The National Energy Modeling System: An Overview 1998

The oil and gas supply module (OGSM) consists of a series of process submodules that project the availability of:

The driving assumption of the OGSM is that domestic oil and gas exploration and development are undertaken if the discounted present value of the recovered resources at least covers the present value of taxes and the cost of capital, exploration, development, and production, subject to a budget constraint. In contrast, international gas trade is determined in part by scenario-dependent, noneconomic factors. Crude oil is transported to refineries (which are simulated in the petroleum market module) for conversion and blending into refined petroleum products. The individual submodules of the oil and gas supply module are solved independently, with feedbacks achieved through NEMS solution iterations (Figure 13).

Technological progress is represented in OGSM through annual increases in the finding rates, economically recoverable resources, and success rates, as well as annual decreases in costs. While the OGSM methodology assumes that increases in cumulative drilling lower the finding rate, the methodology permits this decline to be partially, fully, or more than fully offset by improvements in technology. This "technological stretch" effect is represented by an assumed upwards shift in the finding rate function at the end of each forecast year. Moreover, the rate of decline in finding rates during a given year is assumed to be inversely related to the size of the remaining economically recoverable resource base. This rate of decline is slowed in OGSM through an assumed expansion of the economically recoverable resource base over time due to technological progress. Another representation of technology is in the success rates for exploratory wells, which are assumed to increase annually by a given constant percentage due to technological progress. Finally, technology is represented on the cost side by the existence of time-trend proxy coefficients in the cost equations. These coefficients are intended to capture the beneficial (cost-reducing) effects of technology by putting downward pressure on the drilling, lease equipment, and operating cost projections.

The lower 48 supply submodule projects oil and gas production by conventional recovery methods in onshore and shallow offshore regions and unconventional gas recovery in onshore regions. Unconventional gas is defined as gas produced from nonconventional geologic formations, as opposed to conventional (sandstones) and carbonate rock formations. The three nonconventional geologic formations considered are low-permeability or tight sandstones, gas shales, and coalbed methane. Enhanced oil recovery from onshore regions is handled separately. The lower 48 submodule actually consists of three separate submodules: onshore lower 48 conventional oil and gas supply, offshore oil and gas supply, and unconventional gas recovery supply.

The lower 48 submodule accounts for drilling, reserves estimates, and production capacity--computed independently (for the most part) for each region (6 onshore and 3 offshore) by well class (exploratory and developmental) and fuel category (conventional oil, conventional shallow gas, conventional deep gas, and unconventional gas):

OGSM Outputs	Inputs from NEMS	Exogenous Inputs
Crude oil production Domestic and Canadian natural gas supply curves Pipeline gas and liquefied natural gas imports (excluding Canada) and exports Cogeneration from oil and gas production Reserves and reserve additions Drilling levels Associated-dissolved gas production	Natural gas production by fuel type Oil, gas, and electricity prices Canadian natural gas imports and production	Resource levels Initial finding rate parameters and costs Production profiles Tax parameters Import capacity, costs, and availability

This submodule uses a field-based engineering and economic analysis approach to project reserve additions and production from resources in the deep water offshore Gulf of Mexico Outer Continental Shelf subregion. Two structural components make up the deep water offshore supply submodule, an exogenous price/ supply data generation routine and a endogenous reserves and production timing algorithm.

The price/supply data generation methodology employs a rigorous field-based discounted cash flow (DCF) approach. This offline model utilizes key field properties data, algorithms to determine key technology components, and algorithms to determine the explora-tion, development and production costs, and computes a minimum acceptable supply price (MASP) at which the discounted net present value of an individual prospect equals zero. The MASP and the recoverable resources for the different fields are aggregated by planning region and by resource type to generate resource-specific price-supply curves. In addition to the overall supply price and reserves, costs components for exploration, development drilling, production platform, and operating expenses, as well as exploration and development well requirements, are also carried over to the endogenous component.

After the exogenous price/supply curves have been developed, they are transmitted to and manipulated by an endogenous program within the OGSM. The endogenous program makes choices for field exploration and development based on relative economics of the project profitability compared with the equilibrium crude oil and natural gas prices determined by the petroleum market module and natural gas transmission and distribution module. Development of economically recoverable resources into proved reserves is constrained by drilling activity. Proved reserves are translated into production based on a production to reserves (P/R) ratio. The drilling activity and the P/R ratio are both determined by extrapolating the historical information.

This submodule projects the crude oil and natural gas produced in Alaska. The Alaska oil and gas submodule is divided into three sections: new field discoveries, development projects, and producing fields. Oil and gas transportation costs to lower 48 facilities are used in conjunction with the relevant market price of oil or gas to calculate the estimated net price received at the wellhead, sometimes called the "netback price." A discounted cash flow method is used to determine the economic viability of each project at the netback price. Alaskan oil and gas supplies are modeled on the basis of discrete projects, in contrast to the onshore lower 48 conventional oil and gas supplies, which are modeled on an aggregate level. The continuation of the exploration and development of multiyear projects, as well as the discovery of a new field, is dependent on its profitability. Production is determined on the basis of assumed drilling schedules and production profiles for new fields and developmental projects, historical production patterns, and announced plans for currently producing fields.

A field-based engineering submodule with hybrid exogenous (off-line) and endogenous (on-line) components is used to simulate the exploration and development of enhanced oil recovery (EOR) resources--a process that differs significantly from conventional oil and gas exploration and development:

Separate sets of tabular inputs from the exogenous EOR component are used by the endogenous EOR component for the high oil price, low oil price, and technological progress cases. These sets are developed by the exogenous EOR component based on differing assumptions regarding assumed future natural gas prices and rates of technological progress, as appropriate.

The foreign natural gas supply submodule projects natural gas trade via pipeline as well as liquefied natural gas (LNG) trade. The receiving regions for foreign gas supplies correspond to those of the natural gas integrating framework as established for the natural gas transmission and distribution module. Pipeline natural gas imports flow from two sources: Canada and Mexico. U.S. natural gas trade with Canada is represented by six entry/exit points, and trade with Mexico is represented by three entry/exit points (Figure 14).

Net Canadian natural gas supplies to the United States are determined at the six border crossing locations, over a range of gas prices. The initial step is to provide projections of Canadian drilling activity and supply. Canadian demand is then subtracted from supply to determine gas available for export. Gas supply availability is allocated to regional Canadian/U.S. border crossing points by an allocation algorithm that accounts for the associated pipeline capacities and the price responsiveness of supplies at the border points. The determination of the import volumes themselves occurs in the equilibration process of the natural gas transmission and distribution module. Mexican gas trade is a highly complex issue. A range of noneconomic factors influences, if not determines, flows of gas between the United States and Mexico. The uncertainty is so great that not only is the magnitude of flow for any future year in doubt, but also the direction of flow. Reasonable scenarios have been developed and defended in which Mexico may be either a net importer or exporter of hundreds of billions of cubic feet of gas by 2020. The vast uncertainty and the importance of noneconomic factors in future Mexican gas trade with the United States suggest that these flows should be handled on a scenario basis. Such a scenario can be introduced into the Mexican gas submodule as a user-specified path of future Mexican imports and exports. Otherwise, the analysis uses a prespecified default outlook for Mexican trade, drawn from an assessment of current and expected industry and market circumstances, as indicated in industry announcements or articles and reports in relevant publications. The outlook, regardless of its source, is fixed and is not responsive to energy price changes.

The volume of LNG imports into the United States is projected at four LNG terminals. Imported LNG costs compete with the purchase price of gas prevailing in the vicinity of the import terminal. This is a significant element in evaluating the competitiveness of LNG supplies, since LNG terminals vary greatly in their proximity to domestic producing areas. Terminals close to major consuming markets and far from competing producing areas may provide a sufficient economic advantage to make LNG a competitive gas supply source in some markets. In addition to costs, extensive operational assumptions are required to determine LNG imports. Dominant general factors affecting the outlook include expected developments with respect to the use of existing capacity, expansion at existing sites, and construction at additional locations. The LNG forecast also requires the specification of a combination of factors: available gasification capacity, schedules for and lags between constructing and opening a facility, tanker availability, expected utilization rates, and worldwide liquefaction capacity. For inactive terminals, it is necessary to determine the length of time required to restart operations (normally, between 12 and 18 months). These considerations are taken into account when the economic viability of LNG supplies is determined. The model accounts for LNG exports to Japan from Alaska using an exogenously specified forecast.

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