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), linked to a simplified world refining industry representation used
to model U.S. crude and product imports. TheU.S. segment of the LP model
is created by aggregating individualU.S. refineries within a PADD into
two types of representative refineries, and linking all five PADD’s and
world refining regions 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 11.1.
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 of refineries by incorporating
the 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
content, which 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 11.2): 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 has been
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.
The sulfur specifications assumed for each region and type of gasoline
are provided in Table 11.3.
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 survey of recent literature4 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 $77 million (2007 $). 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 11.4).
AEO2009 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, oxygenated, and reformulated gasoline by applying assumptions
about the annual market shares for each type. In AEO2009 the annual market
shares for each region reflect actual 2007 market shares and are held constant
throughout the projection. (See Table 11.4 for AEO2009 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, the Pacific Region (Census Division 9)
is required to meet CARB standards. Both Federal and CARB standards currently
limit sulfur to 15 ppm.
AEO2009 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 AEO2009 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.
AEO2009 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 11.5).
State and Federal taxes are also added to transportation fuels to determine
final end-use prices (Tables 11.6 and 11.7). 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 AEO2009 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
11.8.
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 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, gas-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 in constant dollar terms. It is assumed that the credit
expires after 2010.
To model the new 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 projects (co-sponsored 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 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 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 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.
Gas-To-Liquids, Coal-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. 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 GTL facilities are built incrementally, with output
volumes of 34,000 barrels per day, at an capital cost of $52,023 per barrel
of daily capacity (2007 dollars). Variable operating costs are assumed
to be $4.67 per barrel (2007 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 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. A CTL facility of this size is assumed to cost about $3.97 billion
in initial capital investment (2007 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 AEO2009. 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. Additional gasification
capacity is projected to be built in the AEO2009 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:
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 2008 and 2009 are projected
at the U.S. level in the Short-term Energy Outlook, (STEO). The PMM adopts
the STEO results for 2008 and 2009, 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.
AEO2009 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.
AEO2009 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.
AEO2009 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.
AEO2009 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.
AEO2009 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.
AEO2009 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 2023.12
AEO2009 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, AEO2009 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 Notes |
