III. The Impacts of the Alaska Natural Gas Pipeline Act of 2002

The “Alaska Natural Gas Pipeline Act of 2002” contained in Title VII of S. 1766 calls for federal action to expedite the construction of a natural gas pipeline from North Alaska to the Lower 48 States. The provisions of the Alaska Natural Gas Pipeline Act are projected to result in the earlier construction of a pipeline than would be the case without this Act. The AEO2002 Reference Case, does not project the pipeline’s construction during the forecast period, out to 2020. Using the same basic assumptions adjusted for the provision of the Alaska Natural Gas Pipeline Act, this analysis projects that a pipeline linking northern Alaskan gas to Lower 48 markets would begin operating in 2020, lowering the lower 48 wellhead price by $0.06 per thousand cubic feet. The Low Oil and Gas Technology Case, developed as a sensitivity analysis for the AEO2002, assumes slower growth in technological change in the exploration and development of these energy resources, resulting in higher natural gas prices than in the AEO2002 Reference Case. This case also does not project the construction of a pipeline before 2020. However, under the proposed provisions in the Low Oil and Gas Technology Case, the pipeline would begin operation in 2014, and result in Lower 48 wellhead prices that are $0.32 per thousand cubic feet lower than the corresponding case without the provision by 2020.

Background

Alaska’s North Slope has extensive hydrocarbon reserves, including natural gas. To date, 35 trillion cubic feet of natural gas have been discovered. These are considered to be marketable reserves, which could be developed at low cost with existing technology, if there was a market for this production. Currently, Alaskan gas is not marketed in the lower 48 since there is no infrastructure to deliver gas produced in Alaskan fields to consumers in the rest of the United States. A pipeline connecting Alaskan fields with lower 48 consumers would allow the natural gas reserves that have already been identified to be marketed profitably, along with other undiscovered Alaskan gas resources. Increasing domestic supply could also reduce the prices paid by consumers for natural gas.

A pipeline for Alaskan natural gas has been discussed since the 1970’s. In 1977, the United States and Canada signed an agreement in principle for the Alaska Natural Gas Transportation System (ANGTS) that proposed the delivery of 2 billion cubic feet per day from the Alaskan North Slope, along the Alaskan-Canadian highway to near Calgary, Alberta, and down to the lower 48. Initial cost estimates for ANGTS, including delivery to the lower 48, were $14.6 billion (1988 estimate, in 1988 dollars.)⁷

With deregulation of U.S. natural gas and the development of lower-cost resources both in the Lower 48 States and Canada, interest in ANGTS waned. Discussion of a natural gas pipeline from Alaska resurfaced in 1999 and 2000, when high gas prices led to a re-evaluation of the feasibility of developing “stranded” Alaskan gas reserves. Phillips, BP, and ExxonMobil formed a partnership to investigate the potential of developing a gas pipeline, following roughly the route proposed by ANGTS or an alternate route across the Beaufort Sea to the MacKenzie Delta in Canada and then down to Alberta. The results of this study have not been released, but one preliminary report suggests that even though estimated pipeline costs are lower than they have been in other studies, the pipeline project is not feasible given current economic conditions.⁸

Alaska Gas Pipeline Methodology and Assumptions

In order to model the potential impacts of a natural gas pipeline running from Alaska to markets in the lower 48, several assumptions about the project were required. These assumptions are based on available information in reports and articles supplemented with consultation with industry and other government sources.

• Resources

The known reserves of 35 trillion cubic feet are considered to be stranded natural gas, or natural gas that could be developed but does not have a ready market, in this case due to geographic isolation. This analysis assumes that 26 trillion cubic feet of the 35 trillion cubic feet of reserves are available for commercial sales. The other 9 trillion cubic feet are assumed to be required for North Slope oil operations, including injection into oil reservoirs to maintain production. Developing 26 trillion cubic feet of the 35 trillion cubic feet may decrease potential oil production in the later years, particularly at Prudhoe Bay.

EIA assumes that these stranded reserves will be developed at a wellhead price of $0.80 per thousand cubic feet. This cost is substantially below projected average wellhead prices in the lower 48, but is consistent with the wellhead prices of stranded natural gas in other regions of the world. The lower price for stranded reserves is due to lower exploration costs associated with these reserves and the lack of other options for the owners of the stranded resource. Without other potential alternate buyers, the owners of stranded gas resources are willing to accept a lower price than they would in areas with easier access to markets.

• Pipeline specifications and costs

EIA’s estimates envision a pipeline capable of carrying 4 billion cubic feet per day, or 1.5 trillion cubic feet per year, from Alaska to the lower 48. The capital cost of the project from the North Slope to Alberta is assumed to be $10 billion (2000 dollars), based on more recent cost estimates.⁹ The estimated cost is lower than the original cost estimate for ANGST due to improvements in pipeline technology, such as composite construction materials.

The cost estimates that underlie EIA’s assumptions are based on a route roughly following the original ANGST proposal. The cost of the pipeline is sensitive to the proposed route, and a pipeline following an alternate route would likely have different costs.

• Required lower 48 prices

Based on the estimated cost of gas at the wellhead, capital costs, operating costs, and required rates of return, Alaska gas delivered by the proposed pipeline is estimated to be competitive when lower 48 wellhead prices are sustained at $3.15 per thousand cubic feet. This estimate includes a $0.70 per thousand cubic foot price differential between Alberta and the Lower 48, based on the historical price differentials in these markets. However, given the uncertainties inherent in these estimations and the historic pattern of sharp year-to-year volatility in natural gas prices, as well as the potential for natural gas prices to drop once the pipeline opens, EIA assumes that construction of the pipeline will only begin with sustained lower 48 wellhead prices of at least $3.50 per thousand cubic feet. This $0.35 cent risk premium ($3.50-$3.15) is assumed to compensate investors for the uncertainties, and is a contingency factor used by investors to estimate potential profitability.

• Pipeline Timing

EIA assumes that the pipeline will require 4 years to build after an initial planning and permitting period of 3 years. Construction will commence only if the average lower 48 wellhead price stays above the trigger price for each year in the planning period. The pipeline is assumed to operate at half capacity the first year it begins production (2 billion cubic feet per day), and then operate at full capacity each year after the first.

• Pipeline and Resource Expansion

EIA’s methodology assumes that there will be additional natural gas resources available beyond the 35 trillion cubic feet of previously-discovered reserves, albeit at a higher cost. The costs of these additional reserves are higher because of the exploratory costs that will be required to bring these undiscovered resources into production. EIA also assumes that given high enough prices, additional pipeline capacity could be added at a latter date. This study does not consider either of these factors.

• Pipeline is not constructed under the assumptions in the AEO2002 reference case

Given these assumptions, the AEO2002 did not project that an Alaska natural gas pipeline would be constructed in its reference case, since projected prices do not exceed the required trigger price of $3.50 during the forecast period.

Modeling the Effects of S. 1766, Title 7, “Alaska Natural Gas Pipeline Act of 2002”

The Alaska Natural Gas Pipeline Act is designed to expedite the creation of a transportation system to deliver Alaska natural gas to the lower 48 states. The Act does this by calling for expedited approval and environmental review, as well as the appointment of a Federal coordinator to “coordinate the expeditious discharge of all activities by Federal agencies with respect to an Alaska natural gas transportation project.” In addition, the act authorizes the Secretary of Energy to guarantee up to 80 percent of the principal of any loan made to finance the construction of the pipeline. The size of the loan guaranty is capped at $10 billion dollars, and the Act gives the Secretary the right to determine the loan requirements and issue any other regulations required to carry out the loan guaranty.

The provisions of the Alaska Natural Gas Pipeline Act of 2002 are reflected in EIA’s methodology in three major ways:

• Increased Executive Branch oversight (Section 705) and expedited environmental and legal reviews (Sections 706 and 707) are assumed to reduce the planning time in EIA’s methodology from 3 years to one year.
• The loan guarantee provisions for a qualifying project by the Department of Energy (Section 707) are assumed to reduce the cost of financing the pipeline, by allowing a pipeline builder who meets the Secretary’s requirements to borrow money at a lower cost. The estimated effect is to reduce the required pipeline tariff, and therefore the trigger price, by $0.10.
• Finally, this study assumes that given the loan guaranty and increased Federal oversight, the additional $0.35 added to the trigger price to account for uncertainties is not required.

Combined with the reduction in costs, the trigger price with the proposed Act is assumed to be $3.05, compared to $3.50 without the proposed Act.

The net effect is to project the construction of the pipeline with less delay and at a lower price than it would be constructed in the absence of S. 1766. The assumptions about construction costs, the required time for actual construction, and the underlying Alaskan natural gas resources are unchanged.

Figure Data

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Results and Sensitivity Analysis

Without the provisions of the proposed pipeline Act, the AEO2002 Reference Case does not project the construction of an Alaska natural gas pipeline before 2020, the end of its forecast period. However, using the same assumptions used in the AEO2002 Reference Case, and the including the assumptions of a loan guaranty and expedited review provided by the proposed “Alaska Natural Gas Pipeline Act of 2002,” this study projects that an Alaska natural gas pipeline would be implemented. Construction of the Alaska natural gas pipeline is projected to begin in 2016, and the first year of deliveries to the lower 48 is projected in 2020. Production in Alaska rises by 800 billion cubic feet (Figure 7.) In the first year that the pipeline is open, 730 billion cubic feet of natural gas is transported to the lower 48, with the rest of the additional production being used as pipeline fuel. The lower 48 wellhead price is projected to be lower than it would be without the pipeline (Figure 8.) Prices in 2020 are $3.20 in the case with the Pipeline Act, compared to $3.26 per thousand cubic feet in the AEO2002 reference case.

To show the potential effects of the Pipeline Act with higher projected natural gas prices, an alternate scenario was generated using the Low Oil and Gas Technology Case from the AEO2002. In this Case, the rate of technological advance in the oil and gas supply sector is projected to be lower than it has been historically, making it more difficult to add natural gas reserves and leading to higher natural gas prices.¹⁰

In the Low Oil and Gas Technology Case, lower 48 wellhead prices reach $4.06 per thousand cubic feet in 2020, compared to $3.26 in the AEO2002 Reference Case. Even though the price by the end of the forecast period in the Low Oil and Gas Technology Case is well above the trigger price, the price is not sustained at a high enough level for long enough for the pipeline to be completed by 2020 under the AEO2002 assumptions, which include no guaranties or expedited Government review. However, construction on the pipeline in this case is projected to begin in 2018.

With the Pipeline Act, the Alaska natural gas pipeline is economically feasible earlier. Construction on the Alaska natural gas pipeline in the Low Oil and Gas Technology Case is projected to begin in 2010. The pipeline is expected to begin transport in 2014, and reach full capacity of 4 billion cubic feet per day, or 1.5 trillion cubic feet per year, by 2015. The volume carried by the pipeline represents about 5 percent of the total natural gas consumed in 2015. By 2020, the total projected volume of natural gas consumed in the Low Oil and Gas Technology Case with the Pipeline Act is 31.8 trillion cubic feet, compared to 31.1 without the Pipeline Act. Forty-three percent of the pipeline’s volume serves to meet new demand brought on by lower prices, while the rest offsets other sources of supply from imports and lower 48 production.

Figure Data

Opening the pipeline earlier leads to lower natural gas prices. In 2020, lower 48 natural gas wellhead prices in the Low Oil and Gas Technology Case with the Pipeline Act are $3.74 per thousand cubic feet, about 8 percent lower than they are projected to be without the Pipeline Act (Table 4.) Lower wellhead prices result in lower prices to consumers (Figure 9.) The residential price of natural gas in 2020 is $8.07 per thousand cubic feet in the Low Oil and Gas technology case without the Pipeline Act, and is $7.72 with the Pipeline Act. Other prices are similarly lower.

Alaska Natural Gas Pipeline Uncertainties

The Alaska natural gas pipeline is a major project. There are several uncertainties in the estimate of its impact on U.S. markets, including:

• The availability of stranded gas to feed the pipeline. While the Alaska natural gas pipeline is one mechanism to bring stranded Alaskan gas to the Lower 48 States, there are other technologies that could allow these resources to be developed profitably. Alternate technologies include liquefied natural gas (LNG) and gas-to-liquids (GTL), both of which have been discussed as possible ways to market Alaskan natural gas. If either of these technologies or other alternatives can provide a higher rate of return for the owners of Alaskan gas reserves, a pipeline may be not be the most economic alternative, though it would support demand in the Lower 48 States.
• The decision-making process behind building a pipeline. The EIA methodology makes very simple assumptions to determine if investors will decide to build the pipeline. In reality, this decision is very complicated, and is based on future expectations, Government support for the project, and the profitability of other competing investment opportunities. In the absence of explicit governmental support for the project, the sustained lower 48 price required to trigger the project could be higher than the required price estimated in this study. Therefore, given the perception of higher risk, a sustained price of $3.50 may not be enough to trigger the pipeline, and the actual required trigger price could be as high as $4 or higher. In addition, there are environmental and Native rights issues that are raised by the construction of the pipeline, which could serve to slow or even halt the proposed pipeline unless these issues are resolved.
• The capital cost of the pipeline. At the time EIA developed its cost assumptions, many of the available cost estimates were either outdated or preliminary. The cost estimates from the joint BP-Phillips-ExxonMobil study have not been made available to the public as of this writing. In addition, the cost of the pipeline is sensitive to the route chosen. Finally, the cost assumptions used in this analysis are based on the best estimates of current costs, but do not reflect possible technological development which could lower these costs in the future. Therefore, there is considerable uncertainty in the assumptions used for the capital cost of the proposed Alaska natural gas project. Changes to the capital cost assumption could also change the timing of pipeline construction.
• For example, if the cost of the Alaska to Alberta pipeline were 20 percent higher than assumed in this analysis, or $12 billion, the trigger price would be $0.30 higher than it was projected in this study. At this higher projected pipeline cost, the new trigger price for the pipeline with the loan guaranty would be $3.35, assuming that the other assumptions remained unchanged. Since the projected lower 48 wellhead price never exceeds this new trigger price in the AEO2002 reference case, the pipeline would not be constructed by 2020. In the Low Oil and Gas Technology Case including the loan guaranty, initial deliveries with the new higher trigger price would be expected to start 3 years later than deliveries are projected to start based on the $10 billion pipeline cost estimate.
• The effects of the loan guaranty on investor’s perceptions of risk. The proposed Act gives the Secretary of Energy broad latitude in determining the requirements and the size of the loan guaranty. The specific policies adopted by the Secretary will influence the investor’s perceptions of risk. In this analysis, the loan guaranty is assumed to allow investors to begin the project as soon as Lower l8 natural gas prices indicate that a pipeline is feasible. However, even with the proposed loan guaranties and Federal oversight, investors may still feel that the project is risky enough that they will not commit to build the pipeline until the lower 48 wellhead price is well above the expected minimum level for profitability. Therefore, once all of the provisions of the proposed Pipeline Act are determined and implemented, the Act could have less of an impact on the prices required to trigger an Alaska natural gas pipeline than this study assumes.

Table 4

Notes and Sources