Petroleum Market Module
The NEMS Petroleum Market Module (PMM) projects 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, unfinished oil imports, other refinery inputs (including alcohols,
ethers, bioesters, corn, biomass, and coal), natural gas plant liquids
production, and refinery processing gain. In addition, the PMM projects
capacity expansion and fuel consumption at domestic refineries.
The PMM contains a linear programming (LP) representation of U.S. refining
activities in the five Petroleum Area Defense Districts (PADDs) (Figure
9). The LP model is created by aggregating individual refineries within
a PADD into two types of representative refineries, and linking all five
PADD's via crude and product transit links. This representation provides
the marginal costs of production for a number of conventional and new petroleum
products. In order to interact with other NEMS modules with different regional
representations, certain PMM inputs and outputs are converted from PADD
regions to other regional structures and vice versa. The linear programming
results are used to determine end-use product prices for each Census Division
(shown in Figure 5) using the assumptions and methods described below.
Key Assumptions
Product Types and Specifications
The PMM models refinery production of the products shown in Table 59.
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
fuels will remain the same as currently specified, with a few exceptions:
the sulfur content, which will be phased down to reflect EPA regulations
for all gasoline and diesel fuels; and, benzene will be reduced in gasoline
beginning in 2011.
Motor Gasoline Specifications and Market Shares
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 the PMM to differentiate between
conventional and reformulated gasoline blends (Table 60): Reid vapor pressure
(Rvp), benzene content, aromatic content, sulfur content, olefins content,
and the percent evaporated at 200 and 300 degrees Fahrenheit (E200 and
E300). The sulfur content specification for gasoline is reduced annually
through 2007 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 2004 and 2007.1 PMM assumes that
RFG has an average annual sulfur content of 135 ppm in 2000 and meets the
30 ppm requirement in 2004. 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 of gasoline are provided in Table 61.
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 II compliance standards which cannot exceed average 1990 levels of
toxic and nitrogen oxide emissions.2
Oxygenated gasoline is assumed to have specifications identical to conventional
gasoline, with the exception of a higher oxygen requirement, specifically
2.7 percent oxygen by weight. 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.
Cellulosic biomass feedstock supplies and costs are taken from the NEMS
Renewable Fuels Model. Initial capital costs for biomass cellulosic ethanol
were obtained from a research project reviewing cost estimates from multiple
sources.3 Operating costs and credits for excess electricity generated
at biomass ethanol plants were obtained from a National Renewable Energy
Laboratory report4 and the USDA Agricultural Baseline Projections to 2015.5
Corn supply prices are estimated from the USDA baseline projections to
2017.6 The capital cost of a 50-million-gallon-per-year corn ethanol plant
was assumed to be $69 million (2006 $). Operating costs of corn ethanol
plants are obtained from USDA survey of ethanol plant costs7. Energy requirements
are obtained from a study of carbon dioxide emissions associated with ethanol
production.8
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 62).
AEO2008 assumes MTBE will be phased out by the end of 2006 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 5.77% 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, oxygenated, and reformulated gasoline by applying assumptions
about the annual market shares for each type. The shares are allowed to
change over time based on assumptions regarding the market penetration
of new fuels. In AEO2008, however, the annual market shares for each region
reflect actual 2006 market shares and are held constant throughout the
projection. (See Table 63 for AEO2008 market share assumptions.)
Diesel Fuel Specifications and Market Shares
In order to account for diesel desulphurization regulations related to
Clean Air Act Amendment of 1990 (CAAA90), low-sulfur diesel is differentiated
from other distillates. In NEMS, Census Division 9 is required to meet
CARB standards. Both Federal and CARB standards currently limit sulfur
to 15 ppm.
AEO2008 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 AEO2008 ULSD price projections
as a distribution cost. The revenue loss associated with the 7.8 percent
downgrade assumption for 2008 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.
AEO2008 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 64).
State and Federal taxes are also added to transportation fuels to determine
final end-use prices (Tables 65 and 66). 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 AEO2008 assumption of current laws and regulations. Federal
taxes are deflated 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 66.
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.
Capacity Expansion
PMM allows for capacity expansion of all processing units including distillation,
vacuum distillation, hydrotreating, coking, fluid catalytic cracking, hydrocracking,
and alkylation manufacturing. 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, and biomass-to-liquids production.
Biofuels Supply
The PMM provides supply functions on an annual basis through 2030 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. Cellulosic ethanol production and biomass-to-liquids
(BTL) production compete for this feedstock.
- The Federal motor fuels excise tax credit for ethanol is 51 cents per
gallon of ethanol (5.1 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. It is assumed that the credit expires after 2010.
To model the new Renewable Fuels Standard in EISA07, several assumptions
were required. In addition to using the text of the Bill it was also assumed
that rules promulgated under the RFS in EPACT05 would govern the administration
of the EISA07 RFS.
- The penetration of cellulosic ethanol into the market is limited before
2012 to the projects cosponsored by DOE grants currently scheduled to produce
approximately 150 million gallons per year.
- Biomass-to-Liquid (Fischer-Tropsch) diesel fuel production contributes
1.5 credits towards the cellulosic mandate.
- Imported cane ethanol counts toward the advanced renewables mandate. In
addition, a limited supply of cellulosic ethanol would be available for
import and would count toward the cellulosic mandate.
- 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 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 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 4.4 cents
by 2020, depending on the average sales per dispenser.
- The total projected incremental infrastructure cost (transportation, distribution,
dispensing) for E85 varies from 27 cents per gallon in 2013 to 6 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 extends the credit again to 2008.
Gas-To-Liquids, Coal-To-Liquids, Biomass-To-Liquids, and Gasification Technologies
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. Given estimates showing
that GTL technology is a less profitable means for monetizing the natural
gas on the North Slope relative to an Alaska pipeline to the lower-48 states,
the earliest start date for a GTL facility is set at 2015. 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 (assumed dedicated to the
pipeline). The GTL facilities are built incrementally, with output volumes
of 50,000 barrels per day, at a cost of $49,100 per barrel of daily capacity
(2006 dollars). Operating costs are assumed to be $4.55 per barrel (2006
dollars). 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.
One CTL facility is capable of processing 21,800 tons of bituminous coal
per day, with a production capacity of 50,000 barrels of synthetic fuels
per day and 200 megawatts of capacity for electricity cogeneration sold
to the grid.11 A CTL facility of this size is assumed to cost over $2.5
billion in initial capital investment (2006 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. 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 liquefied petroleum gases. Petroleum products from CTL
facilities are assumed to be competitive when distillate prices rise above
the cost of CTL production (adjusted for credits from the sale of cogenerated
electricity). 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 AEO2008. 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 Nation, producing CHP and hydrogen.
Additional gasification capacity is projected to be built in the AEO2008 projection, primarily for CHP production.
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:
The PMM sells electricity back to the grid in these percentages at a price
equal to the average wholesale price of electricity in each PMM region.
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. Electricity prices are obtained
from the Electricity Market Model.
Short-term Methodology
Petroleum balance and price information for 2007 are projected at the U.S.
level in the Short-term Energy Outlook, (STEO). The PMM adopts the STEO results for 2007, 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.
AEO2008 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.
AEO2008 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.
AEO2008 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.
AEO2008 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.
AEO2008 represents major provisions in the Energy Policy Act of 2005 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.
AEO2008 includes provisions outlined in the Energy Independence and Security
Act of 2007 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 wheter 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) 32.5 billion gallons in 2022 for all fuels; 2) 17.5 billion gallons
in 2022 for advanced biofuels; 3) 12.5 billion gallons in 2022 for cellulosic
biofuel; 4) 1 billion gallons of biodiesel by 2022.
Petroleum Market Module Notes |
