Report#:DOE/EIA-0554(99)
Introduction
Transportation
Demand
Electricity Market
Oil and Gas
Supply
Natural Gas Transmission & Distribution
Petroleum Market
Coal Market
Renewable Fuels
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Format
Assumptions to the AEO99
Interactive Data Queries to the AEO99
Supplemental Tables to
the AEO99
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The NEMS Petroleum Market Module (PMM) forecasts petroleum product prices and sources of supply for meeting petroleum product demand. The sources of supply include crude oil (both domestic and imported), petroleum product imports, other refinery inputs including alcohol and ethers, natural gas plant liquids production, and refinery processing gain. In addition, the PMM estimates capacity expansion and fuel consumption of domestic refineries.
The PMM contains a linear programming representation of refining activities in three U.S. regions. This representation provides the marginal costs of production for a number of traditional and new petroleum products. The linear programming results are used to determine end-use product prices for each Census Division using the assumptions and methods described below. 75
Key Assumptions
Product Types and Specifications
The PMM models refinery production of the products shown in Table 52.
The costs of producing new formulations of gasoline and diesel fuel that will be phased in as a result of the Clean Air Act Amendments of 1990 (CAAA90) are determined within the linear programming representation by incorporating specifications and demands for these fuels. The PMM assumes that the specifications for these new fuels will remain the same as specified in current legislation.
Table 52. Petroleum Product Categories
Motor Gasoline Specifications and Market Shares
The PMM models the production and distribution of three different types of gasoline: traditional, oxygenated, and reformulated. The following specifications are included in PMM to differentiate between traditional and reformulated gasoline blends (Table 53): octane, oxygen content, Reid vapor pressure (Rvp), benzene content, aromatic content, sulfur content, olefin content, and the percent evaporated at 200 and 300 degrees Fahrenheit (E200 and E300).
Traditional gasoline must comply with antidumping requirements aimed at preventing the quality of traditional gasoline from eroding as the reformulated gasoline program is implemented. Starting in 1998, traditional gasoline must meet the Complex Model compliance standards which cannot exceed average 1990 levels of toxic and nitrogen oxide emissions.76 Traditional gasoline during the 1998-2020 time period is assumed to have “1990 baseline” specifications.
Oxygenated gasoline, which has been required during winter in many U.S. cities since October of 1992, requires an oxygenated content of 2.7 percent by weight. Oxygenated gasoline is assumed to have specifications identical to traditional gasoline with the exception of a higher oxygen requirement. Some areas that require oxygenated gasoline will also require reformulated gasoline. For the sake of simplicity, the areas of overlap are assumed to require gasoline meeting the reformulated specifications.
Reformulated gasoline has been required in many areas in the U.S. since January 1995 (Table 53). In 1998, the EPA began certifying reformulated gasoline using the “complex model,” which allows refiners to specify reformulated gasoline based on emissions reductions from their company, 1990 baseline or the EPA’s 1990 baseline. The PMM uses a set of specifications that meet the “complex model” requirements, but it does not attempt to determine the optimal specifications that meet the “complex model.” Specifications such as Rvp, aromatics, sulfur, and olefin content change in the year 2000 reflecting “phase II” emission reduction requirements for the complex model (Table 53).
The CAAA90 provided for special treatment of California that would allow different specifications for oxygenated and reformulated gasoline in that State. In 1992, California requested a waiver from the winter oxygen requirements of 2.7 percent to reduce the requirement to a range of 1.8 to 2.2 percent. The PMM assumes that Petroleum Administration for Defense District (PADD) V refiners must meet the California specifications. The specifications for reformulated gasoline in PADD V are the same as California standards.
Rvp limitations are effective during summer months, which are defined differently in different regions. In addition, different Rvp specifications apply within each refining region, or PADD. The PMM assumes that these variations in Rvp are captured in the annual average specifications, which are based on summertime Rvp limits, wintertime estimates, and seasonal weights.
Motor Gasoline Market Shares
Within the PMM, total gasoline demand is disaggregated into demand for traditional, oxygenated, and reformulated gasoline by applying assumptions about the annual market shares for each type. The shares are able to change over time based on assumptions about the market penetration of new fuels. In AEO99, the annual market shares for each region reflect actual 1997 market shares and are held constant throughout the forecast. The Census Divisions 3 and 4 market shares were adjusted because St. Louis, Missouri, will be joining the Federal reformulated gasoline program in the summer of 1999. (See Table 54 for AEO99 market share assumptions.)
Table 54. Market Share for Gasoline Types by Census Division (Percentage)
Diesel Fuel Specifications and Market Shares
In order to account for diesel desulfurization regulations, low-sulfur diesel is differentiated from other distillates. Diesel fuel in Census Divisions 1 through 8 is assumed to meet Federal requirements, while diesel fuel in Census Division 9 is assumed to meet California Air Resources Board (CARB) standards.
The PMM contains a sharing methodology to allocate distillate demands between low and high sulfur. Market shares for low-sulfur diesel and distillate fuel are estimated based on data from EIA’s annual Fuel Oil and Kerosene Sales 1997, (on line: http://www.eia.doe.gov/oil_gas/fok/1996/fokframe96.html, November 3, 1997). Since about 20 percent of current demand in the transportation sector is off highway, 80 percent of transportation demand for distillate fuel is assumed to be low sulfur. Consumption of low-sulfur distillate outside of the transportation sector is assumed to be zero.
End-Use Product Prices
End-use petroleum product prices are based on marginal costs of production plus production-related fixed costs plus distribution costs and taxes. The marginal costs of production are determined by the model and represent variable costs of production including additional costs for meeting reformulated fuels provisions of the CAAA90. Environmental costs associated with controlling pollution at refineries77 (Table 55) are reflected as fixed costs (associated operation and maintenance costs prior to 1996 are excluded). Assuming that refinery-related fixed costs are recovered in the prices of light products, fixed costs are allocated among the prices of liquefied petroleum gases, gasoline, distillate, kerosene, and jet fuel. These costs are based on average annual estimates and are assumed to remain constant over the forecast period.
The costs of distributing and marketing petroleum products are represented by adding fixed distribution costs to the marginal and refinery fixed costs of products. The distribution costs are applied at the Census Division level (Table 56) and are assumed to be constant throughout the forecast and across scenarios.
Distribution costs for each product, sector, and Census Division represent average historical differences between end-use and wholesale prices. The costs for kerosene are the average difference between end-use prices of kerosene and wholesale distillate prices. Distribution cost for M85 are assumed to be equivalent to distribution costs for gasoline.
Table 56. Petroleum Product End-Use Markups by Sector and Census Division (1997 Dollars per Gallon)
State and Federal taxes are also added to transportation fuels to determine final end-use prices (Tables 57 and 58). Recent tax trend analysis indicated that State taxes increase at the rate of inflation, therefore, State taxes are held constant in real terms throughout the forecast. Federal taxes are assumed to remain at current levels in accordance with the overall AEO99 assumption of current laws and regulation. Federal taxes are deflated as follows:
Federal Tax product, year = Current Federal Tax product / GDP Deflator year
Table 58. Federal Taxes (1997 Dollars per Gallon)
Crude Oil Quality
In the PMM, the quality of crude oil is characterized by average gravity and sulfur levels. Both domestic and imported crude oil are divided into five categories as defined by the ranges of gravity and sulfur shown in Table 59.
Table 59. Crude Oil SpecificationsA “composite” crude oil with the appropriate yields and qualities is developed for each category by averaging the characteristics of specific crude oil streams that fall into each category. While the domestic and foreign categories are the same, the composite crudes for each category may differ because different crude streams make up the composites. For domestic crude oil, an estimate of total production is made first, then shared out to each of the five categories based on historical data. For imported crude oil, a separate supply curve is provided for each of the five categories.
Regional Assumptions
PMM reflects three refining regions: PADD I, PADD V, and a third region including PADD II-IV. Individual refineries are aggregated into one linear programming representation for each region. In order to interact with other NEMS modules with different regional representations, certain PMM inputs and outputs are converted from a PMM region to a non-PMM regional structure and vice versa.
Capacity Expansion Assumptions
PMM allows for capacity expansion of all processing units including distillation capacity, vacuum distillation, hydrotreating, coking, fluid catalytic cracking, hydrocracking, alkylation, and methyl tertiary butyl ether manufacture. Capacity expansion occurs by processing unit, starting from base year capacities established by PADD using historical data.
Expansion is determined when the value received from the additional product sales exceeds the investment and operating costs of the new unit. The investment costs assume a 15-percent rate of return over a 15-year plant life. Expansion through 1999 is determined by adding to the existing capacities of units planned and under construction that are expected to begin operating during this time. Capacity expansion plans are done every 3 years. For example, after the model has reached a solution for forecast year 2000, the PMM looks ahead and determines the optimal capacities given the demands and prices existing in the 2004 forecast year. The PMM then allows 50 percent of that capacity to be built in forecast year 2002, 25 percent in 2003, and 25 percent in 2004. At the end of 2004, the cycle begins anew, looking ahead to 2007.
Strategic Petroleum Reserve Fill Rate
AEO99 assumes no additions for the Strategic Petroleum Reserve during the forecast period. Additions to the Strategic Petroleum Reserve have not been included in recent budgets.
Short-term Methodology
Petroleum balance and price information for the years 1998 and 1999 are projected at the U.S. level in the Short-term Energy Outlook, September 1998 (STEO). The PMM assumes the STEO results for these years, using regional estimates derived from the national STEO projections.
Biofuels (Ethanol) Supply Submodule
Background
The Biofuels (Ethanol) Supply Submodule provides supply functions on an annual basis through 2020 for ethanol produced from both corn and biomass to produce transportation fuel.
Assumptions
- Corn feedstock supplies and costs are provided exogenously to NEMS. Feedstock costs reflect credits for co-products (livestock feed, corn oil, etc.). Feedstock supplies and costs reflect the competition between corn and its co-products and alternative crops, such as soybeans and their co-products.
- Biomass feedstock supplies and costs are taken from the NEMS Renewable Fuels Model. Capital and operating costs for biomass ethanol are derived from an Oak Ridge National Laboratory report.78
- All corn ethanol production is projected to come from PADD II, where most of the corn is grown. This is not an assumption of the model, but rather a result of the exogenous projections of feedstock costs and quantities. However, it is assumed that the supply will approximate reality to the point that it includes most of the production. Currently, biomass ethanol is also assumed to be produced in PADD II.
- The tax subsidy to ethanol of $0.54 per gallon of ethanol (5.4 cents per gallon subsidy to gasohol at a 10-percent volumetric blending portion) is applied within the premium. This subsidy is scheduled to be reduced to 51 cents by 2007. The tax subsidy is held constant in nominal terms, decreasing with inflation throughout the forecast. The subsidy is assumed not to expire during the forecast period.
- Interregional transportation costs are included in the Petroleum Market Model and are not part of the Biofuels Supply submodule.
Legislation
The PMM reflects recent national and regional legislative and regulatory changes that will affect future petroleum supply and product prices. It incorporates taxes imposed by the 1993 Budget Reconciliation Act and the 1997 Tax Payer Relief Act as well as costs resulting from environmental legislation.
The Budget Reconciliation Act imposes a tax increase of 4.3 cents per gallon on transportation fuels including gasoline, diesel, liquefied petroleum gases, and jet fuel. Except for jet fuel, the tax began on October 1, 1993. Jet fuel was granted a 2-year delay and was enacted in 1996.
The Tax Payer Relief Act of 1997 reduced excise taxes on liquefied petroleum gases and methanol produced from natural gas. The reductions set taxes on these products equal to the Federal gasoline tax on a Btu basis.
With a goal of reducing tailpipe emissions in areas failing to meet Federal air quality standards (nonattainment areas), Title II of the Clean Air Act Admendments of 1990 (CAAA90) established regulations for gasoline formulation. Starting in November 1992, gasoline sold during the winter in the initial 39 carbon monoxide nonattainment areas was required to be oxygenated.79 Starting in 1995, gasoline sold in major U.S. cities that are considered the most severe ozone nonattainment areas must be reformulated to reduce volatile organic compounds (which contribute to ozone formation) and toxic air pollutants, as well as meet a number of other new specifications. Additional areas with less severe ozone problems have chosen to “opt in” to the reformulated gasoline requirement. In 1998 reformulated gasoline will be required to meet a performance based definition, “The Complex Model”. In 2000 the performance measures will become more stringent.
Title II of the CAAA90 also established regulations on the sulfur and aromatics content of diesel fuel, which took effect October 1, 1993. All diesel fuel sold for use on highways now contains less sulfur and meets new aromatics or cetane level standards.
A number of pieces of legislation are aimed at controlling air, water, and waste emissions from refineries themselves. The PMM incorporates related environmental investments as refinery fixed costs. The estimated expenditures are based on results of the 1993 National Petroleum Council Study.80 These investments reflect compliance with Titles I, III, and V of CAAA90, the Clean Water Act, the Resource Conservation and Recovery Act, and anticipated regulations including the phaseout of hydrofluoric acid and a broad-based requirement for corrective action. No costs for remediation beyond the refinery site are included.
Lifting the ban on exporting Alaskan crude oil was passed and signed into law (PL 104-58) in November 1995. Alaskan exports of crude oil have represented about 60 percent of U.S. crude oil exports since November 1995 and are assumed to equal 60 percent of total U.S. crude oil exports in the forecast.
Reduced Sulfur Gasoline Cases
In early 1999 the EPA is expected to propose tighter restrictions on the amount of sulfur allowed in gasoline. Two alternative cases were created to assess the sensitivity of gasoline price and supply to assumed changes to gasoline sulfur limits for gasoline in various parts of the country. The alternative cases reflect proposals for sulfur reduction programs that have been submitted to the EPA by two groups: automakers - the American Automobile Manufacturers Association and the Association of International Automobile Manufacturers, and gasoline producers - the American Petroleum Institute (API) and the National Petrochemical and Refiners Association (NPRA).
Automakers’ National Low Sulfur Gasoline: The alternative case reflects the American Automobile Manufacturers Association/ Association of International Automobile Manufacturers (automakers) petition to the EPA to reduce the average allowable sulfur content of gasoline in the United States to 40 ppm, which is equivalent to the current standard in the State of California. The reduced sulfur standard is assumed to be enforced nationwide in 2004 as it is associated with requirements for technology for lower emissions “Tier 2" vehicles which are required for model year 2004.
API/NPRA Regional Reduced Sulfur Gasoline: The alternative case reflects a proposal by the American Petroleum Institute/National Petrochemical and Refiners Association for a reduced sulfur gasoline program beginning in 2004. The proposal is a regional plan in which all gasoline in Federal reformulated gasoline areas and in 23 States and in East Texas must meet an annual average of 150 ppm (See Table 60). Gasoline in California would continue to meet statewide gasoline requirements which includes a 40 ppm annual average sulfur limit, while gasoline in all other parts of the country would have an annual average 300 ppm. The “second step” of the proposal includes further reduction of sulfur in 2010 for areas that require year-round Nox control gasoline. The actual sulfur level and participants would be determined by a EPA study in 2006. The alternative case assumes 40 ppm gasoline requirements beginning in 2010 for the areas with the 150 ppm limit in 2004.
