3. Oil and Gas Supply Provisions

Numerous provisions have appeared in the energy bills that would affect oil and gas supply. The specific issues analyzed by EIA are:

• Incentives to Sell Alternative Vehicle Transportation Fuels;
• Credits for Nonconventional Fuels Production;
• Opening the Coastal Plain area of the Arctic National Wildlife Refuge to Crude Oil Production; and
• Impact of Provisions to Provide Incentive for the Construction of an Alaska Natural Gas Pipeline to the Lower-48 States.

A. Alternative Motor Vehicle Fuels Credit

1. Credit for Retail Sale of Alternative Fuels as Motor Vehicle Fuel (Senate 2004)

Under Section 2004 of the Senate bill (there is no comparable provision in the House bill), a retail sales credit is proposed for alternative fuels used in motor vehicles, including compressed natural gas, liquefied natural gas, liquefied petroleum gas, hydrogen, and any liquid that consists of at least 85 percent methanol or ethanol by volume. The sales credit is specified in nominal cents per gallon of gasoline equivalent. The credit is 30 cents per gallon from September 2002 through the end of 2003, 40 cents in 2004, and 50 cents in 2005 and 2006.³³

Impact of Alternative Motor Vehicle Fuels Credit

The discussion of the impact of the alternative motor vehicle fuels credit is based on the Reference Case assumptions in AEO2002.³⁴ NEMS only represents prices for three types of alternative fuels: compressed natural gas (CNG), liquefied petroleum gas (LPG), and a fuel mixture of 85 percent ethanol and 15 percent gasoline (E85). Currently there are no liquefied natural gas or hydrogen vehicles on the market and future sales are estimated using a simplified methodology. In order to analyze the impact of the bill, the end-use prices for CNG, LPG, and E85 were reduced by the sales credit values specified in the bill for the given years (after appropriate unit conversions were performed). The analysis was based on the Reference Case used for the CAFE standards analysis.³⁵ The resulting average national alternative fuel prices for the Reference and the Credit Case for the years 2003 through 2006 are shown in Table 7.

Currently the total amount of fuel consumed on a Btu basis by the alternative fuel vehicles identified in the bill represents less than 0.3 percent of the total fuel consumed in the transportation sector. The proposed credit would raise this share by an additional 0.07 percentage points in 2006, the year with the largest credit. As a result, the impact on all primary energy indicators is negligible. However, in 2006, consumption of each fuel under the Credit Case is expected to be higher than in the Reference Case by 7, 59, and 28 percent for CNG, LPG, and E85, respectively. The more limited response to the large CNG price reduction is attributable to the longer lead times required to produce natural gas-capable vehicles and develop the necessary infrastructure. Consumption of the petroleum-based products increases more rapidly because of the lower incremental vehicle costs. The impact of the sales credit rapidly diminishes, especially for the petroleum products, once the credit is removed.

B. Nonconventional Fuels

1. Tax Credits for Nonconventional Fuels Production (House 43005, Senate 2310)

Under present law, a credit of $6.28 per barrel (or Btu equivalent) is provided for fuels produced from nonconventional sources: oil from shale or tar sands; gas from geopressured brine, Devonian shale, coal seams, tight formations, or biomass; and liquid, gaseous, or solid fuels produced from coal (including lignite). For facilities producing gas from biomass or synthetic fuel from coal, the credit is available for production through 2007 from facilities placed in service before July 1, 1998. For other sources, credit was available for production through 2002 for facilities placed in service from 1980 to 1992. Section 43005 of the House bill and Section 2310 of the Senate bill extend and expand the tax credit for producing fuel from certain nonconventional sources.

Section 43005 of the House bill allows a credit of $3 (indexed for inflation) per barrel (or Btu equivalent) for production from all nonconventional sources except landfills for the first four years of production prior to 2010 for new wells placed in service through 2006. Production from existing wells (drilled 1980-1992) is eligible for the credit for production in 2003-2006. For landfills regulated by the Environmental Protection Agency (EPA) the credit is $2. Landfill gas facilities placed in service after June 30, 1998, and before January 1, 2007, are eligible for five years of credit. The credit in this provision is limited to an average daily production of 200,000 cubic feet of gas (or oil equivalent) per project.

Section 2310 of the Senate bill allows a credit of $3 (unindexed for inflation) per barrel (or Btu equivalent) for three years of production from nonconventional fuel sources for new wells placed in service after the date of the enactment of this subsection and before January 1, 2005. Qualifying fuels are oil from shale or tar sands and gas from geopressured brine, Devonian shale, coal seams, or a tight formation. The bill also permits a similar $3 per barrel credit for the production of “viscous oil,” the production of “coalmine methane gas” at active (or soon to be active) coal mines, and the production of liquid, gaseous, or solid fuels from agricultural and animal wastes. These credits also extend for three years of production commencing when facilities are placed in service.

Impact of Extending Nonconventional Fuels Credits

The following analysis of the provisions of the House and Senate bills concerning nonconventional fuel credits was completed in August 2002 using the Reference Case from the AEO2002.³⁶ After that Reference Case was finalized in October 2001, natural gas wellhead prices moved substantially higher then expected. If this trend continues, the effect of the proposed bills might be less than projected in this analysis because the size of the credit is reduced if the sale price exceeds $4.04 per mcf in 2002 dollars. The credit is reduced by the ratio of the sale price minus $4.04 to $1.03. If the price were $5, for example, the tax credit would be reduced by 93 percent ((5.00-4.04)/1.03). Prices above $4.04 were not projected for the periods of the proposed tax credit in AEO2002, and the allowable credit was, accordingly, not reduced in this analysis. Should the current price levels continue, some reduction in the credit would occur.

For this analysis, the major assumptions relate to the resource base that would be eligible for the credit. For undeveloped natural gas resources in coal seams, Devonian shales, and tight formations it was assumed that 60 tcf, 55 tcf, and 228 tcf, respectively, would be eligible for the credit.

For the House bill, EIA analyzed the impact of allowing a credit of 50 cents per mcf ($3 per barrel Btu equivalent) for the first four years of gas production prior to 2010 for production from Devonian shales, coal seams, and tight formations for new wells placed in service through 2006. The primary impacts are a slight increase in the production of gas from nonconventional sources and a slight decrease in production from conventional sources and net imports of natural gas relative to the Reference Case (Table 8). Cumulative production from nonconventional gas sources is projected to be 2.9 percent (1.4 tcf) higher then the Reference Case for the period 2003 to 2010 and 0.5 percent (0.4 tcf) higher from 2011 to 2020 than that production in the Reference Case without the credit. Cumulative net natural gas imports are projected to be 1.5 percent lower (0.6 tcf) from 2003 to 2010 and 1 percent (0.5 tcf) lower from 2011 to 2020 than projected in the Reference Case. Because consumption levels are the same in the tax credit case as in the Reference Case, total natural gas supply does not change from the Reference Case. Thus, the incremental production from nonconventional sources in the tax credit case displaces imported supplies and, to some extent, production from conventional sources.

The House version of the bill is also projected to have a small impact on the natural gas wellhead price. From 2003 to 2010 the projected wellhead price averages 2.8 percent (7 cents per mcf) lower than in the Reference Case. However, the price is projected to be very slightly higher, 1.2 percent (4 cents per mcf) on average, in the last ten years of the forecast, as the effect of the tax incentive wanes.

For the Senate bill, EIA analyzed the impact of a credit of 50 cents (unindexed for inflation) per mcf for the first 3 years of gas production from Devonian shales, coal seams, and tight formations for new wells placed in service through 2004. The effects are projected to be very slight. Cumulative production from nonconventional sources is projected to be 1 percent (0.5 tcf) higher from 2003 to 2010 than projected production in a Reference Case without the credit (Table 9). From 2011 to 2020 nonconventional gas production in the two cases is projected to be virtually the same. The effect on net natural gas imports is also expected to be very slight, as cumulative imports are projected to be 0.7 percent (0.2 tcf) lower from 2003 to 2010 and 0.6 percent (0.3 tcf) lower from 2011 to 2020 than projected in the Reference Case.

The effect of the Section 2310 of the Senate bill on the price of natural gas is projected to be minimal. The projected natural gas wellhead price averages 1.1 percent lower than in the Reference Case from 2003 to 2010 and is virtually the same thereafter.

C. Drilling in the Arctic National Wildlife Refuge

1. Opening the Coastal Plain Area of the Arctic National Wildlife Refuge to Crude Oil Production (House 30401 – 30412)

Sections 30401-30412 of the House Energy Bill, “Arctic Coastal Plain Domestic Energy Security Act of 2003,” call for establishing a competitive oil and gas leasing program in the coastal plain of the Arctic National Wildlife Refuge (ANWR), resulting in an “environmentally sound” program for the exploration, development, and production of oil and gas resources in this area.

The Federal Government now prohibits oil and natural gas development in ANWR, which is located on the northern coast of Alaska, due east of both Prudhoe Bay, the largest oil field ever discovered in the United States, and the National Petroleum Reserve-Alaska (NPRA). Surveys conducted by the U.S. Geological Survey (USGS) suggest that between 5.7 and 16.0 billion barrels of technically-recoverable oil are in the coastal plain area of ANWR (also referred to as the 1002 Area), with a mean estimate of 10.4 billion barrels, divided into many fields. (Technically-recoverable resources are resources that can be recovered with today’s technology.) This estimate includes oil resources in Native lands and State waters out to a 3-mile boundary within the coastal plain area. The mean estimated size of oil resources on Federal lands alone is 7.7 billion barrels. In comparison, the estimated volume of technically-recoverable undiscovered oil in the rest of the United States is 136 billion barrels. Ultimate recovery at the Prudhoe Bay field, including production to date, is estimated to be 13.0 billion barrels.

ANWR was created by the Alaska National Interest Lands Conservation Act (ANILCA) in 1980. Section 1002 of ANILCA deferred a decision on the management of oil and gas exploration and development of 1.5 million acres of potentially productive lands in the coastal plain of ANWR. The “Arctic Coastal Plain Domestic Energy Security Act of 2003” proposes to open this coastal plain area to exploration and production. The coastal plain area represents about 8 percent of the total area of ANWR. The USGS estimates that 74 percent of the oil resources in ANWR’s coastal plain area are on Federal lands, with the remaining 26 percent on State and Native lands. To date, there has been no assessment of the oil and natural gas resources in the portion of ANWR outside of the coastal plain area. However, it is unlikely that the non-coastal plain area of ANWR has the same levels of resources that are estimated to be in the coastal plain area, due to differences in geology.

At the present time, there has been no exploration and development activity in the coastal plain region. An earlier EIA report, Potential Oil Production from the Coastal Plain of the Arctic National Wildlife Refuge: Updated Assessment, ³⁷suggested that between seven and twelve years were required from an approval to explore and develop to first production from the coastal region of ANWR. The study further noted that the time to first production could vary significantly based on time required for leasing after approval to develop is awarded and that environmental considerations and the possibility of drilling restrictions also could significantly affect projected schedules. This earlier analysis assumed that the earliest date that production from ANWR could occur was 2011. Since the bill was not passed in 2002, the earliest production date is now 2012 and the 2020 impact discussed below would occur in 2021 or later.

The current analysis uses the USGS assessment of potential field sizes in the coastal plain area, based on its assessment of the underlying geology. For the purposes of evaluating the impact of opening ANWR on U.S. markets, EIA assumed that State and Native lands within the coastal plain of ANWR would be opened for development.

In the mean resource expectation case, the total volume of technically recoverable crude oil projected to be found within the coastal plain area is 10.4 billion barrels. The largest projected field in ANWR is nearly 1.4 billion barrels. While considerably smaller than the 13-billion-barrel Prudhoe Bay field, this would be larger than any new field brought into production in decades. Subsequent fields are expected to be considerably smaller, with two additional fields with 700 million barrels of oil, five additional fields each with 340 million barrels of oil, and a large number of smaller fields. To put this in context with recent domestic oil discoveries, the Alpine Oil field in Alaska, the largest field to start producing in recent years, is estimated to have 413 million barrels of ultimate recovery.

Potential production from ANWR fields is based on the size of the field discovered and the production profiles of other fields of the same size in Alaska with similar geological characteristics. In general, fields are assumed to take three to four years to reach peak production, maintain peak production for three to four years, and then decline until they are no longer profitable and are closed.

The USGS estimates the total volume of non-associated, technically-recoverable natural gas resources available in ANWR to be between 0 and 10 tcf, with a mean estimated value of 3.5 tcf. An additional 2.0 to 5.5 tcf of technically-recoverable natural gas is estimated to exist in ANWR as associated gas, with a mean estimate of 3.6 tcf. The 35 tcf of stranded natural gas assets estimated to have been found already in Prudhoe Bay and other areas of the North Slope is not currently being commercially developed. These reserves would most likely be developed first if the infrastructure is developed to market North Slope natural gas.

Impact of ANWR Provisions

The basis of the discussion of the ANWR provisions is a study completed by EIA, The Effects of the Alaska Oil and Natural Gas Provisions of H.R.4 and S.1766 on U.S. Energy Markets³⁸completed in 2002 using AEO2002 as a Reference Case.³⁹ After opening ANWR, t otal Alaskan oil production in the mean resource expectation case is estimated to reach 1.9 million barrels per day in 2020 in this analysis, 800,000 barrels per day higher than it is in the Reference Case, which does not include opening ANWR. The projected volume of production from ANWR represents roughly 0.7 percent of projected world oil production in 2020. Total U.S. crude oil production is projected to reach 6.4 million barrels per day, compared to 5.6 million barrels per day in 2020 in the Reference Case.

The increase in ANWR production would lead to a decline in the U.S. dependence on foreign oil. In the Reference Case, net imports are projected to supply 62 percent of all oil used in the United States by 2020. Opening ANWR is estimated to reduce the percentage share of net imports to 60 percent. Nearly 89 percent of the offset imports comes from reducing crude oil imports, with the rest of the offset coming from reducing product imports. Opening ANWR is also projected to increase U.S. employment in the oil and gas sector, but estimating the size of the employment effects is beyond the scope of this analysis.

There are several areas of uncertainty when considering the impact of ANWR production on U.S. energy markets:

• The size of the underlying resource base . There has not been an extensive geological study of the ANWR area. Determining the precise size of oil resources within ANWR will take further study and exploration. The size of the resources will determine the potential ultimate recovery in the region as well as the potential yearly production.

• The underlying field structure . The size of reservoirs that are found in ANWR will determine the rate at which ANWR oil and gas resources are developed. If the reservoirs are larger than expected, production will be larger in earlier years.

• The costs of developing oil resources in ANWR . This analysis assumes that the costs of developing ANWR are not significantly different than the costs of developing oil resources in other parts of northern Alaska. If these costs are higher, ANWR production may be delayed.

• Timing of ANWR production . This analysis assumes that production in ANWR will begin in 2011. It also assumes that production in each new field could not open until two years after production begins in the last field to be previously opened. The actual timing of ANWR production could vary from that assumed in this study.

• Environmental considerations. Environmental restrictions could affect access for exploration and development.

D. Alaska Natural Gas Pipeline

Alaska’s North Slope has extensive natural gas resources, 35 tcf of which have been discovered to date, with initial estimates of 16 tcf yet-to-be discovered resources.⁴⁰ While this gas could be produced at relatively low cost, a particularly large and long pipeline would need to be constructed to bring it to market in the lower-48 States. A pipeline for Alaska natural gas has been discussed since the 1970s. 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 (bcf) per day from the Alaska North Slope, along the Alaska-Canadian highway to near Calgary, Alberta, and down to the lower-48 States.

With deregulation of U.S. natural gas supply and 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 reevaluation of the feasibility of developing “stranded” Alaska gas reserves. Conoco Phillips, BP, and ExxonMobil formed a partnership to investigate the potential of developing a gas pipeline, following roughly the route proposed by ANGTS (the “Southern” route) or an alternate route across the Beaufort Sea to the MacKenzie Delta in Canada and then down to Alberta (the Northern Route”). The results of their analysis, released in May 2002, indicated that the project was not commercially viable at that time and that the Governments will need to play a role in reducing project costs and scheduling risks.

Using cost estimates from the Conoco Phillips, BP, and ExxonMobil analysis and an assortment of other assumptions, EIA has estimated in its Annual Energy Outlook 2003 (AEO2003) that it would require an average lower-48 wellhead gas price of $3.48 per mcf (in 2001 dollars) for the pipeline project to be viable and that it would be built by around 2020 without added incentives. With total project cost estimates of $19.4 billion (in 2001 dollars), lead times of between 7 and 10 years, and the volatile nature of natural gas prices, the risks associated with such an undertaking are significant.

1. Alaska Pipeline Bill Provisions in the House and the Senate Bills

Both of the separately-passed Senate and House energy bills prohibit northern routes for an Alaska natural gas pipeline and promote its expedited approval. However, only the Senate bill provides for a pipeline loan guarantee (Sec. 710) and a northern Alaska natural gas production tax credit (Sec. 2503). The pipeline loan guarantee is intended to cover “not more than 80 percent of the principal of any loan” issued “for the purpose of constructing an Alaska natural gas transportation project” and is limited to $10 billion dollars. The loan guarantee is only available if an application for a certificate of public convenience and necessity for the pipeline has been filed within 18 months after the bill’s enactment. The production tax credit applies to the production of marketed Alaska natural gas entering the pipeline from an area lying north of 64 degrees North Latitude. The amount of the credit is calculated as the difference between $3.25 per million Btu (in nominal dollars in the first year of operation, adjusted for inflation thereafter) and the average monthly price at the AECO-C Hub in Alberta, Canada, effectively guaranteeing producers a floor price of $3.25 per million Btu in Alberta, including the tax credit. This credit is to start no earlier than January 1, 2010, and to extend for 15 years after the initial flow of gas. Three years after the flow of gas commences, the credited amount is to be repaid to the Government on a monthly basis in increments equal to the AECO-C Hub price minus $4.87 per million Btu (in nominal dollars in the first year of operation, adjusted for inflation thereafter), should this difference be positive, times the monthly flow of marketed natural gas.

Alaska natural gas pipeline provisions were also included in S.14 and S.1149, which were debated in the Senate this year but were set aside prior to the August recess when the Senate passed comprehensive energy legislation with the same provisions as the Senate-passed bill from the prior Congress. The tax credit provisions in S.1149 are set relative to a price in Alaska rather than Alberta. The loan guarantee in S.14 differs from those in the Senate-passed bill in that it includes qualifying facilities in Canada and has a higher cap of $18 billion dollars.

The discussion of the Alaska natural gas pipeline incentives below is organized into three distinct parts.

• The first part outlines the key factors affecting the entry-into-service (EIS) of the pipeline, both with and without the incentives. A wide range of EIS dates, both with and without incentives, appears to be possible.
• The second part examines gas market implications of the incentives in the Senate-passed version of H.R. 6, comparing a Reference Case in which the pipeline does not enter service until 2020 with an alternative case in which the pipeline enters service in 2013. These cases reflect the same set of assumptions regarding baseline natural gas prices and the time required to complete the pipeline. While results could differ substantially under other assumptions, these cases provide insight into the implications of earlier EIS dates for the pipeline on natural gas markets.
• The third part discusses the differences between the tax credit provisions in the Senate-passed bill and those in S. 14 and S.1149, including implications for the construction of the pipeline and projected effects on tax revenue.

2. Key Factors Affecting EIS of an Alaska Natural Gas Pipeline

a. Natural Gas Prices

As noted above, projected natural gas prices in the period following EIS are a key factor affecting the economic viability of a pipeline to bring natural gas from Alaska’s North Slope to markets in the lower-48 States. Traditionally, natural gas producers have used current prices as a guide for investment decisions. However, most investments, such as the decision to drill a well, have relatively short gestation periods and relatively rapid payouts. For example, a typical gas well can be connected to the system within a year of project initiation and produces more than 75 percent of its total output within 2 years of being connected. Because a pipeline to transport natural gas from Alaska’s North Slope to the lower-48 markets will have a long gestation period and operate for many years, investment in such a project will tend to be less influenced by short-term natural gas price movements. As a proxy for the sustained higher prices required to motivate investment in a pipeline, the assumption used in EIA’s AEO2003 is that the pipeline project would begin construction once the average price of natural gas at the wellhead exceeds $3.48 per mcf (in 2001 dollars) for 3 consecutive years, during which time permits would be obtained. Under this Reference Case, the pipeline does not enter service until 2021. The reference case from a more recent study, with the same assumptions for the pipeline and slightly higher prices, had an in-service date of 2020.

Since publication of the AEO2003, there have been increasing questions regarding the adequacy of natural gas supplies for the lower-48 market. The amount of working gas in storage reached record lows at the end of the 2002 to 2003 winter season. Prices throughout 2003 have averaged well above $3.48 per mcf, and EIA’s Short-Term Energy Outlook (STEO) projects that average prices at the wellhead will remain above that level through 2004, the end of the STEO projection horizon. New supply options, consisting of liquefied natural gas imports, imports from the MacKenzie Delta, unconventional gas, and gas from Alaska, have been identified. Because of the high capital costs and long construction lead time involved, bringing gas from Alaska by a pipeline through Canada is among the most risky options. This high level of risk has prompted developers to wait. However, were average wellhead natural gas prices in 2004 and 2005 to remain clearly above the $3.48 level and if planning were to commence in 2006, an Alaska pipeline could be expected to be completed between 2013 and 2016. The longer the natural gas price remains at high levels, the greater the incentive for completion.

b. Pipeline Project Gestation Period

The AEO2003 assumes that an Alaska natural gas pipeline can enter into service within 7 years of project initiation, including planning and approvals. Other information, including an estimate by the three major North Slope producers, suggests a longer period, perhaps 9 or 10 years, from initiation of the project to its completion. With this in mind EIA has now set the earliest likely start year at 2013.

A 7-to-10 year period probably represents a reasonable range of estimates for the amount of time to complete the pipeline project once the planning phase is launched. It is not clear where the actual time-to-build might fall within this range or whether the time-to-build would itself be significantly affected by the availability of incentives or the other provisions regarding the pipeline project that are also included in proposed legislation. The actual amount of time required to build the project will clearly affect the timing of EIS, with or without incentives.

3. Market Impacts of Alternative Alaska Pipeline Entry into Service Dates

To estimate the impacts on natural gas markets of alternative pipeline EIS dates, two cases were compared: one where EIS occurs in 2020 (the 2020 Start Case), the other where EIS occurs in 2013 (the 2013 Start Case).

Impact of an Earlier Alaska Pipeline Start Date

The analysis of the market impacts of an earlier pipeline start date in response to the proposed production tax credit provisions was based on the Reference Case⁴¹ developed as part of a mid-year revision to AEO2003 completed for the study, Analysis of S.139, the Climate Stewardship Act of 2003.⁴² The natural gas price, consumption, and production impacts from this analysis reflect specific reference and policy cases based on AEO2003, originally released in November 2002, with some limited updating. Under this Reference Case the pipeline enters service in 2020, with a capacity expansion with added compression assumed to start in 2024. Significant changes in the EIA’s long-term outlook could occur when the AEO2004 is released this Fall. For this reason, it is recommended that users focus their review of these variables on the differences between the two EIS cases rather than the absolute results for either case.

Table 10 provides a summary of the results. Without the tax credit, an Alaska gas pipeline is projected to begin operation in 2020, with initial delivery at 3.9 bcf per day. In this case expansion was assumed not to occur before the end of the forecast horizon in 2025. However, a tax credit is expected to provide sufficient incentive for project planning, followed by construction, to commence upon legislative enactment. Under such a scenario, the pipeline is expected to begin operation in 2013, with no significant opposition or construction delays, at a dry gas delivery rate of 3.9 Bcf per day throughout the forecast period. While it is possible that a capacity expansion will occur, EIA assumed no expansion for the purposes of this analysis. Expansion is likely to occur if market conditions in the lower 48 States warrant it and supplies in Alaska are deemed adequate upon further exploration for natural gas on the North Slope.

Under both cases Alaska production continues to provide for consumption in the State itself and for liquefied natural gas (LNG) exports to Japan. Total Alaska production is projected to increase from 0.4 trillion cubic feet (tcf) in 2002 to 2.2 tcf by 2025. Of the 11.6-tcf increase in supply needed by the United States in 2025 compared with 2002, 15 percent is expected from Alaska in both cases. On a cumulative basis from 2002 through 2025 Alaska production represents 3.9 and 6.6 percent of U.S. supply in the 2020 Start Case and the 2013 Start Case, respectively. However, Alaska is expected to represent an even greater share of the cumulative growth in U.S. supply during the forecast over 2002 levels – 8.3 percent in the 2020 Start Case and 16.0 percent in the 2013 Start Case.

The introduction of Alaska natural gas to the lower-48 States results in reduced domestic production in the lower-48 States, reduced imports, and increased consumption. Of the additional 11.2 tcf of cumulative production in Alaska from 2013 to 2025 that results from the earlier introduction of the pipeline in 2013, 16 percent represents increased consumption, 54 percent displaces lower-48 production, 30 percent displaces imports. Cumulative natural gas production from unconventional sources⁴⁴ absorbs about 60 percent of the lower 48 reduction, although it represents only about 40 percent of the cumulative lower-48 production over the period. This can be attributed to the typically higher costs associated with unconventional natural gas production (most of which is located in the Rocky Mountain region), identifying it as a marginal supply source. LNG imports into the United States, and into Mexico that are targeted for the United States, represent 86 percent of the net import reduction, with the remainder attributable to Canada. The differences between the two cases are greatest between 2014 and 2017.

Large-volume supply projects, such as an Alaska natural gas pipeline, are expected to place downward pressure on prices, particularly when initially brought online. Under the 2020 Start Case, an Alaska pipeline results in an annual price reduction in the overall lower-48 wellhead price in 2020 of 4 cents (in 2001 dollars) compared to the price in the previous year. The 2013 introduction of the pipeline reduces the average wellhead price by 9 cents in 2014 compared to 2012. When comparing the price differences between the two cases, the greatest difference occurs in 2015, when the wellhead price is 25 cents lower (in 2001 dollars) in the 2013 Start Case, relative to the $3.67-per-mcf price in the 2020 Start Case in 2015. Prices are generally higher throughout the forecast in the 2020 Start Case, relative to the earlier start case, except between 2020 and 2022 when the pipeline first comes on line.

From 2013 to 2025, U.S. natural gas consumers, while cumulatively consuming more natural gas, would be expected to save almost $20 billion (in 2001 dollars) on natural gas purchases, because of generally lower delivered prices in the 2013 Start Case. The impact in lost revenues to lower-48 producers would be even more dramatic at $48 billion (in 2001 dollars). Table 11 summarizes the cumulative impact of the earlier start of an Alaska gas pipeline as a result of the H.R.6.EAS tax credit proposal.

A net present value calculation can provide a slightly different perspective from using cumulative revenues to summarize the impact of an earlier start of an Alaska gas pipeline. In general, consumer savings and producer revenue losses are greater in the initial years after the pipeline begins to operate, in the latter part of 2013. A net present value calculation places greater weight on the changes that occur in the earlier years over those occurring later. Table 12 provides the revenue impact in net present value terms using an assumed 7-percent rate of return.

U.S. Treasury Implications as a Result of the Tax Credit

The more difficult assessment is the potential impact of a tax credit on the U.S. Treasury. Here, we consider the impact on the U.S. Treasury as a direct result of the tax credit as well as the impact of an earlier (2013) pipeline start on federal royalty receipts from natural gas production in the lower 48 States.

The Treasury impacts of the tax credit will depend on monthly natural gas prices at the AECO-C hub. EIA projects annual price trends for all U.S. lower-48 production at the wellhead, but these projections do not reflect short-term price volatility affecting particular months or particular trading hubs. Using EIA’s annual average lower-48 wellhead price projections and assuming a $0.60 per mcf (in 2001 dollars) differential⁴⁵ between the lower-48 price and the AECO-C Hub price, the AECO-C Hub price would not be expected to fall below the $3.25 per million btu in 2013 dollars (or $2.59 per mcf in 2001 dollars) floor on an annual basis for the tax credit to take effect. Under these assumptions the lower-48 wellhead price would have to be below $3.19 per mcf in 2001 dollars for the credit to be triggered.

Given the wide variability of natural gas prices, this result should not be construed as a definitive estimate of tax credit costs. Natural gas prices are expected to continually be volatile in the future, as they have in the past, and even more so with spot prices, such as at the AECO-C Hub. The AECO-C Hub price in particular has experienced relatively low periods in the past when the flow of gas from Canada into the United States was constrained by pipeline capacity. While the general belief is that prices over the next two decades will be higher than they have been in the past decade, average U.S. wellhead prices under $3.19 were the norm in the 1990s. On the other hand, realized prices could actually be higher than those projected by EIA, if historic trends in technological progress are not sustained into the future, resource estimates prove to be too optimistic, or the amount recoverable per well prove to be lower than estimated.

Federal royalty receipts from natural gas production in Federal onshore and offshore areas would be impacted by an earlier pipeline start that reduced either the volume or value of production. EIA does not project the share of total U.S. natural gas production subject to Federal royalties. However, information on the Minerals Management Service (MMS) website indicates that in 2000, production from Federal onshore and offshore resources accounted for 36 percent of total U.S. natural gas production (onshore at 11 percent and offshore at 25 percent). MMS reports that royalty rates in 2000 were 12.27 percent for onshore production and approximately 15.5 percent for offshore production – the standard rate for offshore royalties is 16.67 percent, but some production gets significant royalty relief. Assuming a constant 36 percent of production on federal lands, entry-into service of the Alaska pipeline would reduce Federal royalty receipts by $2.5 billion (cumulative undiscounted year 2001 dollars) over the first 15 years of operation.

Finally, it should be noted that additional indirect Federal budget impacts may also result from changes in the level of economic activity and tax revenue collections, which should be positively affected by the pipeline project itself and negatively affected by any displacement of gas development activities in the lower-48 States. Increased natural gas supply and lower prices projected as a result of the earlier availability of North Slope gas should also provide economic benefits to gas consumers that may be reflected in increased economic activity. Consideration of these impacts is beyond the scope of the present analysis.

4. Variations Under S.1149 and S.14

A variation of the tax credit and the loan guarantee were proposed in S.1149 and S.14, and a provision for accelerating the depreciation of Alaska pipeline assets for tax purposes was proposed in S.1149. These three provisions are:

1. A 15-year production tax credit for Alaska North Slope gas equal to $0.52 per million Btu (in 2002 dollars), that is reduced equally for every cent a to-be-determined monthly reference wellhead price for gas in Alaska exceeds $0.83 per million Btu [Sec. 511 of S.1149];
2. A pipeline loan guarantee on 80 percent of the capital costs, including interest during construction, not to exceed $18 billion dollars for a pipeline running from the North Slope of Alaska to the continental United States. [Sec. 144 of S.14];
3. A shortened accelerated cost recovery period for assets when calculating taxable income related to the Alaskan portion of the Alaska natural gas pipeline [Sec. 512 of S.1149].

These variations of the tax credit and loan guarantee should not appreciably change the start date of the pipeline compared to the similar provisions in the recently-passed Senate bill (Sec. 2503 and 710 of H.R.6.EAS). Including the Canadian portion of the pipeline within the loan guarantee could increase the interest of the Canadians in the project. However, the primary difference is expected to be the impact on the U.S. Treasury, as the tax credit under S.1149, unlike the one under H.R.6.EAS, is estimated to result in a direct impact on the U.S. Treasury, when based on an approximate calculation using annual average forecasted prices. A more rapid depreciation of pipeline assets for tax purposes is not expected to notably alter the tariff charges for the pipeline or affect the start date, but should allow the pipeline to more readily secure financing.

a. Rapid Depreciation of Pipeline Assets

S.1149 (Section 512) allows the portion of an Alaska natural gas pipeline that is within the State of Alaska to be depreciated on an accelerated basis over 7 years, rather than the current 15 years, for tax purposes. This provision holds for a pipeline that is placed in service after December 31, 2014.⁴⁶ In general, a company benefits by accelerating the depreciation of an asset when calculating taxable income by reducing tax payments in the early years of the project, when additional cash flow can be more important (e.g., in securing bonds), and deferring these taxes to later years. A shorter depreciation period allows the pipeline to more readily secure financing for a project and successfully begin operations.

When a pipeline sets rates for transportation services, taxes are calculated on a straight-line basis and, in a given year, are not equal to the actual taxes paid to the Federal Government. Therefore, a change in the depreciation period for tax purposes does not directly change the calculation of taxes used for ratemaking purposes. However, the rate base is adjusted by the accumulated level of the deferred taxes, which ultimately results in a potential change in the regulated rate charged by the pipeline company and an insignificant change in taxes owed. Overall, the impact on pipeline tariffs is expected to be negligible.

On a cumulative basis over the 15-year period after the pipeline goes into service, the taxes paid to the Federal Government on a nominal basis can be expected to be nearly equal under a 7-year accelerated depreciation schedule versus a 15-year schedule. The relative budgetary impacts are related to the impacts of inflation and the general time value of money. For the purposes of this analysis, EIA assumed that the portion of an Alaska natural gas pipeline in the State of Alaska would cost $4.6 billion (in 2001 dollars), or 40 percent of the $11.6 billion dollar estimate from the producer consortium for the pipeline taken further to Alberta. On a present value basis, assuming a discount rate of 7 percent, the Federal Government would expect to receive $260 million (in 2001 dollars) less in tax revenue as a direct result of moving from a 15-year to a 7-year depreciation schedule.

b. Tax Credit Provision

With the tax credit provision proposed under S.1149, suppliers of natural gas to the pipeline will receive $1.35 per million Btu in total from gas purchasers and from the tax credit, as long as the reference price in Alaska is between $0.83 and $1.35 per million Btu. When the reference price exceeds $1.35, no production tax credit is allowed, and the producer receives just the market price. When the reference price falls below $0.83, the production tax credit stays at $0.52, and the effective recovered price for the suppliers of gas to the pipeline is the reference price in Alaska plus $0.52 per million Btu ($0.53 per mcf in 2001 dollars). Since EIA assumes that producers of gas in Alaska will supply sufficient gas to fill the pipeline in the initial years of operation at $0.80 per mcf at the wellhead, a total return of $1.35 ($1.37 per mcf in 2001 dollars), as called for under the bill, should be more than sufficient for producers to be willing to supply the gas and provide the necessary incentive for the pipeline to be built as soon as possible.

The reference price in Alaska is to be established by a National regulatory body based on a monthly published market price for natural gas, presumably in the lower-48 States or Alberta, minus any transportation and processing costs (including gas treatment costs). An estimate of the cost of a production tax credit to the Federal Government depends on the projected natural gas prices for the selected market, as well as the toll for the transportation of the gas and the processing costs. Lower natural gas prices or higher transportation tolls than estimated could increase the amount of tax credits. Since EIA has the capability to project the average lower-48 wellhead price, that market was selected for this analysis. The historical differential between lower-48 and Alberta wellhead prices was used to represent Alberta-to-market transportation costs,⁴⁷ while a regulated based tariff calculation was used to estimate the pipeline tariff from Alaska to Alberta. Gas treatment costs were assumed at $0.41 per mcf in (2001 dollars).

The remainder of this section discusses issues related to the calculation of transportation costs and the selection of a published market price, all of which can affect the amount of available tax credits. The section concludes with estimates of available tax credits under several alternative assumptions.

The Published Market Price

The S.1149 tax credit is specified in relation to “the applicable reference price.” Although the language in the bill is not explicit, the implication is that this is a reference price on the North Slope. The bill indicates that this reference price will be established using “a published market price…(reduced by any gas transportation costs and gas processing costs as determined by the appropriate national regulatory body for natural gas transportation)….” One plausible, but not explicitly required, implementation of this methodology would use “transportation costs” that represent the regulated transportation rates associated with moving the gas along natural gas pipelines from the North Slope to a point associated with the “published market price.” EIA did not consider the potential of transportation costs which do not reflect the cost of moving gas from the North Slope to a geographical location associated with the selected “published market price.”

For points in North America beyond the Alberta hub with “published market prices,” there are multiple routes to move gas from the Alberta hub. In addition, regulated rates on pipelines can vary depending on the provided level of service – notably, service is typically provided with varying degrees of “firmness” and under different commitment periods. This suggests that the “national regulatory body” would presumably have a degree of latitude in setting the specific rates that would be applied, unless the language in the bill is made more specific. Based on an assumption that Alberta and U.S. gas compete at common U.S. market points based on transportation differentials, EIA’s analysis uses the difference between the lower-48 average wellhead price and the Alberta wellhead price as the Alberta-to-lower-48 component of the transportation differential to be subtracted from a lower-48 average wellhead “published price.”

Figure Data

In actuality, there are a couple of implications for selecting one published market price over another. Although the language is vague in the bill, EIA assumes that the intention is to select a price reported at a primary natural gas market hub (a spot price) that is associated with a particular geographical area. Spot prices are generally much more responsive to changes in market conditions (particularly on the high end) than what would be reflected in an average wellhead price and are typically higher on average.⁴⁸ Some market hub prices are more volatile than others because of their location on the pipeline network (Figure 1). When the pipelines servicing an area at the end of the network (e.g., in California or New York) reach maximum utilization levels, the rise in prices can be expected to exceed any rise experienced at other more central hubs (e.g., the Henry Hub). Conversely, prices at the AECO-C Hub and wellhead prices in Alberta have been depressed when pipeline constraints have restricted the flow of gas out of Canada. At such times the AECO-C Hub price can be expected to fall below the average wellhead in Alberta. In practice, using a spot price rather than an average wellhead price as a “published market price” will tend to result in instances of more wild swings in the resulting monthly reference price in Alaska when the U.S. gas market is stressed. Such short-term market responses are not captured in EIA’s annual forecast. Excluding the short-term fluctuations, the average lower-48 wellhead price generally tracks reasonably well with the Henry Hub price.

Transportation Costs

Estimates of available tax credits are also sensitive to uncertainty in the toll for transporting the gas. EIA employs a simple representation of the calculations used to establish regulated natural gas pipeline rates, based on assumptions provided by the Alaska producer group (e.g., a debt/equity ratio of 70/30) and others assumptions based on averages from financial reports by major U.S. pipeline companies. In the end, the actual tariff will depend on the rate case filed at the Federal Energy Regulatory Commission (FERC) and what FERC finally approves. It also will depend on the accuracy of the cost estimates -- the Alaska producer group has indicated an uncertainty range of plus or minus 20 percent on the capital costs. Higher transportation costs than those calculated by EIA, including estimates made by the producer group, would increase tax credits available under S.1149.

Under standard pipeline rate calculations, tariffs can be expected to decline in real terms, and potentially in nominal terms, over time as a pipeline is depreciated. As the pipeline ages, refurbishments and operation and maintenance expenses can be expected to increase and offset some of this decline. The tolls that were released by the Alaska producer group reflect their estimates of the actual tariff that will be charged the first year of operation. ConocoPhillips, one of the potential Alaska North Slope producers, indicated that they believe that the rate will remain constant in nominal terms over the life of the pipeline – levelized nominal rates. For the purpose of this analysis, EIA calculated the expected Alaska-to-Alberta tariff in nominal terms, which decline over time as the pipeline is depreciated. Then, a “levelized” nominal tariff was established as the average of this series over 15 years. This rate was assumed to be constant in nominal terms over the life of the project. The expected tax credit will be assessed for both levelized and nonlevelized rates.

It is EIA’s understanding that the potential pipeline owners can propose either levelized or non-levelized rates to their new customers and ultimately to FERC. The regulator usually agrees if the customers are agreeable. It is possible that the availability of tax credits may favor the use of non-levelized (in nominal terms) rates, which could increase the likelihood that tax credits could be collected in early years with higher transportation rates that would not have to be repaid when rates fall. The language in the bill does not preclude this possibility.

Estimated Applied Tax Credit

EIA estimates that the initial total transportation and fuel cost to move natural gas from Alaska to the lower-48 States starting in 2013 is $2.20 per mcf in 2001 dollars (assuming levelized transportation and processing rates in nominal terms thereafter). This includes: 1) $0.41 for gas treatment, 2) $1.19 for transportation from Alaska to Alberta, including pipeline fuel, and 3) $0.60 (in 2001 dollars) for transportation to the lower 48 wellhead equivalent. If the average U.S. wellhead price were used as the “published market price,” and the $2.20 per mcf average transportation rate were used to establish the “reference price” in Alaska, then EIA estimates that the tax credit would take effect in 2013 if the average monthly U.S. wellhead price falls below $3.57 per mcf in 2001 dollars. However, over the life of the pipeline, the transportation costs are assumed to fall in real terms, causing this $3.57 threshold to fall.

• Assuming the Alaska pipeline starts operations in 2013 with a delivery volume of 3.9 Bcfd, the average annual lower-48 wellhead price projection falls below the tax credit threshold in the first 3 years of the pipeline’s operation (by an annual average of 15 cents), when the additional supplies in the market cause downward pressure on the price. This amounts to a $396 million (2001 dollars) impact on the U.S. Treasury directly attributable to the tax credit under S.1149. This calculation does not take account of month-to-month fluctuations, which -- given the difference in the payment and repayment triggers -- are likely to increase costs to the Treasury, possibly by a substantial amount.

As noted in the earlier discussion of ratemaking, tariff calculations are affected by numerous factors and assumptions. The actual tariffs may differ significantly from any estimate and could substantially affect Treasury costs. Using an alternative rate structure in which nominal rates are not levelized, the cumulative undiscounted impact on the U.S. Treasury would be $1.71 billion 2001 dollars.⁴⁹ Using the toll in 2013 for the Alaska-to-Alberta pipeline estimated by the Alaska producers group at $1.47 per mcf (2001 dollars, but held constant in nominal terms thereafter) for transportation ($1.13 per mcf) and processing ($0.34 per mcf), the cumulative undiscounted impact on the U.S. Treasury as a direct result of the tax credit is estimated to be $17 million 2001 dollars.

Again, these calculations do not take account of month-to-month fluctuations, which given the difference in the payment and repayment triggers, are likely to increase costs to the Treasury, possibly by a substantial amount. An extreme upper bound on the budgetary impact of the tax credit can be calculated under the assumption that all North Slope gas receives the full credit in each month. Over a 15-year period, the maximum cumulative undiscounted impact on the Federal budget as a direct result of the tax credit would be $13 billion 2001 dollars, assuming no expansion on the Alaska pipeline. Actual costs are unlikely to approach this extreme upper bound. For illustrative purposes, Tables 13 and 14 display the production tax credit and the associated reductions in Federal tax receipts for ranges of lower-48 wellhead prices and transportation tolls.

As outlined in the earlier discussion of the tax credit provision in H.R.6.EAS, the total net impact on the U.S. Treasury (i.e., not just from the tax credit specifically) will also reflect impacts on federal royalty collections as well as any changes in the level of economic activity that affect revenues or outlays.

Oil and Gas Supply - Tables

Notes and Sources