Introduction
On June 17, 2002, Senator Jeff Bingaman, Chairman of the Senate Committee
on Energy and Natural Resources, requested that EIA provide analysis of
eight factors related to the Senate-passed fuels provisions of H.R. 4,
the Energy Policy Act of 2002.1 In response, the Energy Information Administration
(EIA) has prepared a series of analyses discussing the market impacts
of each of these factors.
Because of the rapid delivery time requested by Sen. Bingaman, each requested
factor related to the Senate-passed bill was analyzed separately, that
is, without analyzing the interactions among the various provisions. In
addition, assumptions about State actions, such as their implementation
and timing of MTBE bans, influence the results. Discussions about some
of these interactions have been included in order to explain the interconnected
nature of such issues.
EIA’s projections are not statements of what will happen but what
might happen, given known technologies, technological and demographic
trends, and current laws and regulations. The Annual Energy Outlook 2002
(AEO2002) is used in these analyses to provide a policy-neutral Reference
Case that can be used to analyze energy policy initiatives. EIA does not
propose, advocate or speculate on future legislative or regulatory changes.
Laws and regulations are assumed to remain as currently enacted or in
force in the Reference Case; however, the impacts of emerging regulatory
changes, when clearly defined, are reflected.
The analyses involve simplified representations of reality because reality
is complex. Projections are highly dependent on the data, methodologies,
and assumptions used to develop them. Because many of the events that
shape energy markets are random and cannot be anticipated (including severe
weather, technological breakthroughs, and geopolitical disruptions), energy
market projections are subject to uncertainty. Further, future developments
in technologies, demographics, and resources cannot be foreseen with any
degree of certainty. These uncertainties are addressed through analysis
of alternative cases in the AEO2002.
Near-Term Renewable Motor Fuels Capacity
The authors of H.R. 4 write that, “The term ‘renewable fuel’
means motor vehicle fuel that is produced from grain starch, oilseeds,
or other biomass; or is natural gas produced from a biogas source, including
a landfill, sewage waste treatment plant, feedlot, or other place where
decaying organic material is found…”
Although many known, and perhaps some unknown, renewable fuel sources
qualify under the definition, through 2020 the requirement for renewable
content of motor vehicle fuel is expected to be met primarily by ethanol
blended into gasoline at volume fractions of 10 percent or lower.
There are several ways to produce ethanol. H.R. 4 makes specific reference
to emerging technology for conversion of cellulose to ethanol. Each gallon
of ethanol produced from cellulosic feedstocks is to be counted as 1.5
gallons of renewable motor vehicle fuel. Ethanol can be produced from
cellulose by conversion of the cellulose to sugar and fermentation. It
can also be produced by gasification of cellulose and subsequent catalytic
conversion to ethanol. Both technologies are still at the pilot stage.
It is hoped that this credit for cellulose ethanol will accelerate its
commercialization.
The established technology for ethanol production is fermentation of sugars
from sugary plants or from plant starches converted to sugar. Corn is
the most common raw material for ethanol production in the United States.
There are two methods of ethanol production from corn: wet milling and
dry milling. All ethanol production requires water, but wet mills are
so named because the first step in the process is soaking the corn in
hot water to allow for subsequent separation of the grain into components.
Wet mills generally produce corn oil and the animal feed ingredients corn
gluten meal and corn gluten feed in addition to ethanol. Some of the starch
may be diverted to starch or sweetener production. The dry mill process
begins with the grinding of the grain before water is added. Dry mills
produce distillers’ dried grains, also an animal feed, along with
ethanol. Existing ethanol capacity is about half wet mill and half dry
mill. New plants are expected to be dry mills, because the capital cost
per gallon of dry mill capacity is considerably lower than that for wet
mill capacity.
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Whether dry mill or wet mill, ethanol plants yield 2.65 gallons of fuel
ethanol per bushel of corn input. The cost of corn per gallon of ethanol
is projected to be $0.88 (2000 dollars) in 2004 (Table 1). Energy requirements
vary by technology. Existing wet mills use 40,848 British Thermal Units
(Btu) of coal and 10,212 Btu of natural gas per gallon of ethanol on average.
Existing dry mills are expected to use 18,900 Btu of coal, an average
of 18,900 Btu of natural gas, and 1.09 kilowatt-hours of electricity per
gallon by 2004. New dry mills are expected to use an average of 37,800
Btu of natural gas and 1.09 kilowatt hours (or 3712 Btu) of electricity
per gallon.2,3 Dry mills are expected to reduce consumption of coal and
natural gas over the forecast period.4 Energy cost projections are based
on industrial sector projections for 2004.5
Dry mills’ revenue from the sale of distillers’ dried grains
and wet mills’ revenue from the sale of corn gluten feed, corn gluten
meal, and corn oil is reflected in the coproduct credit for each type
of plant. Existing plants will operate as long as average variable costs
are covered. Capital costs already incurred are not applicable to the
decision to operate. New plants will only be built and operated if average
total costs are covered.
EIA does not collect ethanol capacity data, but collects monthly production
data. So far in 2002, United States ethanol production has averaged 128,000
barrels per day. If production continues at this same pace, 1.962 billion
gallons will be produced for the entire year.6 Ethanol production in 2001
was 1.765 billion gallons.7
The Renewable Fuels Association (RFA), an ethanol industry trade group,
maintains a list of ethanol producers, their plant sizes, and their feedstocks.
The producers on the RFA list have existing capacity of 2.4 billion gallons
per year. Of that, approximately 2.3 billion gallons are located in the
Midwest region. All of the capacity being added, about 460 million gallons,
is in the Midwest. About 55 million gallons of existing capacity are dedicated
to feedstocks other than corn. Alternative feedstocks include milo, or
grain sorghum, waste from beverage alcohol production, potato waste, sugar,
and cheese whey. In addition to corn, barley and wheat starch are used
by some producers. All of the new capacity is to be corn-fed and is expected
to come online in 14 months or less from the date of this report. The
Nation will have about 2.86 billion gallons of ethanol capacity available
in 2004. This number is reflected in the graphs and discussion below.
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The United States imports a small quantity of fuel ethanol as well. In
2001, 10.5 million gallons were imported from Canada, and 2.8 million
gallons were imported from Costa Rica. One reason for the low level of
imports is the tariff of $0.54 per gallon that applies to most imported
fuel ethanol to offset the gasoline excise tax exemption for ethanol-blended
gasoline.
EIA Study
Four MTBE/rewewable fuels policy cases were analyzed using the National
Energy Modeling System (NEMS).8
- The No State MTBE Ban case, which is the base case for this analysis,
assumes that the 17 States with pending MTBE bans do not implement their
bans, allowing the cost of the RFS to be evaluated from today’s
levels. The States are: Arizona, California, Colorado, Connecticut, Illinois,
Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri,
Nebraska, New York, Ohio, South Dakota, and Washington. Existing oxygenate
mandates continue in this case.
- The 17-State MTBE ban case assumes that the 17 States proceed
to phase out MTBE as planned. Existing oxygenate mandates continue in
this case.
- The RFS case adds the RFS on top of the State MTBE bans, but
not a Federal MTBE ban. Existing oxygenate mandates continue in this case.
- The 87-percent reduction MTBE reduction case assumes that H.R.
4 becomes law, but that Texas, which currently uses about 13 percent of
all MTBE blended in the United States, opts to continue using MTBE. This
assumption was drawn from an earlier study for Senators Murkowski and
Daschle.9 In this case, as in the bill, oxygenate mandates are repealed
and the RFS takes effect.
The results of interest are ethanol consumption and gasoline price effects.
Figure 1 shows the effects of the four sets of scenarios on ethanol consumption.
If the State MTBE bans are not implemented, ethanol consumption is projected
to remain approximately constant at 2.5 billion gallons per year. This
is above the level of the RFS for 2004. Although existing ethanol capacity
and capacity under construction have been added in anticipation of an
MTBE phaseout, producers will find it economic to sell ethanol for blending
into conventional gasoline as long as the ethanol blenders’ tax
credit remains in place. In the base case about 146,000 barrels per day
of ethanol are blended in 2006, but only 40,000 barrels per day of that
are blended into RFG.
The schedule set down by H.R. 4 requires 2.3 billion gallons of renewable
transportation fuel in 2004 and 2.6 billion gallons in 2005. These volumes
can be produced from existing ethanol plants and plants currently under
construction. Industry capacity for 2004 is expected to be 2.86 billion
gallons per year if all the plants under construction are completed on
schedule. The requirement for 2006 is 2.9 billion gallons. Assuming a
plant size of 40 million gallons annually, 1 new plant is needed to meet
the requirement in 2006. Another 8 plants must be added to produce the
3.2 billion gallons required for 2007. More severe MTBE reductions result
in ethanol consumption over and above the levels required by the RFS case
with only 17 States banning MTBE. Projected ethanol consumption under
the 87-percent MTBE reduction case is 3.496 billion gallons in 2006 and
3.565 billion gallons in 2007. The number of new plants necessary by 2006
under this scenario grows from 1 to 16. Then, 2 more are needed by 2007.
In the RFS case 173,000 barrels per day of ethanol are blended into gasoline
and of that, 120,000 barrels per day are blended into RFG in 2006. About
96 percent of ethanol is projected to be produced in the Midwest in that
year. In the 87-percent MTBE ban case, case 212,000 barrels per day of
ethanol are blended into gasoline and 183,000 barrels per day of that
are blended into RFG in 2006. In this case ethanol plant expansion occurs
primarily in the Midwest, with 97 percent of ethanol production projected
to occur in the Midwest in 2006.
Either scenario is technically feasible, as construction of an ethanol
plant is about a 2year process. However, construction and engineering
firms are facing significant demands for labor related to the 2004 reduction
of sulfur levels in gasoline and the 2006 reduction of sulfur levels in
diesel fuel. As a result, ethanol producers may find new plant construction
somewhat more costly than usual in 2006.
Figure 2 shows the gasoline price effects in the four cases. The baseline
for gasoline price comparisons is the case where no States implement MTBE
bans. The pending State MTBE bans are projected to increase average national
motor gasoline prices by 1.8 to 2.1 cents per gallon. The RFS has very
little additional effect. Further MTBE reductions in the 87-percent reduction
case increase gasoline prices to 2.7 cents per gallon in 2006 and 2.8
cents per gallon in 2007 over what would be expected without any MTBE
reduction.
When RFG prices are broken out from overall gasoline prices, a similar
pattern with greater projected cost impacts is observed (Figure 3). The
pending State MTBE bans have the largest impact on national average RFG
prices--3.5 to 3.6 cents per gallon. The RFS case results are again not
much different from the State MTBE ban results. The RFS and the 17 State
MTBE bans increase projected gasoline prices by at most 3.7 cents per
gallon over the no State MTBE ban case. The 87-percent reduction case
increases RFG prices by 7.0 cents over the case with no State MTBE bans.
An unintended consequence of the RFS might be an ethanol plant construction
boom leading to overcapacity and depressed prices. If would-be ethanol
plant builders expect low prices in the future, they may choose not to
enter the market. If everyone thinks and acts the same way, not enough
ethanol plants will be built, and a gap between the required quantity
and ethanol industry capacity could emerge. An ethanol industry consultancy
has indicated that banks financing ethanol plant construction could be
expected to refrain from lending on projects leading to possible oversupply.10 Firms wishing to begin or expand ethanol production can therefore expect
banks to discipline industry expansion.
Passage of the energy bill may not resolve all the demand-side uncertainties
in the ethanol market because the legislation leaves several issues unresolved.
In particular, since the legislation does not specify exactly how the
RFS volumes are to be shared among refiners, blenders, and importers,
and how the credit trading program will work, the regional demand for
ethanol cannot be projected with certainty. In addition, the legislation
allows States to petition for a waiver or reduction of the RFS, which
could reduce ethanol demand from what is projected here and could cause
uncertainties in the level of ethanol demanded in specific years.
Ethanol plant emissions have recently drawn the scrutiny of the Environmental
Protection Agency. Drying the distillers’ grains emits carbon monoxide
and volatile organic compounds, which may have negative health effects.
Some of the organic compounds also smell unpleasant, causing complaints
from residents near ethanol plants. The probable solution is thermal oxidation
of the exhaust from the grain dryer, which reacts the organic compounds
with oxygen to form water vapor and carbon dioxide.11 New ethanol producers
are expected to address these concerns up front by designing their plants
with thermal oxidizers.
The ethanol industry is expected to continue to concentrate in the Midwest
regions, where grain feedstocks are most plentiful.
Comparison to Previous Analysis of Energy Legislation
This work projects slightly smaller gasoline price impacts than EIA’s
prior analysis of S. 517 performed at the request of Senators Murkowski
and Daschle. The latter study projected an average gasoline price increase
of a little over 3 cents per gallon and an average RFG price increase
of a little under 8 cents per gallon under the RFS, an 87- percent MTBE
reduction, and waiver of the oxygenate requirement for RFG. Such a waiver
allows the RFS to be met by blending ethanol into conventional gasoline
rather than blending ethanol into RFG, which is more complicated. Since
the S. 517 study was completed, EIA obtained updated data on the ethanol
industry that show greater capacity, lower projected corn feedstock costs,
and lower production costs. This is the main reason for the slightly smaller
estimated gasoline price impacts (by about 0.4 cents per gallon for all
gasoline) of the RFS and MTBE reduction.
The S. 517 study also projected that the RFS would have a smaller impact
on ethanol consumption than the State MTBE bans in 2005. The S. 517 study
projected cellulose ethanol production of 133 million gallons per year
in 2005. Each gallon of cellulose ethanol is credited as 1.5 gallons of
renewable fuel under the RFS. But, cellulose ethanol technology has not
progressed as rapidly as expected. EIA now expects production of ethanol
from cellulose no earlier than 2010. Corn ethanol production must make
up the projected loss of 170 million gallons (with the 150-percent credit)
toward the RFS if it is enacted. As a result, the current analysis projects
a larger impact on corn ethanol use for the RFS than the State MTBE bans
in 2005.
Conclusion
The ethanol industry is expected to be able to supply the volumes of ethanol
required to phase out the use of MTBE and to meet a renewable motor fuels
requirement under consideration in Congress. The industry is expected
to have more than the capacity needed to meet the renewable fuels standard
in 2004 and 2005, since it has 461 million gallons of capacity under construction.
Anywhere from 9 to 18 new plants are needed to meet the RFS or an 87-percent
reduction in MTBE volume in 2007. But since ethanol plants only take about
2 years to build, timing will not be a problem in the scenarios analyzed
in this paper. It is important to note that ethanol plant construction
requires adequate lead time and a fairly certain projection of ethanol
demand. The additional volumes of ethanol projected in this analysis may
not be available without a renewable fuels requirement or MTBE regulation
enacted well in advance of the desired date of implementation.
In the absence of an RFS or nationwide MTBE ban, the industry can meet
the demand for ethanol in the 17 States that have banned MTBE without
adding a single plant beyond those currently being built. In the 87-percent
MTBE reduction case, RFG prices are expected to increase 7.0 cents per
gallon, and national average prices are expected to increase about 2.8
cents per gallon, compared to a case in which no States implement their
MTBE bans.
Contacts
Notes and Sources
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