed fields and Point Thomson field, not including carbon dioxide), but some of this gas will be consumed (current rate 0.2 tcf/yr) by future (oil and gas) production activities at Prudhoe Bay. The stranded gas reserves at Prudhoe Bay are presently attracting proposals for construction of a gas transportation system that can take the natural gas to markets outside of Alaska.

In the Mackenzie delta area of Canada (300 miles east of Prudhoe Bay), exploration drilling from 1970 and 1989 discovered 53 oil and gas pools about equally divided between the onshore and offshore areas. The Mackenzie delta area contains approximately 9-12 tcf of discovered gas, some of which may be in pools sufficiently large to justify construction of a new gas pipeline to take the gas south to Alberta. The largest gas field is Taglu (2.07 tcf) located onshore. All of the Mackenzie delta discoveries are stranded at the present time, although several development proposals are under consideration.

A total of 83 exploration wells have tested prospects in the Federal waters offshore Alaska since 1976. Exploration results have been disappointing, and the few significant oil and gas discoveries made in the Arctic remain undeveloped due to high capital costs and uncertain prices. Two offshore oil fields, Liberty and Northstar, will begin production in 2001-2003, but the associated gas will be used for lease operations. The Burger well, located on the Chukchi shelf 360 miles west of Prudhoe Bay, penetrated the largest gas pool found to date in the Alaska Federal offshore. However, Burger is located in a formidable setting far from existing infrastructure and is uneconomic to develop with current technology and price conditions.

Most (82%) of the 190.99 tcf of undiscovered natural gas resources forecast for Alaska and the Alaska Federal offshore occur in the Arctic. If the undiscovered gas resources in the Mackenzie delta (53 tcf) are added to those onshore in northern Alaska (63.5 tcf), and Federal submerged lands on the Beaufort (32.07 tcf) and Chukchi shelves (60.11 tcf), the Arctic regional undiscovered gas potential totals 208.68 tcf. This volume is equal to 40% of the total U.S. undiscovered conventional gas resource base (526 tcf). Arctic Alaska and the Mackenzie delta seem destined to someday become major producing areas for natural gas. However, a significant fraction of the undiscovered gas resources could occur in small, remote accumulations that may never be profitable to develop.

Across Alaska and the Alaska offshore, unconventional sources like gas hydrates and coal bed methane are estimated to contain up to 170,000 tcf of natural gas in place. Most of this hypothetical natural gas resource is contained in gas hydrates that are located far offshore in water depths exceeding 300 m and will remain inaccessible for the foreseeable future. However, 37 to 44 tcf of gas are estimated to occur in sub-permafrost gas hydrates in and around the Prudhoe Bay-area developed oil fields and might be exploited on an experimental basis once a gas transportation infrastructure is installed.

Resource assessments in 1995 and 2000 estimated the total undiscovered conventionally recoverable gas resource base and the fractions of that gas resource base that could be profitable to develop. Several Alaska provinces, onshore and offshore, were found to potentially hold economic gas resources at landed market prices of $2.11 and $3.52/mcf (constant $2000, equivalent to oil at $18/bbl and $30/bbl). At $2.11/mcf paid at a variety of markets, 6.172 tcf gas might be economic to develop across Alaska (5.14 tcf for offshore alone). At $3.52/mcf, 12.23 tcf gas might be economic to develop (8.67 tcf for offshore alone). The undiscovered economically recoverable gas resources (12.230 tcf) represent only 6% of the 190.99 tcf total undiscovered conventionally recoverable gas resource base for all of Alaska.

At high gas prices like those witnessed in the U.S. in recent months, economic recoverability improves for most offshore Alaska provinces. At a gas price of $6/mcf (constant $2000) delivered to a variety of markets, the Alaska Federal offshore could contain a total of 35.78 tcf of undiscovered economically recoverable gas. At $6.00/mcf, 20.0 tcf could be economic to co-produce with oil resources on the Chukchi shelf and deliver as LNG to Pacific Rim markets. Associated gas resources produced through new offshore oil fields on the Beaufort shelf and delivered to a plantgate at Prudhoe Bay become economic at prices of $1.00/mcf or higher, with 4.66 tcf economically recoverable at $6/mcf. If produced gas is delivered to a hypothetical plantgate at Kivalina—the port for the Red Dog mining operation—Hope basin could have economically recoverable gas resources of 2.27 tcf at $6/mcf. Not all basins invite economic development. Even at a $6.00/mcf price, most of the Bering Sea provinces remain uneconomic. Gas prices of $10/mcf to $15/mcf would be required to support significant economic gas development in Norton basin, St. George basin, or Navarin basin. At $6/mcf, North Aleutian basin in southern Bering Sea offers 5.90 tcf of undiscovered, economically recoverable gas. However, North Aleutian basin is under a moratorium forbidding oil and gas leasing, exploration, or development until year 2012. At $6/mcf delivered to the local gas transmission pipeline network in Cook Inlet region, the Lower Cook Inlet (Federal waters) could have 1.24 tcf of undiscovered economically recoverable gas. At $6/mcf delivered as LNG to Japan, the Shumagin-Kodiak shelf and Gulf of Alaska shelf could have 1.40 tcf and 0.31 tcf, respectively, of undiscovered economically recoverable gas.

The Prudhoe Bay-area gas reserves (26 tcf ) are the key assets that will drive near-term strategic decisions about how to transport and market stranded natural gas from northern Alaska. Since 1977, natural gas recovered during oil production has been re-injected to increase oil recovery or used as fuel for production facilities. Over 35 tcf of gas has already been produced and re-injected or consumed at the Prudhoe Bay area fields. In 1999, gross gas production from the North Slope oil fields was 3.15 tcf (8.63 bcfpd) of which 93 percent was re-injected.

The 5.8 billion barrels oil reserves remaining (as of late 1999) in the Prudhoe Bay area fields (originally17 billion barrels) are now only a little larger than the remaining gas reserves—an energy asset equivalent to 4.6 billion barrels of oil. Northern Alaska oil production is declining precipitously and there is some concern about when production will fall below the minimum required to profitably operate the Trans Alaska oil pipeline (TAPS). As the Prudhoe Bay area oil fields begin to approach depletion, daily gas production is increasing and gas-handling capacities may someday further constrain oil production. Expansion of gas-handling facilities may be required to allow oil production to continue at optimum rates, or, at least at rates sufficient for TAPS operations. Alternatively, gas sales out of Prudhoe Bay could help avoid capital outlays for new gas-handling equipment. Limited gas sales could begin at any time from the Prudhoe Bay-area fields without affecting recovery of the remaining 5.8 billion barrels of oil reserves. Major gas sales could begin after year 2015 with no harm to ultimate oil recoveries, and the impacts of earlier gas sales could possibly be mitigated through measures like increased waterflood and carbon dioxide re-injection (Meyers, 2000).

At present, three concepts are in the forefront for commercializing the stranded gas resources in northern Alaska and Mackenzie delta:

• A New Pipeline Connecting to the Canadian gas pipeline network. Build conventional or high-pressure gas pipelines to carry the gas from Prudhoe Bay and Mackenzie delta to northern Alberta or British Columbia, where the new pipeline would join the Canadian pipeline network and supplement ongoing transmission gas exports to the U.S. Pipeline capacities of 2.5 bcfpd (0.9 tcf/yr) or 4.0 bcfpd (1.46 tcf/yr) delivered to the western Canada pipeline network typify most proposals.

• Liquefied natural gas (LNG) to Asian Pacific Rim. Build a conventional or high-pressure gas pipeline that carries the gas from Prudhoe Bay-area fields to a port in southern Alaska, where the gas is chilled to liquefied natural gas (LNG) and loaded on special LNG tankers for transport to the Asian Pacific Rim or perhaps the U.S. West Coast via return pipeline from hypothetical a port in western Mexico. System throughput for current proposals ranges from 1.5 bcfpd (0.5 tcf/yr) to 2.5 bcfpd (0.9 tcf/yr).
  
• Gas to liquids (GTL) and tankers to U.S. West Coast. Build a new facility in the Prudhoe Bay area and use GTL technology to convert natural gas to middle-distillate (diesel-like) liquids. The GTL product could be pumped in segregated batches through the Trans Alaska oil pipeline and then transported by tankers to the U.S. West Coast. A 50,000 bpd (0.5 bcfpd or 0.2 tcf/yr) plant has been promoted by one group, but BP-Amoco, a major owner of the gas at Prudhoe Bay, is presently building a small experimental GTL plant at Nikiski in Cook Inlet, Alaska (operational in 2002).

The original proposal for a gas pipeline through Canada—the Alaska Natural Gas Transportation System (ANGTS) and now sometimes called the "Highway Route"—followed the Dalton Highway from Prudhoe Bay to Fairbanks and then followed the Alaska Highway to central Alberta. A 1995 study published by the ANGTS group (abstr. by Thomas and others, 1996, p. 3-4) estimated that delivery costs for their $16.7 billion project would range from US$2.82/mcf to US$4.17/mcf in $1995 (or $3.29/mcf to $4.86/mcf in $2000). A similar "highway" gas pipeline project now being studied by the Prudhoe Bay gas owners would cost US$10 billion (2.5 bcfpd line) to US$12 billion (4.0 bcfpd line) and could profitably deliver gas to Chicago for $3.50/mcf (Meyers, 2000). Chicago city gate prices were approximately $8/mcf in January 2001. U.S. domestic natural gas demand, now at 22 tcf/year, is predicted to rise to 35.57 tcf/year by year 2020 (AEO, 2000, tbl. A1), thus ensuring a future of strong demand for any gas that can be profitably brought to the U.S. market from northern Alaska or Canada.

Alaska has the only LNG export operation in the U.S. Small amounts of LNG (0.06 tcf/year) from gas fields in Cook Inlet have been sent to Yokohama, Japan since 1971. A much grander LNG export model, shipping perhaps 0.9 tcf/year, has been proposed by Yukon Pacific Corporation for moving gas from northern Alaska into the Asian Pacific Rim and U.S. West Coast markets. The LNG project at the largest scale would require construction of a new gas conditioning plant at Prudhoe Bay, an 800-mile gas pipeline, a new LNG plant and marine terminal at Valdez in southern Alaska, and a new LNG tanker fleet, all for approximately $12.76 billion ($2000). No economic studies of the most recent LNG proposals are publicly available. A 1995 study by Thomas and others (1996) using a 0.85 tcf/yr LNG project costing $16.03 billion ($1995) found that a flat world oil price of $19.36/bbl ($1995) was required for the LNG project to economically "breakeven" (NPV₁₀=0). The AEO (2000) Reference Case forecasts that world oil will reach this price in year 2015. A $19.93 world oil price is approximately equivalent to an LNG price of $3.77/mcf (in September 2000, Cook Inlet LNG shipments to Japan were receiving $4.33/mcf). A 1999 DOE update study by Robertson (1999) found the LNG project to be unprofitable (NPV₁₀= — $2,402 billion), in fact providing the poorest return of all marketing concepts modeled by that study. An LNG export volume of 0.9 tcf/year would be equal to a very large fraction (28%) of the entire 1998 Asian Pacific rim LNG market (3.225 tcf/year). The chief risk element of the LNG proposals is that such large exports might flood the principal market and cause a price collapse. Because of market risk and capital cost considerations, plans for smaller initial LNG-based projects (output as low as 0.46 tcf/year, costing $8.2 billion to construct) have also been proposed, but the economics of the smaller scale projects are not publicly available.

Gas-to-liquids (GTL) technology forms an attractive option because it can supplement the throughput of the Trans Alaska oil pipeline (TAPS) and perhaps extend the operating life of this critically important oil transportation system decades into the future. The addition of GTL liquids to the oil transportation system would also moderate per-barrel oil pipeline tariffs, which are expected to rise in the future as the volume of pipeline throughput falls. The continued existence of the oil pipeline and a lowering of future oil pipeline tariffs are critical to the economics of future development of smaller, undiscovered oil fields in northern Alaska and the Arctic Federal offshore. A 1995 study by Thomas and others (1996) of a hypothetical 300,000 bpd (3 bcfpd or 1.1 tcf/yr) northern Alaska GTL project costing $13 billion found that a "breakeven" (NPV₁₀=0) flat world oil price of $19.94/bbl ($1995) was required for economic viability. The AEO (2000) Reference Case forecasts that world oil prices will not reach this price until after year 2020. However, in September 2000, the actual world oil price averaged $31.10/bbl (or $26.69/bbl in $1995). GTL, or at least its modern component processes, involve relatively new technologies that are only now entering commercial applications. A recent study of northern Alaska GTL economics by Robertson (1999) revealed that incremental construction of several small GTL facilities allowed for "learning"—resulting in cost reductions to facilities built later in the life of the project. This "incremental" GTL model provided the most favorable economic outcome. Future market demand for GTL product is expected to be robust. The chemical conversion of natural gas to liquid hydrocarbons creates an essentially refined product that is free of polluting agents and that as a transportation fuel can command premium market prices, particularly on the U.S. West Coast, where ultra-clean motor fuels will be mandated.

The gas transportation system that is eventually constructed to take Prudhoe Bay gas reserves to market will be scaled to the known reserve volumes. For this reason, the gas transportation system will be completely filled for years after start up with production from Prudhoe-area gas fields. Newly-discovered gas will have to await declines in the area production levels such that excess capacity (unfilled space) develops in the gas transportation system. If we assume that a gas pipeline to Prudhoe Bay is operational by year 2007 and that excess capacity becomes available after 90 percent depletion of known reserves, the earliest shipments of newly-discovered gas would be in year 2015 for an 8 bcfpd line, or year 2023 for a 4 bcfpd line, or year 2033 for a 2.5 bcfpd line. An 8 bcfpd gas pipeline has not been proposed but this is the present rate of gas recycling in the Prudhoe-area fields. There are currently proposals for the two smaller pipelines, of which the 4 bcfpd pipeline seems to be favored. Of course, if substantial new gas discoveries justified the additional expense, increasing pipeline pressure (adding compression equipment) could increase pipeline capacity at any time.

Northern Alaska and its contiguous continental shelves are richly endowed with natural gas. However, finding and developing any significant fraction of this undiscovered resource will prove very costly. At the current slow pace of leasing, exploration, and development, a significant fraction of the undiscovered natural gas endowment of northern Alaska could remain unavailable to meet market demands for many decades.

Because of the long lead-time required for major construction projects, the time may now be at hand for decisions about how to export the stranded natural gas reserves of northern Alaska and northwestern Canada. These decisions will lead to construction of a huge natural gas marketing infrastructure costing billions of dollars. Gas production strategies and new infrastructure will determine the character of oil and gas development in northern Alaska and northwestern Canada for many decades to come.