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Report
#: DOE/EIA-0581(2003 Released March 4, 2003 Report
Contents Annual
Energy Outlook 2003 |
The
National Energy Modeling System: An Overview 2003 Petroleum Market Module The petroleum market module (PMM) represents domestic refinery operations and the marketing of petroleum products to consumption regions. PMM solves for petroleum product prices, crude oil and product import activity (in conjunction with the international energy module and the oil and gas supply module), and domestic refinery capacity expansion and fuel consumption. The solution is derived, satisfying the demand for petroleum products and incorporating the prices for raw material inputs and imported petroleum products, the costs of investment, and the domestic production of crude oil and natural gas liquids. The relationship of PMM to other NEMS modules is illustrated in Figure 17. PMM is a regional, linear–programming representation of the U.S. petroleum market. Refining operations are represented by a three–region linear programming formulation of the five Petroleum Administration for Defense Districts (PADDs) (Figure 18). PADDs I and V are each treated as single regions, while PADDs II, III, and IV are aggregated into one region. Each region is considered as a single firm where more than 40 distinct refinery processes are modeled. Refining capacity is allowed to expand in each region, but the model does not distinguish between additions to existing refineries or the building of new facilities. Investment criteria are developed exogenously, although the decision to invest is endogenous. PMM assumes that the petroleum refining and marketing industry is competitive. The market will move toward lower–cost refiners who have access to crude oil and markets. The selection of crude oils, refinery process utilization, and logistics (transportation) will adjust to minimize the overall cost of supplying the market with petroleum products. Although the petroleum market responds to pressure, it rarely strays from the underlying refining costs and economics for long periods of time. If demand is unusually high in one region, the price will increase, driving down demand and providing economic incentives for bringing supplies in from other regions, thus restoring the supply/demand balance. Existing regulations concerning product types and specifications, the cost of environmental compliance, and Federal and State taxes are also modeled. PMM incorporates taxes imposed by the 1993 Budget Reconciliation Act as well as costs resulting from the Clean Air Act Amendments of 1990 (CAAA90) and other environmental legislation. The costs of producing new formulations of gasoline and diesel fuel as a result of the CAAA90 are determined within the linear–programming representation by incorporating specifications and demands for these fuels. An important innovation in NEMS involves the relationship between the domestic and international markets. Whereas earlier models postulated entirely exogenous prices for oil on the international market (the world oil price), NEMS includes an international energy module that estimates supply curves for imported crude oils and products based on, among other factors, U.S. participation in international trade. Regions PMM models U.S. crude oil refining capabilities based on the five PADDs which were established during World War II and are still used by EIA for data collection and analysis. The use of PADD data permits PMM to take full advantage of EIA’s historical database and allows analysis and forecasting within the same framework used by the petroleum industry. Product Categories Product categories, specifications, and recipe blends modeled in PMM are included in the "Petroleum Products Modeled in PMM" table. Fuel Use PMM determines refinery fuel use by refining region for purchased electricity, natural gas, distillate fuel, residual fuel, liquefied petroleum gas, and other petroleum. The fuels (natural gas, petroleum, other gaseous fuels, and other) consumed within the refinery to generate electricity from CHP facilities are also measured. Crude Oil Categories Both domestic and imported crude oil are aggregated into five categories, as defined by the following ranges of gravity and sulfur (see "Crude Oil Categories in PMM" table). This aggregation of crude oil types allows PMM to account for changes in crude oil composition over time. A composite crude with the appropriate yields and qualities is developed for each category by averaging characteristics of specific crude oil streams that fall into each category. While the domestic and foreign categories are the same, the composites for each type may differ, because different crude oil streams make up the composites. Refinery Processes Not every refinery processing unit is represented in PMM. The refinery processes represented were chosen because they have the most significant impact on production. The following distinct processes are represented in the "Refinery Processing Units Modeled in PMM" table. Natural Gas Plants The outputs of natural gas processing plants, including ethane, propane, butane, isobutane, and natural gasoline are modeled in PMM. These products move directly into the market to meet demand or are inputs to the refinery. Ethanol PMM contains an ethanol submodule which provides the PMM linear program with regional ethanol supplies and prices. Ethanol quantity/price curves are calculated in each Census Division for both corn–derived and cellulose–derived ethanol, allowing PMM to forecast transportation ethanol demand. The supply curves take into account feedstock costs, feedstock conversion costs, and energy prices. Corn and corn co–product quantities and costs are provided exogenously from the USDA Agricultural Baseline Projections to 2011.29 Cellulose feedstock supply/price curves are provided by the renewable fuels module of NEMS. End-Use Markups The linear–programming portion of the model provides unit prices of products sold in the refinery regions (refinery gate) and in the demand regions (wholesale). End–use markups are added to produce a retail price for each of the Census Divisions. The markups are based on an average of historical markups, defined as the difference between the end–use prices by sector and the corresponding wholesale price for that product. The average is calculated using data from 1989 to the present. Because of the lack of any consistent trend in the historical end–use markups, the markups remain at the historical average level over the forecast period. State and Federal taxes are also added to transportation fuel prices to determine final end–use prices. Recent tax trend analysis indicates that State taxes increase at the rate of inflation, while Federal taxes do not. In PMM, therefore, State taxes are held constant in real terms throughout the forecast while Federal taxes are deflated at the rate of inflation. Gasoline Types Federal and State legislations have resulted in the production of several blends of gasoline. PMM categorizes these blends into four gasoline types: conventional gasoline, oxygenated gasoline, Federal reformulated gasoline, and California reformulated gasoline. The conventional category includes gasoline blended with 10–percent ethanol, also known as gasohol. Oxygenated gasoline is conventional gasoline containing a minimum of 2.7–percent oxygen by weight for use in specific regions of the United States during the winter months to reduce carbon monoxide. Federal reformulated gasoline is blended according to U.S. Environmental Protection Agency (EPA) Complex Model II specifications with a minimum oxygen content of 2.0 percent by weight for use in ozone non–attainment areas. PMM uses either ethanol or ethers (MTBE, ETBE, and other ethers) to obtain the 2.0 percent oxygen requirement. However, after 2004, the model uses only ethanol in Census Division 9 to make Federal reformulated gasoline, because of California legislation which bans the use of MTBE in gasoline by the end of 2003. California reformulated gasoline is blended to the California Air Resources Board (CARB) specifications, which are more severe than the Federal reformulated standards, but have no minimum oxygen requirement. Because about two–thirds of California’s gasoline consumption occurs within Federal ozone nonattainment areas, gasoline in these areas is also assumed to meet the Federal oxygen requirement of 2.0 percent. Although the reference case assumes current laws and regulations, additional product specifications can be modeled for policy analysis. Ultra–Low–Sulfur Diesel In December 2000, EPA promulgated the “ultra-low-sulfur diesel” (ULSD) regulation for highway diesel. By definition, ULSD is highway diesel that contains no more than 15–ppm sulfur at the pump. The new regulation contains the “80/20” rule, which requires the production of 80 percent ULSD and 20 percent 500 ppm highway diesel between June 2006 and June 2010, and a 100–percent requirement for ULSD thereafter. Because NEMS is an annual average model, the full impact of the 80/20 rule cannot be seen until 2007, and the impact of the 100– percent requirement cannot be seen until 2011. Major assumptions related to the implementation of the ULSD rule are as follows:
Gas–To–Liquids and Coal–To–Liquids If prices for lower sulfur distillates reach a high level, it is assumed that gas-to-liquids (GTL) facilities will be built on the North Slope of Alaska to convert stranded natural gas into distillates, to be transported on the Trans-Alaskan Pipeline System (TAPS) to Valdez and shipped to markets in the lower 48 States. The facilities are assumed to be built incrementally, no earlier than 2005, with output volumes of 50,000 barrels per day, at a cost of $21,500 per barrel of daily capapcity (2001 dollars). Operating costs are assumed to be $3.99 per barrel. Transportation costs to ship the GTL product from the North Slope to Valdez along the TAPS range from $2.75 to $4.45 per barrel, depending on total oil flow on the pipeline and the potential need for GTL to maintain the viability of the TAPS line if Alaskan oil production declines. Initially, the natural gas feed is assumed to cost $0.82 per million cubic feet (2001 dollars). It is also assumed that coal-to-liquids (CTL) facilities will be built when low sulfur distillate prices are high. One CTL facility is capable of processing 16,400 tons per day bituminous coal and will have a production capacity of 33,200 barrels per day of synthetic fuels and 696 MW of CHP electric generating capacity. CTL facilities are assumed to be built near existing refineries. For the East Coast, potential CTL facilities are assumed to be built near the Delaware River basin; for the Central region, near the Illinois River basin or near Billings, Montana; and for the West Coast, in the vicinity of Puget Sound in Washington State. The CTL yields are assumed to be similar to those from a GTL facility because both involve the Fischer-Tropsch process to convert syngas (CO + H2) to liquid hydrocarbons. The primary yields would be distillate and kerosene, with additional yields of naphthas and LPG. Petroleum product production from CTL’s is assumed to be competitive when distillate prices rise above the cost of CTL production – adjusted for credits from the sale of electricity co-products. |