Reformulated gasoline has been required in many areas in the United States 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 companies’ respective 1990 baselines or the EPA’s 1990  baseline.  The PMM reflects “Phase 2” 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 11.3). 

AEO2010 assumes MTBE was phased out by the end of 2007 as a result of decisions made by the petroleum industry to discontinue MTBE blending with gasoline.  Ethanol is assumed to be used in areas where reformulated or oxygenated gasoline is required. Federal reformulated gasoline (RFG) is blended with 10% ethanol; oxygenated gasoline is blended with 10% ethanol; and California Air Resources Board (CARB) RFG is blended with up to 10% ethanol.  Ethanol is also allowed to blend into conventional gasoline at up to 10 percent by volume, depending on its blending value and relative cost competitiveness with other gasoline blending components. EISA2007 defines a requirements schedule for having renewable fuels blended into transportation fuels by 2022.  

Reid Vapor Pressure (RVP) limitations are effective during summer months, which are defined differently by consuming 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.  

Within the PMM, total gasoline demand is disaggregated into demand for conventional, and reformulated gasoline by applying assumptions about the annual market shares for each type. In AEO2010 the annual market shares for each region reflect actual 2007 market shares and are held constant throughout the projection.   (See Table 11.3 for AEO2010 market share assumptions.) 

Diesel Fuel Specifications and Market Shares 

In order to account for ultra-low-sulfur diesel regulations related to Clean Air Act Amendment of 1990 (CAAA90), low-sulfur diesel is differentiated from other distillates.  In NEMS, the Pacific Region (Census Division 9) is required to meet CARB standards.   Both Federal and CARB standards currently limit sulfur to 15 ppm.

AEO2010 incorporates the “ultra-low-sulfur diesel” (ULSD) regulation finalized in December 2000. ULSD is highway diesel that contains no more than 15 ppm sulfur at the pump. The ULSD regulation includes a phase-in period under the “80/20” rule, that requires the production of a minimum 80 percent ULSD for highway use between June 2006 and June 2010, and a 100 percent requirement for ULSD thereafter.   As NEMS produces annual average results, only a portion of the production of highway diesel in 2006 is subject to the 80/20 rule and the 100 percent requirement does not cover all highway diesel until 2011. 

NEMS models ULSD as containing 7.5 ppm sulfur at the refinery gate in 2006, phasing down to 7ppm sulfur by 2011. This lower sulfur limit at the refinery reflects the general consensus that refiners will need to produce diesel with a sulfur content below 10 ppm to allow for contamination during the distribution process.  

It is assumed that revamping (retrofitting) existing refinery units to produce ULSD will be undertaken by refineries representing two-thirds of highway diesel production and that the remaining refineries will build new units. The capital cost of revamping is assumed to be 50 percent of the cost of adding a new unit.  

The amount of ULSD downgraded to a lower value product because of sulfur contamination in the distribution system is assumed to be 7.8 percent at the start of the program, declining to 2.2 percent at full implementation.  The decline reflects the expectation that the distribution system will become more efficient at handling ULSD with experience. 

A revenue loss is assumed to occur when a portion of ULSD that is put into the distribution system is contaminated and must be sold as a lower value product.   The amount of the revenue loss is estimated offline based on earlier NEMS results and is included in the AEO2010 ULSD price projections as a distribution cost.   The revenue loss associated with the 7.8 percent downgrade assumption for 2009 is 0.7 cents per gallon.   The revenue loss estimate declines to 0.2 cents per gallon after 2010 to reflect the assumed decline to 2.2 percent.  

The capital and operating costs associated with ULSD distribution are based on assumptions used by the EPA in the Regulatory Impact Analysis (RIA) of the rule. [9] Capital costs of 0.7 cents per gallon are assumed for additional storage tanks needed to handle ULSD during the transition period.  These capital expenditures are assumed to be fully amortized by 2011.   Additional operating costs for distribution of highway diesel of 0.2 cents per gallon are assumed over the entire projection period.   Another 0.2 cent cost per gallon is assumed for lubricity additives.  Lubricity additives are needed to compensate for the reduction of aromatics and high-molecular-weight  hydrocarbons  stripped  away  by  the  severe hydrotreating  used  in  the desulphurization process. 

Demand for highway-grade diesel, both 500 ppm and ULSD combined, is assumed to be equivalent to the total transportation distillate demand. Historically, highway-grade diesel supplies have nearly matched total transportation distillate sales, although some highway-grade diesel has gone to nontransportation uses such as construction and agriculture.  

The energy content of ULSD is assumed to decline from that of 500 ppm diesel by 0.5 percent because undercutting and severe desulphurization will result in a lighter stream composition than that for 500 ppm diesel.  

AEO2010 incorporates the “nonroad, locomotive, and marine” (NRLM) diesel regulation finalized in May 2004. The PMM model has been revised to reflect the nonroad rule and re-calibrated for market shares of highway, NRLM diesel, and other distillate (mostly heating oil, but excluding jet fuel and kerosene). The NRLM diesel rule follows the highway diesel rule closely and represents an incremental tightening of the entire diesel pool.  The demand for high sulfur distillate is expected to diminish over time, while the demand for ULSD (both highway and NRLM) is expected to increase over time.  

The final NRLM rule is implemented in multiple steps and requires sulfur content for all NRLM diesel fuel produced by refiners to be reduced to 500 ppm starting mid-2007. It also establishes a new ultra-low-sulfur diesel (ULSD) limit of 15 ppm for nonroad diesel by mid-2010.  For locomotive and marine diesel, the rule establishes an ULSD limit of 15 ppm in mid-2012. 

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 within the LP 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 are implicitly assumed in the annual update of the refinery investment costs for the processing units.  

The costs of distributing and marketing petroleum products are represented by adding product-specific distribution costs to the marginal refinery production costs (product wholesale prices).  The distribution costs are derived from a set of base distribution markups (Table 11.4). 

State and Federal taxes are also added to transportation fuels to determine final end-use prices (Tables 11.5 and 11.6).  Recent tax trend analysis indicates that State taxes increase at the rate of inflation, therefore, State taxes are held constant in real terms throughout the projection. This assumption is extended to local taxes which are assumed to average 2 cents per gallon. [10] Federal taxes are assumed to remain at current levels in accordance with the overall AEO2010 assumption of current laws and regulations.  Federal taxes are deflated to constant 2007$ as follows: 

Federal Tax _{product, year} = Current Federal Tax _product / GDP Deflator _year 

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 11.7. 

A “composite” crude oil with the appropriate yields and qualities is developed for each category by averaging the characteristics of specific crude oil streams in the 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. Each import supply curve is linked to a world oil supply market balance for that crude type, such that the quantity of crude oil imported depends on the economic competition with use by the rest of the world. 

Capacity Expansion 

PMM  allows  for  capacity  expansion  of  all  processing  unit types  including  distillation,  vacuum  distillation, hydrotreating, coking, fluid catalytic cracking, hydrocracking, and alkylation. 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 a financing ratio of 60 percent  equity and 40 percent debt, with a hurdle rate and an after-tax return on investment of about 9 percent. Capacity expansion plans are determined every 3 years.   For example, the PMM looks ahead in 2008 and determines the optimal capacities given the estimated demands and prices expected in the 2011 projection year.  The PMM then allows any of that capacity to be built in each of the projection years 2009, 2010, and  2011.  At the end of 2011 the cycle begins anew, looking ahead to 2014. ACU capacity under construction that is expected to begin operating during by 2010 is added to existing capacities in their respective start year.  Capacity  expansion is also  modeled  for  corn  and  cellulosic  ethanol,  coal-to-liquids, gas-to-liquids, and biomass-to-liquids production.  

Alternative Fuel Technology Characteristics 

The PMM explicitly models a number of liquid fuels technologies that do not require petroleum feedstocks. These technologies produce both fuel grade products for blending with traditional petroleum products as well as alternative feedstocks for the traditional petroleum refinery (Table 11.8).  

Estimates of capital costs, operating cost, and process yield for these technologies are shown in Table 11.9. Costs are defined for 2007 and are escalated in the PMM using the GDP deflator. Owner’s Capital Cost is defined as the anticipated cost for a fully continuous, commercial scale plant. However, some of the technologies have not yet been proven at a commercial scale. As a result, a technology optimism factor is applied to the owner’s capital cost for the first plant of those technologies. For the next four plants, the capital cost decreases linearly such that the fifth plant is built at the owner’s capital cost defined in the table. Following this phase, capital cost is decreased at a rate corresponding to the maturity of the components that make up the technology, reflecting the principle of learning by doing.This principle is implemented in the PMM in the same way as it is in the Electricity Market Module. Model parameters are shown in Table 11.10. 

Variable operating cost includes the cost of feedstock, utility requirements, coproduct credit, and other costs that depend on the technology and they represent the expected costs to operate a fully continuous, commercial scale plant for each technology. The breakdown is shown in Table 11.11. 

Alternative Fuels Market Dynamics 

In the PMM, overnight capital costs are annualized and then added to variable and fixed costs in order to provide a cost of production. [11] As a result of this inclusion of capital cost in the cost of production, a given technology’s production cost has the potential to become more or less attractive relative to other technologies as plants are built. 

While cost of production defines a basis for comparison, market competition is often defined by the required feedstock. For example, technologies requiring vegetable oils (biodiesel and renewable diesel) compete with each other for that feedstock, limiting the overall market share of each technology. As a consequence of this and the Renewable Fuels Standard, cellulosic ethanol and Biomass to Liquids (BTL) technologies, which include Fischer-Tropsch and Pyrolysis, compete directly with each other. By contrast, technologies like Gas to Liquids and Coal to Liquids compete more directly with petroleum fuels, since their feedstocks are more similar to petroleum and their fuels are not required by the RFS. Renewable Diesel on the other hand, which refers to hydrodeoxygenation of vegetable oils and animal fats, often competes directly with petroleum fuels, despite its feedstock, since it is not eligible for the same tax credit as methyl ester biodiesel when co-processed with petroleum feeds 

Biofuels Supply 

The PMM provides supply functions on an annual basis through 2035 for ethanol produced from both corn and cellulosic biomass to produce transportation fuel.   It also assumes that small amounts of vegetable oil and animal fats are processed into biodiesel, a blend of methyl esters suitable for fueling diesel engines. 

• 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. 

• Cellulosic (biomass) feedstock supply and costs are provided by the Renewable Fuels Module in NEMS.    

• The Federal motor fuels excise tax credit  for ethanol is  45 cents  per gallon of ethanol (4.5 cents per gallon credit to gasohol at a 10-percent volumetric blending portion) is applied within the model.  The tax credit is held constant in nominal terms, decreasing with inflation throughout the projection in constant dollar terms.  It is assumed that the credit expires after 2010. 

To model the Renewable Fuels Standard in EISA2007, several assumptions were required. In addition to using the text of the legislation it was also assumed that rules promulgated under the RFS in EPACT05 would govern the administration of the EISA2007 RFS. 

• The  penetration  of  cellulosic  ethanol  into  the  market  is  limited  before 2012  to the likely projects currently expected to produce approximately 5 million gallons per year. 

• Methyl ester biodiesel production contributes 1.5 credits towards the advanced mandate. 

• Renewable Diesel and Fischer-Tropsch diesel contribute 1.7 credits toward the cellulosic mandate.

• Renewable gasoline and Fischer-Tropsch naphtha contribute 1.54 credits toward the cellulosic mandate. 

• Pyrolysis Oil production contributes 1 credit toward the advanced mandate under RFS1 rules regarding biomass based crude oils. 

• Imported Brazilian sugarcane ethanol counts towards the advanced renewable mandate.  Supply curves for sugarcane ethanol imports allow for substantial penetration by 2022 (1.5 billion gallons) into the U.S. advanced fuel supply pool, after which sugarcane ethanol remains competitive due to its relatively low production cost, availability, and the assumed expiration of the 54 cents/gallon import tariff by Jan. 1, 2011.  Ample sugarcane ethanol supply for export from Brazil is supported by outside forecasts [12].  In addition, cellulosic ethanol would be available for export to the U.S. (largely from bagasse feedstock) but this supply is limited in part due to competition with the growing use of sugarcane residue for electricity generation in Brazil. 

•  The cellulosic biofuel waiver, when activated, reduces the cellulosic, advanced, and total requirement by that amount in all future years.  In years beyond 2022, the last year specified in the EISA, the RFS mandate levels are held constant. 

• It  is  assumed  that  biodiesel  and  BTL  diesel  may  be  consumed  in  diesel  engines without  significant infrastructure modification (either vehicles or delivery infrastructure).  

• Ethanol is assumed to be consumed as either E10 or E85, with no intermediate blends. The cost of placing E85 pumps at the most economic stations is spread over all transportation fuels.  Using this assumption, the E10 blending market is assumed to be saturated and the E85 market consumes additional ethanol after 2014. 

• To accommodate the ethanol requirements in particular, transportation modes are expanded or upgraded for both E10 and E85, and it is assumed that most ethanol originates from the Midwest, with nominal  transportation costs ranging from a low of 1.7 cents per gallon for expanded distribution in the Midwest, to as high as 2.6 cents per gallon for the Southeast and West Coast. 

• For E85 dispensing stations, it is assumed the average cost of a retrofit and new station is about $45,000 per station, which translates into an incremental cost per gallon ranging from 26 cents in 2013 to 3 cents by 2020, depending on the average sales per dispenser. 

• The total projected incremental nominal infrastructure cost (transportation, distribution, dispensing) for E85  varies from 27 cents per gallon of E85 in 2013 to 5 cents per gallon in 2020. 

Interregional transportation is assumed to be by rail, ship, barge, and truck, and the associated costs are included in PMM.   A subsidy is offered by the Department of Agriculture’s Commodity Credit Corporation for the production of biodiesel.  In addition, the American Jobs Creation Act of 2004 provides an additional tax credit of $1 per gallon of soybean oil for biodiesel and 50 cents per gallon for yellow grease biodiesel until 2006, and EPACT05 extended the credit again to 2008. The Emergency Stabilization Act of 2008 extended it again to 2009 and increased the yellow grease credit to $1 per gallon. 

Non-Biofuel Alternative Supply 

Gas-to-liquids (GTL) facilities convert natural gas into distillates, and are assumed to be built if the prices for lower sulfur distillates reach a high enough level to make it economic. In the PMM, gas-to-liquids facilities are assumed to be built only on the North Slope of Alaska, where the distillate product is transported on the Trans-Alaskan Pipeline System (TAPS) to Valdez and shipped to markets in the lower 48 States. The earliest start date for a GTL facility is set at 2017. Also, the source of feedstock gas to any GTL facility in Alaska is assumed to be from undiscovered, non-associated resources which will be more costly than the current, largely associated proved reserves on the North Slope, which are assumed to be dedicated to the pipeline.  The transportation cost to ship the GTL product from the North Slope to Valdez along the TAPS is assumed to be the price set to move oil (i.e. the TAPS revenue recovery rate).  This rate is a function of allowable costs, profit, and flow, and can change over the projection. 

It is also assumed that coal-to-liquids (CTL) facilities will be built when low-sulfur distillate prices are high enough to make them economic. Additionally, a proces which allows co-firing of coal with biomass (CBTL) is explicitly modeled for producers who wish to receive RFS credit for a portion of their product.   A CTL facility of this size is assumed to cost about $4.62 billion in initial capital investment (2008 dollars).  CTL facilities could be built near existing refineries. For the East Coast, potential CTL facilities could 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.  It is assumed that CTL facilities can only be built after 2010. 

Gasification of petroleum coke (petcoke) and heavy oil (asphalt, vacuum resid, etc.) is represented in AEO2010. The PMM assumes petcoke to be the primary feedstock for gasification, which in turn could be converted to either combined heat and power (CHP) or hydrogen production based on refinery economics. A typical gasification facility is assumed to have a capacity of 2,000 ton-per-day (TPD) which includes the main gasifier and other integrated units in the refinery such as air separation unit (ASU), syngas clean-up, sulfur recovery unit (SRU), and two downstream process options - CHP or hydrogen production.  Currently, there is more than 5,000 TPD gasification capacity in the U.S. that produces CHP and hydrogen. 

Combined Heat and Power (CHP) 

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 CHP, and merchant CHP.  Power generators and CHP plants are modeled in the PMM linear program as separate units which are allowed to compete along with purchased electricity. Both the refinery and merchant CHP units provide estimates of capacity, fuel consumption, and electricity sales to the grid based on historical parameters. 

Refinery sales to the grid are estimated using the following percentages which are based on 2005 data: 

Merchant CHP plants are defined as non-refiner owned facilities located near refineries to provide energy to the open market and to the neighboring refinery. These sales occur  at a price equal to the average wholesale price of electricity in each PMM region, which are obtained from the Electricity Market Model. 

Short-term Methodology 

Petroleum balance and price information for 2009 and 2010 are projected at the U.S. level in the Short-term Energy Outlook, (STEO).   The PMM adopts the STEO results for 2009 and 2010, 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 CAAA90 established regulations for oxygenated and reformulated gasoline and reduced-sulfur (500 ppm) on-highway diesel fuel. These 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.  

AEO2010 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. 

AEO2010 reflects Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements finalized by the EPA in December 2000.  Between June 2006 and June 2010, this regulation requires that 80 percent of highway diesel supplies contain no more than 15 ppm sulfur while the remaining 20 percent of highway diesel supplies contain no more than 500 ppm sulfur. After June 2010, all highway diesel is required to contain no more than 15 ppm sulfur at the pump. 

AEO2010 reflects nonroad locomotive and marine (NRLM) diesel requirements finalized by the EPA in May 2004. Between June 2007 and June 2010, this regulation requires that nonroad diesel supplies contain no more than 15 ppm sulfur.  For locomotive and marine diesel, the action establishes a NRLM limit of 15 ppm in mid-2012. 

AEO2010 incorporates the American Jobs Creation Act of 2004 to extend the Federal tax credit of 51 cents per gallon of ethanol blended into gasoline through 2010. 

AEO2010 represents major provisions in the Energy Policy Act of 2005 (EPACT05) concerning the petroleum industry, including: 1) removal of oxygenate requirement in RFG; and 2) extension of tax credit of $1 per gallon for soybean oil biodiesel and $0.50 per gallon for yellow grease biodiesel through 2008.  

The Emergency Stabilization Act of 2008 extended the soybean oil for biodiesel tax credit again to 2009 and increased the yellow grease credit to $1 per gallon. 

AEO2010 includes provisions outlined in the Energy Independence and Security Act of 2007 (EISA2007) concerning the petroleum industry, including a renewable Fuels Standard increasing total U.S. consumption of renewable fuels.  Although the statute calls for higher levels, due to uncertainty about whether the new RFS schedule can be achieved and the stated mechanisms for reducing the cellulosic biofuel schedule, the final schedules in PMM were assumed to be: 1) 30.9 billion gallons in 2023 for all fuels; 2) 15.9 billion gallons in 2023 for advanced biofuels; 3) 10.9 billion gallons in 2023 for cellulosic biofuel; 4) 1 billion gallons of biodiesel by 2023.[13] 

AEO2010 includes the EPA Mobil Source Air Toxics (MSAT 2) rule which includes the requirement that all gasoline products (including reformulated and conventional gasoline) produced at a refinery during a calendar year will need to contain no more than 0.61 percent benzene by volume. This does not include gasoline produced or sold in California which is already covered by the current California Phase 3 Reformulated Gasoline Program. 

Due to the uncertainty surrounding compliance options, AEO2010 did not include any explicit modeling treatment of the International Maritime Organization’s “MARPOL Annex 6” rule covering cleaner marine fuels and ocean ship engine emissions.

Petroleum Market Module - Tables

Petroleum Market Module Notes