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DOE/EIA-0554(2001) Report
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Petroleum Market Module 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.100 Key Assumptions Product Types and Specifications The PMM models refinery production of the products shown in Table 63. Table 63. Petroleum Product Categories The costs of producing different formulations of gasoline and diesel fuel that are required by State and Federal regulations 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, except that the sulfur content of all gasoline will be phased down to less than 10 percent of recent levels to reflect new regulations published by EPA in February 2000.101 The PMM models the production and distribution of three different types of gasoline: conventional, oxygenated, and reformulated (Phase 2). The following specifications are included in PMM to differentiate between conventional and reformulated gasoline blends (Table 64): 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). The sulfur specification for gasoline is reduced to reflect recent regulations requiring the average annual sulfur content of all gasoline used in the United States to be phased-down to 30 parts per million (ppm) between the years 2004 and 2007. PMM assumes that RFG has an average annual sulfur content of 135 ppm in 2000 and will meet the 30 ppm requirement in 2004. The reduction in sulfur content between now and 2004 is assumed to reflect incentives for “early reduction”. The regional assumptions for phasing-down the sulfur in conventional gasoline account for less stringent sulfur requirements for small refineries and refineries in the Rocky Mountain region. The 30 ppm annual average standard is not fully realized in conventional gasoline until 2008 due to allowances for small refineries. The sulfur specifications assumed for each region and type are provided in Table 65. Table 65. Gasoline Sulfur Content Assumptions, by Region and Gasoline Type, Parts per Million (PPM) Conventional gasoline must comply with antidumping requirements aimed at preventing the quality of conventional gasoline from eroding as the reformulated gasoline program is implemented. Conventional gasoline must meet the Complex Model compliance standards which cannot exceed average 1990 levels of toxic and nitrogen oxide emissions.102 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 conventional 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. 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 reflects “Phase II” reformulated gasoline requirements which began in 2000. 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.” (Table 64). 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 Air Resources Board (CARB) phase 2 specifications through 2002 and the recently developed “CARB3" specifications after 2002. The CARB3 specifications reflect the removal of the oxygen requirement designed to compliment the State’s plans to ban the oxygenate, methyl tertiary butyl ether (MTBE) by the end of 2002. Without a waiver from the U.S. EPA, a minimum oxygen content will still be required in the areas of California covered by the Federal reformulated gasoline program (Los Angeles, San Diego, and Sacramento). AEO2001 assumes that the oxygen requirement remains intact in these areas because no waiver had been granted at the time of the development of the forecast. AEO2001 reflects legislation which bans or limits the use of MTBE in seven additional States: Arizona, Connecticut, Maine, Minnesota, Nebraska, New York, and South Dakota. Since the oxygen requirement on RFG is assumed to continue in these States, the MTBE ban is modeled as a requirement to produce ethanol blended RFG. Ethanol blends were assumed to account for the following market percentages:
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 conventional, 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 AEO2001, the annual market shares for each region reflect actual 1999 market shares and are held constant throughout the forecast. The Census Divisions 3 and 4 market shares were adjusted because St. Louis, Missouri, joined the Federal reformulated gasoline program in the summer of 1999. (See Table 66 for AEO2001 market share assumptions.) Table 66. Market Share for Gasoline Types by Census Division Diesel Fuel Specifications and Market Shares In order to account for diesel desulfurization regulations related to CAAA90, low-sulfur diesel is differentiated from other distillates. In NEMS diesel fuel in Census Divisions 1 through 8 is required to meet Federal requirements, while diesel fuel in Census Division 9 is required to meet California Air Resources Board (CARB) standards. Both Federal and CARB standards limit sulfur to 500ppm. 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 1999, (on line: http://www.eia.doe.gov/oil_gas/petroleum/data_publications/ fuel_oil_ and_kerosene_sales/foks.html, September, 2000). Since about 15 percent of current demand in the transportation sector is off highway, 85 percent of transportation demand for distillate fuel is assumed to be low sulfur. Consumption of low-sulfur distillate also occurs in the industrial sector where it is assumed to be 50 percent of the market. 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 refineries (Table 67) are reflected as fixed costs (associated operation and maintenance costs prior to 1996 are excluded).103 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 68) and are assumed to be constant throughout the forecast and across scenarios. Table 68. Petroleum Product End-Use Markups by Sector and Census Division Distribution costs for each product, sector, and Census Division represent average historical differences between end-use and wholesale prices. The distribution costs for kerosene are the average difference between end-use prices of kerosene and wholesale distillate prices. Distribution costs for M85 are assumed to be equivalent to distribution costs for gasoline. State and Federal taxes are also added to transportation fuels to determine final end-use prices (Tables 69 and 70). 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. This assumption is extended to local taxes which are assumed to average 2 cents per gallon.104 Federal taxes are assumed to remain at current levels in accordance with the overall AEO2001 assumption of current laws and regulation. Federal taxes are deflated as follows:
Table 69. State and Local Taxes on Petroleum Transportation Fuels by Census Division 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 71. Table 71. Crude Oil Specifications A “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, estimates of total regional production are 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. Cogeneration Assumptions Electricity consumption in the refinery is a function of the throughput of each unit. Sources of electricity consist of refinery power generation, utility purchases, refinery cogeneration, and merchant cogeneration. Power generators and cogenerators are modeled in the PMM linear program as separate units which are allowed to compete along with purchased electricity. Both the refinery and merchant cogeneration units provide estimates of capacity, fuel consumption, and electricity sales to grid based on historical parameters. Refinery sales to the grid are estimated using the following perecentages which are based on 1998 data:
The PMM is forced to sell electricity back to the grid in these percentages at a price equal to the average price of electricity. Merchant cogenerator’s are defined as non-refiner owned facilities located near refineries to provide energy to the open market and to the neighboring refinery. The PMM assumes that 66 percent of electricity from merchant cogenerators in every region is sold to the grid. These sales occur at a price equal to the average of the generation price and the industrial price of electricity for each PMM region. Electricity prices are obtained from the Electricity Market Model. 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 occurs in NEMS when the value received from the additional product sales exceeds the investment and operating costs of the new unit. The investment costs assume a15-percent hurdle rate in the decision to invest and a 15-percent rate of return over a 15-year plant life. Expansion through 2000 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 2001, 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 AEO2001 assumes no additions for the Strategic Petroleum Reserve (SPR) during the forecast period. Any SPR draw is assumed to be in the form of a swap with a zero net annual change. Short-term Methodology Petroleum balance and price information for the year 2000 is projected at the U.S. level in the Short-term Energy Outlook, (STEO). The PMM assumes the STEO results for 1999, using regional estimates derived from the national STEO projections. Legislation and Regulations 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. Title II of the Clean air Act amendments of 1990 (CAAA90) established regulations for oxygenated and reformulated gasoline, and reduced-sulfur (500 ppm) on-highway diesel fuel, which are explicitly modeled in the PMM. Reformulated gasoline represented in the PMM meets the requirements of phase 2 of the Complex Model, except in the Pacific region where it meets CARB 3 specifications. The reformulated gasoline in areas of the Pacific region covered by the Federal RFG program continue to require 2.0 percent oxygen. AEO2001 reflects legislation which bans or limits the use of the gasoline blending component MTBE in the following states: Arizona, California, Connecticut, Maine, Minnesota, Nebraska, New York, and South Dakota. AEO2001 reflects “Tier 2" Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements finalized by EPA in February 2000. This regulation requires that the average annual sulfur content of all gasoline used in the United States be phased-down to 30 ppm between the years 2004 and 2007. The 30 ppm annual average standard is not fully realized in conventional gasoline until 2008 due to allowances for small refineries. 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.105 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. Biofuels (Ethanol) Supply Background The PMM provides supply functions on an annual basis through 2020 for ethanol produced from both corn and cellulosic biomass to produce transportation fuel. Assumptions
Cellulosic 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.106
Interregional transportation is assumed to be by rail, and the associated costs are included in the Petroleum Market Model. Methyl Tertiary Butyl Ether Ban Case This alternative case reflects recommendations from a Blue Ribbon Panel (BRP) of experts convened by the EPA to study problems associated with methyl tertiary butyl ether (MTBE) in water supplies. In addition to tighter controls on leaking underground storage tanks, the BRP recommend a substantial reduction in MTBE in gasoline and removal of the Federal oxygen requirement for reformulated gasoline. The BRP further noted that other ethers, such as ethyl tertiary butyl ether (ETBE) and tertiary amyl methyl ether (TAME), have similar but not identical characteristics and recommended studying the health effects and characteristics of those compounds before they are allowed to be placed in widespread use. Because of the greater scrutiny, refiners and blenders are unlikely to increase the use of these ethers significantly. As a result, the use of all ethers in gasoline was assumed to be limited in this case. Although the BRP did not specify a target level of MTBE, this case reflects a complete ban of MTBE as have numerous legislative proposals in 2000. The use of MTBE began to increase as a result of the introduction of oxygenated gasoline in the fall of 1993. The elimination of the oxygen specification in RFG requires that other specifications be adjusted in order to maintain air quality. In order to maintain current emissions levels of air toxics, as recommended by the BRP, the MTBE ban case assumes tighter limits on benzene in RFG than does the AEO2001 reference case (Table 72). In the MTBE ban case, gasoline consumption and crude oil price projections remain the same as in the AEO2001 reference case. The only changes relative to the reference case are gasoline specifications and the ban on ether use beginning in the year 2004. Table 72. Gasoline Specifications for MTBE Reduction Scenario Although the alternative case assumes that the oxygen requirement for RFG is removed, a wintertime oxygen requirement would remain intact for Los Angeles and surrounding areas that do not meet United States air quality standards for carbon monoxide. This isolated seasonal oxygen requirement is reflected as a weighted annual average requirement for the Federal ozone nonattainment areas.
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