Report#:DOE/EIA-0554(99)

Introduction

Macroeconomic Activity

International Energy

Household Expenditure

Residential Demand

Commercial Demand

Industrial Demand

Transportation Demand

Electricity Market

Oil and Gas Supply

Natural Gas Transmission & Distribution

Petroleum Market

Coal Market

Renewable Fuels

The NEMS Oil and Gas Supply Module (OGSM) constitutes a comprehensive framework with which to analyze oil and gas supply.  A detailed description of the OGSM is provided in the EIA publication, Model Documentation Report:  The Oil and Gas Supply Module (OGSM), DOE/EIA-M063(99), (Washington, DC, January 1999).  The OGSM provides crude oil and natural gas short-term supply parameters to both the Natural Gas Transmission and Distribution Module and the Petroleum Market Module.  The OGSM simulates the activity of numerous firms that produce oil and natural gas from domestic fields throughout the United States, acquire natural gas from foreign producers for resale in the United States, or sell U.S. gas to foreign consumers.

OGSM encompasses domestic crude oil and natural gas supply by both conventional and nonconventional recovery techniques.  Nonconventional recovery includes enhanced oil recovery and unconventional gas recovery from tight gas formations, gas shale, and coalbeds.  Foreign gas transactions may occur via either pipeline (Canada or Mexico) or transport ships as liquefied natural gas (LNG).

Primary inputs for the module are varied.  One set of key assumptions concerns estimates of domestic technically recoverable oil and gas resources  Other major factors affecting the projection include the start date and threshold price for the Alaskan Natural Gas Transportation System (ANGTS), projections for enhanced oil recovery production, supplemental gas supplies over time, and natural gas import and export capacities.

Key Assumptions

Domestic Oil and Gas Technically Recoverable Resources

Domestic oil and gas technically recoverable resources67 consist of proved reserves,68 inferred reserves,69 and undiscovered technically recoverable resources.70  OGSM resource assumptions are based on estimates of technically recoverable resources from the United States Geological Survey (USGS) and the Minerals Management Service (MMS) of the Department of the Interior, with supplemental adjustments to the USGS nonconventional resources by Advanced Resources International (ARI), an independent consulting firm.71 While undiscovered resources for Alaska are based on USGS estimates; estimates of recoverable resources are obtained on a field by field basis from a variety of sources including trade press. Published estimates in Tables 45 and 46 reflect the removal of intervening reserve additions between the dates of the USGS (1/1/94) and MMS (1/1/95) estimates and 1/1/97.

Table 45.   Crude Oil Technically Recoverable Resources (Billion Barrels)

Table 46.   Natural Gas Technically Recoverable Resources (Trillion Cubic Feet)

Alaskan Natural Gas

The outlook for natural gas production from the North Slope of Alaska is affected strongly by the unique circumstances regarding its transport to market.  Unlike virtually all other identified deposits of natural gas in the United States, North Slope gas lacks a means of economic transport to major commercial markets.  The lack of viable marketing potential at present has led to the use of Prudhoe Bay gas to maximize crude oil recovery in that field.  This use is expected to delay extraction of gas for market until the post-2005 period. The estimates for gas from the North Slope that will be transported to lower 48 States markets through ANGTS are dependent on the capacity of this system.  ANGTS is projected to flow gas to market in two phases, and it is assumed that production will be available to fully utilize the capacity in both phases, if constructed. Operational capacity for the first phase is 767 billion cubic feet per year delivered to the U.S./Canadian border. Annual capacity increases to 1,150 billion cubic feet upon the completion of the second phase.  Operation for each phase is assumed to begin at midyear; thus only half of the capacity is available for the first year of operation, with full capacity available in each year thereafter.  It is assumed that ANGTS will not begin operation until 2005 at the earliest, to support oil recovery in the Prudhoe Bay field.  Each phase of ANGTS is brought on line in OGSM when the appropriate border-crossing price is reached for gas delivered to the lower 48 States.  The price for phase one is $3.96 in 1997 dollars per thousand cubic feet.  When this price is reached, ANGTS is brought on line in the following year, with a total flow of 383 billion cubic feet, reaching the full capacity of 767 billion cubic feet in subsequent years.  If a higher threshold price of $5.31, in 1997 dollars per thousand cubic feet is reached, then phase two will begin the following year.  The flow will increase by 192 billion cubic feet, to 959 billion cubic feet, and in each subsequent year the flow will be 1,150 billion cubic feet.  This methodology is applied in all the cases.

The projection for supplemental gas supply is identified for three separate categories:  synthetic natural gas (SNG) from liquids, SNG from coal, and other supplemental supplies.

Projected SNG production from liquids is based on an econometrically derived equation, with the independent variable being the regional average market price for natural gas.  SNG from the currently operating Great Plains Coal Gasification Plant is assumed to continue through 2008, at 57.67 billion cubic feet per year.  In all cases, it is assumed that in midyear 2009 the Great Plains facility will stop producing natural gas when the current purchase contract expires and natural gas production is not economical.  At that time, the facility is assumed to be more profitable.  Other supplemental supplies are held at a constant level of 44.04 billion cubic feet per year throughout the forecast because this level is consistent with historical data and there is no reason to believe this will change significantly in the context of a reference case forecast.

Natural Gas Imports and Exports

U.S. natural gas trade with Mexico and natural gas exports from the United States to Canada are determined exogenously to NEMS.  U. S. exports of LNG are also exogenously determined. U.S. import flows from Canada are determined endogenously within the model but are constrained by assumed pipeline capacities. Exogenously specified projections of pipeline import and export values from Canada and Mexico are shown in Table 47.

Table 47. U. S. Natural Gas Imports and Exports (Billion Cubic Feet per Year)

Canadian production and exports to the United States are determined endogenously within the model.  Natural gas exports to Canada from the United States are assumed to be a constant 51 billion cubic feet in each projection year because this is the current level and there is no forecast for pipeline expansion for exports.  The Canadian economically recoverable resource base estimate used in the model for the beginning of year 1990 is 304 trillion cubic feet for gas, derived from figures published by the National Energy Board.  This quantity was assumed to increase at a rate of 2 percent each projection year to reflect improvements in and penetration of technology.

Annual U.S. exports of LNG were assumed to be a constant at 67.6 billion cubic feet in each projection year. LNG imports are determined endogenously within the model.  The outlook for LNG imports was based on a combination of influences, including available gasification capacity, announced plans by each company, tanker availability, expected utilization rates, projected gas prices and liquefaction capacity, and long-term contracts with a responsible purchaser.  LNG import capacity in 1996 is 0.3 trillion cubic feet.  The outlook for LNG imports also includes an implicit assumption that no major operational or institutional difficulties arise that are not resolved expeditiously.  

Currently, only two LNG import terminals are in operation: the Distrigas facility in Everett, Massachusetts, and the Trunkline facility in Lake Charles, Louisiana.  The other two existing import terminals, at Cove Point, Maryland, and at Elba Island, Georgia, are not expected to reopen for tanker imports in the projection period.

Offshore Royalty Relief

The Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58) gives the Secretary of Interior the authority to suspend royalty requirements on new production from qualifying leases and requires that royalty payments be waived on new leases sold in the 5 years following November 28, 1997.  The volume of production on which no royalties are due is assumed to be 17.5 million barrels of oil equivalent (BOE) in water depths of 200 to 400 meters, 52.5 million BOE in water depths of 400 to 800 meters, and 87.5 million BOE in water depths greater than 800 meters.  In any year during which the arithmetic average of the closing prices on the New York Mercantile Exchange for light sweet crude oil exceeds $28 per barrel or natural gas exceeds $3.50 per million Btu, any production of crude oil or natural gas will be subject to royalties at the lease stipulated royalty rate. 

Climate Change Action Plan

The natural gas production forecasts incorporate the expected results of the Climate Change Action Plan (CCAP)— Action Item 35, entitled Launch Coalbed Methane Outreach Program.  Under Action Item 35, the Department of Energy (DOE) and the Environmental Protection Agency (EPA) created a program to raise the awareness among key coal companies and State agencies of the potential for cost-effective methane emissions reduction.  

Estimates of the production resulting from this program through 2020 have been obtained from EPA. These production projections are presented in Table 48.

Table 48. Production from Mines Reached by CCAP Action Item 35

The annual production increases resulting (linear interpolations for interim year) from CCAP Action Item 35 are added to baseline forecasts of coalbed methane production from the OGSM.  The additional production is allocated regionally based on sharing factors derived from analysis in the EPA report, Opportunities to Reduce Anthropogenic Methane Emissions in the United States.72

Rapid and Slow Technology Cases

Two alternative cases were created to assess the sensitivity of the projections to changes in the assumed rates of progress in oil and natural gas supply technologies.  To create these cases, conventional oil and natural gas reference case parameters for the effects of technological progress on finding rates, drilling, lease equipment and operating costs, and success rates were adjusted upward and downward by 50 percent.  (Table 49)

Table 49. Assumed Average Annual Rates of Technological Progress on Costs Finding Rates, and Success Rates (Percemt)

A number of key exploration and production technologies for enhanced oil recovery and unconventional gas recovery were assumed to penetrate at alternative rates with varying degrees of effectiveness.

All other parameters in the model were kept at their reference case values, including technology parameters for other modules, parameters affecting foreign oil supply, and assumptions about imports and exports of LNG and natural gas trade between the United States and Mexico.