Issues in Focus
Introduction
This section of the AEO provides in-depth discussions on topics of special
interest that may affect the projections, including significant changes
in assumptions and recent developments in technologies for energy production,
energy consumption, and energy supply. In view of recent increases in energy
prices, this year’s topics include discussions of the underlying cost factors
in key industries and how consumers respond to higher energy prices. The
potential impacts of developing oil and natural gas resources in the Outer
Continental Shelf (OCS), developments related to an Alaska natural gas
pipeline, and key issues for the development of new nuclear and biomass-to-liquids
technologies are also discussed.
World Oil Prices in AEO2007
Over the long term, the AEO2007 projection for world oil prices—defined
as the average price of imported low-sulfur, light crude oil to U.S. refiners—is
similar to the AEO2006 projection. In the near term, however, AEO2007 projects
prices that are $8 to $10 higher than those in AEO2006 [59].
The AEO2007 reference case remains optimistic about the long-term supply
potential of non-OPEC producers. In the reference case, increased non-OPEC
and OPEC supplies are expected to cause a price decline from 2006 levels
to under $50 per barrel (2005 dollars) in 2014. After that, a gradual rise
in oil prices, averaging 1.1 percent per year in constant dollar terms
or about 3.0 percent in nominal terms, is expected through 2030. The AEO2007
reference case world oil price in 2030 is $59 per barrel in 2005 dollars,
or about $95 per barrel in nominal terms.
Any long-term projection of world oil prices is highly uncertain. Above-ground
factors that contribute to price uncertainty include the extent of access
to oil resources, investment constraints, the economic and other objectives
of countries where major reserves and resources are located, the cost and
availability of substitutes, and economic and policy developments that
affect the demand for oil. Below-ground factors contributing to oil price
uncertainty include the extent of reserves and resources and the physical
and engineering challenges of producing oil.
The three world oil price paths in AEO2007 are shown in Figure 10. Compared
with the reference case, the world oil price in 2030 is 69 percent (about
$41 per barrel) higher in the high price case and 40 percent (about $23
per barrel) lower in the low price case. As a result, world oil consumption
in 2030 is 14 percent lower in the high price case and 9 percent higher
in the low price case than in the reference case. Prices in the low price
case decline from 2006 levels to $34 per barrel in 2016 and remain relatively
stable in real dollar terms thereafter, rising only slightly to $36 per
barrel in 2030. In the high price case, the world oil price dips somewhat
in 2007 from 2006 levels, then increases steadily to $101 per barrel (2005
dollars) in 2030. The AEO2007 high and low oil price cases illustrate alternative
oil market futures, but they do not bound the set of all possible outcomes.
The high and low oil price cases in AEO2007 are based on different assumptions
about world oil supply. The AEO2007 reference case uses the mean estimates
of oil and natural gas resources published by the U.S. Geological Survey
(USGS) [60]. The high price case assumes that the worldwide crude oil resource
is 15 percent smaller and is more costly to produce than assumed in the
reference case. The low price case assumes that the worldwide resource
is 15 percent larger and is cheaper to produce than assumed in the reference
case.
The AEO2007 reference case represents EIA’s current best judgment regarding
the expected behavior of key members of OPEC. In the reference case, OPEC
members increase production at a rate that keeps world oil prices in the
range of $50 to $60 per barrel (2005 dollars) over the projection period,
reflecting a view that allowing oil prices to remain above that level for
an extended period could lower their long-run profits by encouraging more
investment in non-OPEC conventional and unconventional supplies and discouraging
consumption of liquids worldwide.
The prices in the reference case are high enough to trigger the entry into
the market of some alternative energy supplies, including oil sands, ultra-heavy
oils, GTL, CTL, and biomass-to-liquids, which are expected to become economically
viable when oil prices are in the range of $30 to $50 per barrel. The same
price range also increases the likelihood of greater investment in unconventional
oil production.
Several non-OPEC countries, including Russia, Azerbaijan, Kazakhstan, Brazil,
and Canada, are expected to increase production over the projection period,
pursuing projects that are economically attractive with oil prices at or
somewhat below those in the reference case. In Russia, oil production has
recovered from a low of 6.0 million barrels per day in 1996, reaching 9.6 million
barrels per day in 2006 [61]. While the Russian government has sought to
increase its control of oil exploration, development, and production and
recent actions have resulted in a markedly less desirable climate for foreign
investment in Russian petroleum—a development that does not bode well for
higher levels of petroleum production in the future—higher world oil prices
have allowed the government to invest in additional exploration and production
(E&P), which suggests continued production growth. The recent investments
are projected to add 1 to 2 million barrels per day to Russia’s oil production
by 2030.
The Caspian Sea nations of Azerbaijan and Kazakhstan control large deposits
of oil and natural gas. Because the two countries are landlocked, however,
there was little incentive to develop their resources until pipelines began
to be built. With the opening of the BTC oil pipeline in 2006 between the
Caspian and Mediterranean Seas, production in Azerbaijan’s Caspian offshore
is expected to rise quickly, to 1.2 million barrels per day in 2010 [62].
Azerbaijan’s production already has begun to surge, rising by more than
40 percent from 2005 to 2006, with similar volume growth expected in 2007
[63]. Production is expected to decline slowly in the future, however,
to 1.0 million barrels per day in 2030.
Kazakhstan produced 1.4 million barrels per day in 2005 [64]. Recent access
to the BTC pipeline is expected to lower its total production and export
costs. The Kazakh government has stated goals of producing 3.5 million
barrels per day by 2015. Kazakhstan’s geology and economics might support
that production level; however, uncertainties with regard to regulatory
and tax policy could slow the rate of production growth. In addition, its
success in reaching the stated target depends on access to export pipelines
and adequate investment. In the AEO2007 reference case, Kazakhstan’s production
is projected to reach 3.3 million barrels per day in 2030.
Brazil produced 1.7 million barrels per day of crude oil in 2006. Its production
is expected to continue growing, based on proven reserves of more than
11 billion barrels, clear government policy objectives to increase production,
and an increasingly competitive production market following the 1999 reforms
that began to allow foreign oil companies to compete with the national
oil company, Petrobras [65]. More than one-half of the country’s oil reserves
are in deepwater fields, and Brazil has long been a leader in developing
deepwater production technology. Total liquids production from Brazil is
projected to reach 4.6 million barrels per day in 2030.
Canada’s conventional oil production is projected to remain relatively
constant at 2.0 million barrels per day through 2015, but oil sands production
is projected to grow rapidly. In recent years, net growth in production
from Canada’s oil sands has averaged 150,000 barrels per day [66], and
production is projected to reach 2.3 million barrels per day in 2015 and
3.7 million barrels per day in 2030.
The production outlook for the countries highlighted here informs the three
EIA world oil price cases. Sustained higher oil prices support the development
and production of oil from more remote, technically challenging, and unconventional
resources. Oil prices are significantly affected by assumptions about the
ultimate size of world resources. Smaller resource estimates strengthen
OPEC producers’ influence over prices and raise their profits; however,
the resulting higher prices encourage more extensive development of non-OPEC
oil supplies, limiting the extent of OPEC’s influence on prices. Oil production
around the world over the next 25 years will also depend on the stability
of government regulations and tax policies, access to export pipelines
and ships, and adequate investment.
The projections for world petroleum production in 2030 are 101.6, 117.3,
and 128.1 million barrels per day in the AEO2007 high price, reference,
and low price cases. The projected market share of world petroleum liquids
production from OPEC in 2030 is about 33 percent in the high price case,
41 percent in the reference case, and 43 percent in the low price case.
Because assumed production costs rise from the low price case to the reference
case to the high price case, the differences in net profits among the three
cases are smaller than they might have been if the underlying supply curves
for OPEC and non-OPEC producers had remained unchanged. In the absence
of tighter resources and higher costs, an OPEC strategy that attempted
to pursue the output path in the high price case would subject OPEC to
the risk of losing market share to other producers, as well as to alternatives
to oil. The AEO2007 projections for world oil production are shown in Table
3. Further discussions of the three world oil price cases and their implications
for energy markets appear in the “Market Trends” section.
Impacts of Rising Construction and Equipment Costs on Energy Industries
Costs related to the construction industry have been volatile in recent
years. Some of the volatility may be related to higher energy prices. Prices
for iron and steel, cement, and concrete—commodities used heavily in the
construction of new energy projects— rose sharply from 2004 to 2006, and
shortages have been reported. How such price fluctuations may affect the
cost or pace of new development in the energy industries is not known with
any certainty, and short-term changes in commodity prices are not accounted
for in the 25-year projections in AEO2007. Most projects in the energy
industries require long planning and construction lead times, which can
lessen the impacts of short-term trends.
From the late 1970s through 2002, steel, cement, and concrete prices followed
a general downward trend. Since then, however, iron and steel prices have
increased by 9 percent from 2002 to 2003, 9 percent from 2003 to 2004,
and 31 percent from 2004 to 2005. (Early data from 2006 indicate that iron
and steel prices have started to decline, but the direction of future prices
remains to be seen.) Cement and concrete prices, as well as the composite
cost index for all construction commodities, have shown similar trends,
although with smaller increases, from 2004 to 2005 and 2005 to 2006 (Figure
11).
The cost index for construction materials has shown an average annual increase
of 7 percent over the past 3 years in real terms. Over the past 30 years,
however, it has shown an average annual decrease of 0.5 percent, with decreases
following periods of increases in the early 1970s and early 1990s. AEO2007
assumes that, for the purposes of long-term planning in the energy industries,
costs will revert to the stable or slightly declining trend of the past
30 years.
Oil and Natural Gas Industry
Exploration and Production Costs
The American Petroleum Institute publishes an annual survey, Joint Association
Survey of Drilling Costs [67], which reports the cost of drilling oil and
natural gas wells in the United States. As shown in Figure 12, the average
real cost of drilling an onshore natural gas development well to a depth
of 7,500 to 9,999 feet roughly doubled from 2003 to 2004 [68].
Offshore drilling costs largely reflect the cost of renting an offshore
drilling rig. ODS-Petrodata, Inc., has reported that, in real dollar terms
from August 2004 to August 2006, daily rental costs for offshore jack-up
rigs drilling at water depths of 250 to 300 feet increased by about 225
percent, while fleet utilization increased from about 80 percent to 89
percent; for semisubmersible rigs drilling at water depths of 2,001 to
5,000 feet, daily rental costs increased by approximately 340 percent,
while fleet utilization increased from about 80 percent to just under 100
percent; and for floating rigs drilling at water depths of 5,001 feet or
more, daily rental costs increased by approximately 266 percent, while
fleet utilization increased from about 88 percent to 100 percent [69].
Petroleum Refinery Costs
Oil & Gas Journal uses Nelson-Farrar refinery construction cost indexes
to track the overall cost of refinery construction. According to the Nelson-Farrar
indexes, refinery construction costs increased overall by about 17 percent
from 2002 to 2005 in real dollar terms. The escalation rate associated
with petroleum refinery construction is lower than the rate for oil and
natural gas drilling, because refinery costs in some categories have either
declined or increased only slightly. Specifically, from 2002 to 2005, the
following escalation rates for refinery construction were reported by Oil
& Gas Journal: refinery composite index, 9 percent; pumps and compressors,
3 percent; electrical machinery, -10 percent; internal combustion engines,
-5 percent; instruments, -3 percent; heat exchangers, 36 percent; materials,
22 percent; and construction labor, 5 percent [70].
In the aggregate, the large increases for heat exchangers and materials
were largely offset by smaller increases or decreases for the other categories.
More importantly, the 5-percent increase in labor costs is largely responsible
for keeping the overall cost increase low, because labor costs account
for about 60 percent of the overall cost of refinery construction.
Discussion
Although the cost of steel and other commodities used in the oil and natural
gas industry have posted significant cost increases over the past few years,
the escalation of industry costs has not been caused by commodity cost
increases alone, but also by higher crude oil and natural gas prices and
the resulting increase in demand for exploration services (contract drilling,
seismic data collection, well logging, fracturing, etc.). While iron and
steel prices increased by 72 percent from May 2002 to June 2006 [71], onshore
drilling costs increased by 100 percent and rental rates for offshore drilling
rigs by 200 percent or more.
The growth in demand for services has occurred primarily in the E&P segment
of the industry rather than refining sector. Higher crude oil and natural
gas prices increase both producer cash flows and rates of return; greater
potential profitability provides producers with the incentive to invest
in and produce more oil and natural gas; and increased cash flow gives
them more money to invest in more projects.
The increase in demand for services in the oil and natural gas industry
is best illustrated by offshore drilling rig rates and fleet utilization.
Similarly, the increase in demand for onshore drilling services is best
illustrated by the growth in the number of onshore drilling rigs operating.
Baker-Hughes, Inc., has reported that 1,656 onshore drilling rigs were
in operation at the end of August 2006, compared with 738 at the end of
August 2002 [72].
The refining sector has not experienced the same degree of cost escalation,
largely because there has not been a significant increase in U.S. refining
construction activity over the past few years. Consequently, cost increases
in the petroleum refining sector largely mirror the increases associated
with the various commodities used in refineries (steel, nickel, cobalt,
etc.) rather than a significant increase in demand for refinery services
and equipment.
Future cost changes in the E&P and refinery sectors of the oil and natural
gas industry are expected to follow different patterns. Over the long term,
new service capacity will be added to meet demand in the E&P sector; and
if oil and natural gas prices stabilize, the demand—and consequently prices—for
E&P services will decline. Conversely, if oil and natural gas prices increase
in the future, it will take longer for E&P service capacity to catch up
with the increased level of demand. In the refinery sector, construction
costs are more likely to follow the path of construction commodity costs,
barring a significant surge or reduction in demand for refinery equipment
and construction services.
In NEMS, the real-world interaction between escalating petroleum E&P costs
and the supply and demand for E&P services is captured in two ways. First,
as oil and natural gas prices rise, E&P activities, such as the number
of wells drilled, also increase. The increase in E&P activity, in turn,
causes the cost of E&P activities to increase in the NEMS projections.
Second, changes in E&P costs are addressed through annual econometric reestimations
of equations related to oil and natural gas supply activities. The annual
reestimations capture the latest trends in E&P costs and their impacts
on E&P activity levels and outcomes. For example, for the AEO2007 projections,
the reestimations capture all the cost increases and outcomes for E&P activity
that occurred through December 31, 2004. With regard to petroleum refining,
the recent cost escalation for refining equipment resulting from higher
commodity prices (including steel and concrete) is considered to be temporary
and self-correcting over the long term, both through the addition of new
commodity supplies and through a reduction in demand for those commodities.
As a result, equipment costs for the petroleum refining sector are expected
to rise at the overall rate of inflation over the long term.
Coal Industry
In the coal industry, both the mining and transportation sectors have been
susceptible to the volatility of steel prices over the past few years.
Higher prices for steel can make investments in machinery and equipment
for coal mining more expensive; and coal transportation—predominantly by
rail—depends on investments in freight cars, locomotives, and track, all
of which require steel as a raw material.
The costs of rail equipment and, to a lesser extent, mining equipment and
machinery followed the general pattern of declining steel prices from the
mid-1970s through 2001 and 2002 (Figure 13). Although steel prices began
to rise in 2003, rail equipment and mining machinery and equipment prices
did not begin rising until 2005 and 2006, respectively. Although the early
2006 data suggest that steel prices have started to decline, there is no
evidence yet of a decline in the equipment prices.
Coal Mining
The U.S. Census Bureau, in its Current Industrial Reports, combines surface
mining equipment with construction machinery. In the construction machinery
category, some subcategories provide better indicators than others of the
price changes that have affected the surface mining industry. For example,
the subcategory that includes draglines, excavators, and mining equipment
has increased by 26 percent (average value in constant dollars) since 2002,
while the number of units shipped has increased by 10 percent (Table 4).
A smaller subcategory that includes draglines has increased by 33 percent
in average value since 2002, with a 59-percent increase in quantity shipped.
Larger hydraulically operated excavators show a different pattern, with
a 10-percent decline in average value and a 57-percent increase in quantity
shipped over the same time period, as does the subcategory that includes
coal haulers, which did not show a significant increase in value between
2004 and 2005. For the subcategories with increases in average value, the
largest increases occurred in 2004, coinciding with higher steel prices.
Both surface and underground mines rely on machinery made largely from
steel to produce coal efficiently. Although specific costs typically are
not publicly available, many of the major mining companies, including Peabody,
CONSOL, and Massey, have indicated in their annual reports that they are
susceptible to higher costs for machinery purchases as a result of increases
in the cost of steel. Census Bureau data indicate that the mining industry
as a whole (including coal mining) spent $597 million on underground mining
machinery in 2005, as compared with $393 million in 2004 (constant 2005
dollars) [73]. In addition to higher steel costs, the increase may also
be due in part to the amount or mix of mining machinery purchased and in
part to increases in other manufacturing costs.
Peabody listed the value of its mining and machinery assets at $1.2 billion
in 2005, up from $910 million in 2004 and $759 million in 2003 (2005 dollars)
[74]. The more recent annual increase, from 2004 to 2005, is larger than
the earlier one, but the portion attributable to the effect of higher steel
prices on the cost of newly acquired equipment is not publicly known. The
company’s operating costs, in constant dollars, rose by 8.4 percent from
2003 to 2005, from $11.23 per ton to $12.17 per ton of coal produced [75].
CONSOL cited both higher labor costs and higher commodity prices as the
reasons for a 5.9-percent real increase in operating costs (to $30.06 per
ton) in 2005 compared with 2004 [76]. For Massey, the average cash cost
per ton of coal has risen to $35.62 per ton in 2005 from $26.58 per ton
in 2001 (2005 dollars) [77].
Joy Global, a manufacturer of mining machinery [78], has mentioned in its
annual report that some customers have delayed orders for manufacturing
equipment in response to the short-term price volatility for steel and
steel parts and that steel availability, in addition to prices, has been
a problem in recent years. In general, the company has long-term contracts
with steel suppliers, which help maintain steel availability, but those
contracts also have surcharge provisions for increases in raw material
costs. Caterpillar, Inc., another mining equipment manufacturer, has also
been paying surcharges for steel.
As of February 2005, some steel prices paid by Joy Global were 100 percent
higher than they had been 15 months earlier [79]. The company appears to
have been able to pass through the higher steel prices to its customers
(including coal producers), increasing its overall gross profit margins
from 2004 to 2005.
Although the coal mining sector is hurt by higher costs for steel as an
input factor in the production process, higher demand for steel and steel
products also helps to boost metallurgical coal prices. Some coal companies
are paying more for steel-based equipment, but at the same time their profit
margins may be protected by their ability to sell their coal at higher
prices.
The cost increases for coal mining equipment that occurred in 2006 are
included in the AEO2007 reference case. Thereafter, mine equipment costs
are assumed to return to the long-term trend, increasing at the general
rate of inflation.
Coal Transportation
Railroads are the primary mode for coal transportation in the United States,
carrying about two-thirds of all coal shipments. The railroads use both
steel and concrete to keep pace with the increased traffic demands placed
on their network. (Concrete is used to provide a foundation for rail beds
and, increasingly, is being used to make ties for tracks that carry heavier
loads.) Consistent with the recent increase in steel prices, BNSF Railway
Company, one of the largest coal haulers in the United States, has cited
a $70 million increase in material costs associated with locomotive, freight
car, and track structure in 2005 [80]. Freight cars and locomotive orders
and new track installation often represent long-term decisions by railroads.
BNSF, for instance, has contracted to take delivery of 845 locomotives
by 2009. As of 2005, it had acquired 405 of the total [81]. Depending on
the terms of those contracts, BNSF may or may not be susceptible to variation
in steel prices.
For new freight car acquisitions, aluminum cars, lighter than steel cars
and thus capable of carrying larger volumes of coal, tend to be preferred.
The construction of aluminum cars still depends on some steel components,
however, because more than 50 percent of the weight of a 42,000-pound aluminum
car is made up of steel [82].
In 2005, more than 40,000 new freight cars of all types were acquired,
representing an investment of roughly $3 billion. Some industry experts
project that an additional 40,000 new freight cars per year is the minimum
level that will be required to replace retired cars and maintain current
capacity [83]. The average cost of all freight cars, including coal cars,
ordered from Freight Car America was $68,000 both in 2004 and in 2005,
as compared with $60,000 in 2003 (2005 dollars) [84]. In addition to reflecting
the increase in steel prices in 2004 and 2005, the averages may vary according
to the mix of cars delivered; however, 93 percent of the cars sold by Freight
Car America in 2005 are used for coal transportation. Freight Car America
has also indicated in its annual report that raw steel prices increased
by 155 percent from October 2003 to December 2005, and that the company
has successfully passed the increase on to purchasers for 96 percent of
its car deliveries [85].
The railroads have already added a record number of locomotives to their
fleets in recent years. In 2004, Class I railroads purchased or leased 1,121
new locomotives—91 percent more than in 2003 and 21 percent more than the
previous high since 1988. In 2005, Norfolk Southern (NS) added 102 locomotives
to its fleet, bringing its total to 4,000. In the same year, Union Pacific
(UP) had plans to add 315 new locomotives. In 2004, Kansas City Southern
ordered 30 new locomotives that were capable of transporting 9.6 percent
more 110-ton cars than the rest of its existing fleet [86]. In 2006, BNSF
has plans to add 310 locomotives to its fleet, at an estimated cost of
$550 million [87]. Each new piece of equipment can have a much larger marginal
impact on a railroad’s capacity than its older existing equipment. Over
time, the added economic benefit of more efficient equipment capable of
moving heavier, longer train sets is likely to outweigh the recent increase
in steel costs.
Finally, with increasingly heavy loads of coal being moved, the repair
and maintenance cycle for existing railroad infrastructure becomes shorter,
and the maintenance is more likely to be affected by short-term volatility
in steel (and labor) prices. In 2004, for example, the seven Class I railroads
spent $403 million (constant 2005 dollars) on rail and other materials
for repair and maintenance of existing track [88]. In addition, over the
next few years, the major railroads have plans to expand their network
by adding multiple track systems and sidings. New track must be laid to
handle higher freight volumes, and with heavier loads, more steel will
be needed. For instance, track weighing 131 pounds per yard might be needed,
as compared with 90 to 110 pounds per yard for less heavily used track.
BNSF laid 749, 695, and 711 miles of track in 2003, 2004, and 2005, and
an additional 884 miles is planned for 2006 [89].
The AEO2007 reference case assumes that railroad equipment costs will rise
in real terms through 2009, then return to their long-term declining trend.
Electric Power Industry
The Handy-Whitman index for electric utility construction provides an average
cost index for six regions in the United States, starting from 1973. A simple
average of the regional indexes for construction of electricity generation
plants is used in Figure 14 to show a national cost trend relative to the cost index
for construction materials. Because equipment and materials generally represent
two-thirds to three-quarters of total power plant construction costs, it
is not surprising that the trends are similar.
The long-term trend for construction costs in the electric power industry
shows declining costs from 1975 to around 2000, after which it is relatively
flat in real terms. The two indexes diverge in the early 2000s, with electric
power construction costs showing a flat to slightly increasing trend, while
general construction costs continue to decline. The difference coincides
with a construction boom in the electric power sector from 2000 to 2004,
when annual capacity additions averaged 38 gigawatts per year—well above
previous build patterns (Figure 15). Over those years there were shortages
and price increases specific to construction in the electric power industry
due to the pace of building. For the past 3 years, the Handy-Whitman index
shows an average annual increase of 5 percent, slightly less than that for
the overall construction cost index.
Currently, new construction in the electric power sector is slowing down,
with generating capacity additions averaging 16 gigawatts per year from
2004 to 2006. The slowdown is more likely a response to the oversupply
of available capacity than a response to higher commodity prices. It is
typical for investment in the power industry to cycle through patterns
of increased building and slower growth, responding to changes in the expectations
for future demand and fuel prices, as well as changes in the industry,
such as restructuring.
AEO2007 does not project significant increases in new generating capacity
in the electric power sector until after 2015. A total of 258 gigawatts
of new capacity is expected between 2006 and 2030, representing a total
investment of approximately $412 billion (2005 dollars). If construction
costs were 5 to 10 percent higher than assumed in the reference case, the
total investment over the period could increase by $21 billion to $41 billion.
Energy Demand: Limits on the Response to Higher Energy Prices in the End-Use
Sectors
Energy consumption in the end-use demand sectors—residential, commercial,
industrial, and transportation—generally shows only limited change when
energy prices increase. Several factors that limit the sensitivity of end-use
energy demand to price signals are common across the end-use sectors. For
example, because energy generally is consumed in long-lived capital equipment,
short-run consumer responses to changes in energy prices are limited to
reductions in the use of energy services or, in a few cases, fuel switching;
and because energy services affect such critical lifestyle areas as personal
comfort, medical services, and travel, end-use consumers often are willing
to absorb price increases rather than cut back on energy use, especially
when they are uncertain whether price increases will be long-lasting. Manufacturers,
on the other hand, often are able to pass along higher energy costs, especially
in cases where energy inputs are a relatively minor component of production
costs. In economic terms, short-run energy demand typically is inelastic,
and long-run energy demand is less inelastic or moderately elastic at best
[90].
Beyond the short-run inelasticity of demand in the end-use sectors, several
factors make the long-run demand response to changes in energy prices relatively
modest, including:
- Infrastructure—such as the network of roads, rails, and airports—that is
unlikely to be substantially altered even in the long term
- General lack of fuel-switching capability in capital equipment
- Unattractive attributes of some energy-saving equipment, such as differences
in quality or comfort and high cost
- Structural features of energy markets—including builder/owner versus buyer/renter
incentives; incomplete information on energy-using equipment, such as consumption
levels and potential savings; and inadequate price signals to consumers,
resulting from rate design or other issues [91]
Uncertainty with regard to the value of potential energy savings and the
opportunity costs of technology choices for long-lived equipment.
Buildings Sector
In the buildings sector, which includes residential and commercial end
uses, building structures are long-lived assets that affect energy consumption
through their overall design and “shell integrity” against unwanted heat
transfers in or out of the building. A typical building may remain in the
stock for 75 years. Beyond the structure itself, the energy-consuming equipment
in a building typically lasts from 10 to 30 years. As a result, adjustments
to the stock of buildings and equipment take many years, even if energy
prices change dramatically. Because most previous disruptions in energy
prices have been transitory, there is little evidence to indicate how quickly
and how much the buildings sector could respond to a decades-long trend
of increasing energy prices.
Limited capability for fuel switching is the rule rather than exception
for equipment in buildings. In the residential sector, consumers have some
limited choices between electricity and other fuels for a given energy
service. For example, the thermostat on a natural gas water heater can
be adjusted to reduce the use of the electric heating element in a clothes
washer or dishwasher. In the commercial sector, some boilers have true
dual-fuel capability; however, fuel-switching opportunities are available
for only 3 percent of commercial buildings, accounting for 16 percent of
total commercial floorspace, which use both oil and natural gas as fuel
sources [92].
In some cases, energy services provided by more efficient equipment may
be less desirable, and consumers may be slow to adopt the more efficient
option when energy prices are high. For example, early versions of compact
fluorescent lights (CFLs) had several quality issues, including bulky sizes
that did not fit standard fixtures, poor light quality (flickering, poor
color rendering, low light levels), and premature failures that caused
life-cycle energy savings to be less than advertised [93]. Today’s CFLs
typically perform much better than the early models, and they are much
less expensive. Even with those gains, however, some of their features
remain less desirable than those of incandescent lights. CFLs typically
have a warmup period, requiring several seconds to reach full output, and
they cannot be dimmed. Other examples include lower outlet air temperatures
for heat pumps than for other heating equipment and slower recovery times
for heat pump water heaters.
Structural features of energy markets also contribute to the limited demand
response. For example, investment decisions often are made by home builders,
landlords, and property managers rather than the energy service consumers.
In such cases, the decisionmakers may prefer to purchase and install less
costly, less efficient equipment, because they will not pay the future
energy bills. Builders may choose less efficient equipment or offer fewer
options to buyers in order to reduce design costs and increase profitability,
even though consumers might be willing to pay higher home purchase prices
or higher rents if they could lower their energy bills over the long term.
A related issue arises from the inability of most consumers to evaluate
the tradeoffs between capital cost and efficiency. Green building rating
systems, such as the EPA’s ENERGY STAR and DOE’s Building America, do attempt
to provide reliable information on the energy efficiency of buildings and
potential energy savings [94].
In addition, because building equipment generally is expected to last for
more than 10 years, many tenants will move before their cumulative energy
savings can make up for the added expense of installing energy-efficient
equipment. Residential homeowners on average stay in the same house for
only 8 years [95], and while the value of potential energy savings might
be expected to increase the sale price of a house, there are no guarantees
(although there is some evidence that energy efficiency investments are
capitalized in a home’s market value) [96].
Replacement of equipment before failure is uncommon in buildings, especially
in the residential sector. An example often cited is replacement of water
heaters. Typically, a consumer waits until the water heater completely
fails before replacing it. Because the failure creates considerable inconvenience,
the consumer is likely to buy a new water heater as quickly as possible,
without comparing price and efficiency tradeoffs before making a purchase
decision. In the commercial sector, an exception is lighting retrofits,
which often are made before the existing equipment wears out.
The potential for disruption of operations during equipment replacement
can also affect decisions by purchasers, especially in the commercial sector,
where energy costs are only a small fraction of business expenses for a
typical commercial establishment. Efficiency investments may not be seen
as cost-effective if the cost of the disruption outweighs potential savings,
as is often the case with retrofits to improve the efficiency of building
shells.
Demand response can also be attenuated by price signals that are incomplete
or do not represent marginal costs. For example, because residential renters
often pay electric bills but not natural gas bills, they may see the costs
of air conditioning (electric) but not heating (natural gas, except for
the electricity that powers the fan in a forced-air furnace). In commercial
buildings, energy consumption choices (turning off computers or lights,
for example) often are made by office workers who see no cost implications.
Residential consumers, who typically see only monthly electric bills based
on average costs, have no incentive to reduce their use of air conditioning
on peak days. Under nonseasonal time-of-use rates, they would pay the higher
marginal cost; but nonseasonal time-of-use rates currently are available
in only about 5 percent of the residential market. For commercial customers,
who tend to be larger consumers of electricity, the additional cost of
more sophisticated demand metering or nonseasonal time-of-use metering
is less significant, and their rates more often approximate the marginal
cost of the electricity they use.
Industrial Sector
The industrial sector is more responsive to price changes for all inputs;
however, the speed at which operational changes can be introduced to mitigate
the cost impacts of rising energy prices is limited. Limitations arise
from the fuel mix required by the existing capital stock (for example,
it is not feasible in general to operate a natural-gas-fired boiler using
coal), slow stock turnover, and falling capital investment rates. In addition,
a strategy to reduce the demand for energy services by reducing production
rates could prove to be more costly than the value of the energy savings
if the reduction in output increased the probability of losing market share,
reduced overall profitability, or led to contractual penalties.
Over a longer period, existing equipment could be scrapped and replaced
with new equipment that uses different fuels or uses the same fuel more
efficiently. The investments required to implement such changes would,
however, compete with other uses of the funds available. Given the inherent
uncertainty of energy prices, firms may be less than eager to invest in
such measures as alternate fuel capability. Because most energy prices
rise and fall together, dual-fuel investments may not be expected to have
attractive paybacks. If high energy prices were sustained, however, companies
might find previously neglected opportunities to reduce energy losses resulting
from poor maintenance or other housekeeping items. Further, firms might
find low-cost or no-cost options for reducing energy expenditures while
maintaining the same level of energy services [97]. Successful examples
include motor system optimization and steam line insulation, with implementation
costs recovered in less than 1 year [98].
Energy costs account for only 2.8 percent of annual operating costs for
U.S. manufacturing [99]. As a result, energy-saving investments may be
less important than other factor-saving investments. Indeed, if energy
prices rose substantially, corporate cash flow and the financial capital
available for such investments could be reduced.
According to EIA’s 2002 Manufacturing Energy Consumption Survey (MECS),
more than 90 percent of petroleum consumption in the manufacturing sector
is in the form of feedstocks [100]. In 2002, the sector’s petroleum consumption
for energy totaled only 450 trillion Btu, of which 140 trillion Btu was
reported as switchable. Consumption of natural gas in the manufacturing
sector totaled 6.5 quadrillion Btu in 2002, about 10 percent of which was
used for feedstock. The 2002 MECS data indicate that 18 percent of the
natural gas used for energy could be switched to another fuel, primarily
petroleum. If all such switching did take place, the sector’s petroleum
consumption for energy would more than triple, increasing by 1 quadrillion
Btu.
In summary, the manufacturing sector does respond to higher factor input
prices, including energy prices, but energy expenditures do not constitute
a large portion of most manufacturers’ operating costs. Over time, however,
the overall energy intensity of manufacturing does tend to decline in response
to higher energy prices [101].
Transportation Sector
In the transportation sector, when consumers seek out energy-saving products
and other cost-effective ways to service their travel needs, the energy
cost savings are weighed against the perceived value of other factors considered
in the decisionmaking process. Those factors include—but are not limited
to—mobility, safety, comfort, quality, reliability, emissions, and capital
cost.
The transportation sector is served primarily by four modes of travel:
highway, air, rail, and water. Most of the energy consumed in the transportation
sector is for highway vehicle travel, which accounts for approximately
85 percent of total consumption, followed by air (9 percent) and rail and
water (6 percent combined). Energy consumption in the transportation sector
consists almost exclusively (98 percent) of petroleum fuels. Thus, when
there are appreciable increases in fuel prices, opportunities for reducing
fuel expenditures through fuel switching are limited. As a result, savings
can be realized only through reductions in travel demand, mode switching,
improvements in system efficiency, and/or improvements in vehicle fuel
efficiency.
The amount of efficiency improvement that could potentially be achieved
varies greatly across modes and is limited by infrastructure constraints,
vehicle lifetime and use patterns, and vehicle design criteria. For example,
rail is a very energy-efficient way to move freight, about 11.5 times more
energy-efficient on a Btu per ton-mile basis than heavy trucks. Opportunities
for efficiency improvement in the rail mode are minimal, limited primarily
to increases in system efficiency through higher equipment utilization
and more efficient equipment operation—for example, by using unit and shuttle
trains and by reducing locomotive idling. Limits are imposed by very long
equipment lives, available infrastructure, and vehicle duty cycles. Similarly,
waterborne travel is very efficient, and opportunities for energy savings
are limited to improvements in system efficiency.
Air travel is serviced by a very competitive industry with significant
investments in long-lived capital stock that operates in a constrained
infrastructure. Immediate improvements in fuel efficiency can be gained
through increased utilization of available infrastructure and increased
load factors (ratio of passengers to available seats), but the desire of
each company to maintain or increase market share limits opportunities
for market players to act.
Long-term efficiency gains in air travel are realized through the adoption
of technologies that improve either infrastructure efficiency (increased
aircraft throughput at gates) or aircraft fuel efficiency (improved engine
efficiency and lightweight materials); however, efficiency losses that
result from changes in market structure to meet continued demand for increased
flight availability and convenience generally cancel out efficiency gains.
For example, the amount of air travel serviced by regional jets, which
are about 40 percent less efficient than narrow-body jets, continues to
increase as consumers look for improved destination and flight availability.
As the share of the market served by regional jets increases, the overall
fuel efficiency of the active aircraft stock is reduced, regardless of
gains in the efficiency of larger aircraft.
Unlike the other transportation modes, highway vehicles have a relatively
short life. The average age of the existing passenger car fleet is 9 years,
and the average age of trucks (light and heavy) is 8 years, reflecting,
in part, the shift toward light trucks for personal transportation over
the past decade. In addition, the car stock turns over at a rate of about
6 percent per year. Heavy truck stocks turn over at a much slower rate,
approximately 4 percent per year. Those slow stock replacement rates, coupled
with consumer attitudes toward fuel economy improvement relative to other,
more highly desired vehicle attributes, make it difficult to realize short-term
increases in fuel economy for the vehicle stock as a whole.
Further limiting increases in vehicle fuel economy is the scarcity of cost-effective
alternatives within the vehicle categories preferred by consumers. Whether
the consumer rates the desirability of a vehicle purchase by quality, safety,
seating capacity, storage capacity, towing capacity, luxury, or performance,
once the criteria are established they limit the vehicle types considered.
For example, someone shopping for a van or sport utility vehicle is unlikely
to view a compact as a viable alternative.
In addition to efficiency improvements made within a mode, transportation
efficiency can be improved by switching to more efficient modes of travel.
For example, passenger and freight travel can be served by a variety of
travel modes (highway, air, and rail), with mode selection determined by
cost of service, access, convenience, mobility afforded, and time budgets.
When energy prices increase, consumers seeking reductions in travel costs
examine the expected savings associated with alternative mode choices in
relation to the values placed on other considerations. For most consumers,
alternative mode choices are limited, providing little opportunity for
cost reductions. For others, the cost savings that would result from the
choice of an alternative mode of travel are likely to be outweighed by
the value placed on travel time, convenience, and mobility.
Miscellaneous Electricity Services in the Buildings Sector
Residential and commercial electricity consumption for miscellaneous services
has grown significantly in recent years and currently accounts for more
electricity use than any single major end-use service in either sector
(including space heating, space cooling, water heating, and lighting).
In the residential sector, a proliferation of consumer electronics and
information technology equipment has driven much of the growth. In the
commercial sector, telecommunications and network equipment and new advances
in medical imaging have contributed to recent growth in miscellaneous electricity
use [102].
Until recently, energy consumption for most miscellaneous electricity uses
has not been well quantified. A September 2006 report prepared for EIA
by TIAX LLC [103] provides much-needed information about many miscellaneous
electricity services. For the report, TIAX developed estimates of current
and future electricity consumption for the 10 largest miscellaneous electricity
loads in the residential sector and for 10 key contributors to miscellaneous
electricity use in the commercial sector, based on current usage and technology
trends. The information has allowed EIA to disaggregate components of the
“other” electricity consumption category and refine the AEO2007 projections
for the buildings sector. Based on the conclusions of the TIAX study, which
allows a finer breakout of smaller electric uses in the buildings sector,
the projected growth rate for miscellaneous electricity use in the AEO2007
reference case is lower than was projected in the AEO2006 reference case.
Residential Sector
The 10 miscellaneous electricity uses evaluated by TIAX account for about
40 percent of the comparable miscellaneous electricity use in 2005 (11
percent of total residential electricity use). Televisions (TVs), which
were accounted for separately in previous AEOs, account for one-third of
residential miscellaneous electricity use in 2005 in the TIAX study, and
TVs and set-top boxes are projected to account for 80 percent of the growth
in electricity use for the 10 miscellaneous loads from 2005 to 2030. It
should be noted that considerable uncertainty surrounds the projections,
in that technological change and innovation, as well as consumer preferences,
can lead to rapid changes in the market for these products. Table 5 summarizes
electricity use in 2005, 2015, and 2030 for the 10 residential loads included
in the study.
As shown in Table 5, electricity use for TVs and set-top boxes nearly doubles
from 2005 to 2030. This projection is based on factors such as number of
TVs per house, screen size, technology type, satellite/cable penetration,
and the transition away from analog to digital broadcasts. For most TVs
in the current stock, the transition to digital broadcasts will require
a set-top box to decode the signal, as reflected in the sharp increase
of electricity use for set-top boxes from 2005 to 2015. After 2015, when
newer TVs are expected to have the decoder built in, the rate of increase
slows. Continued penetration of satellite and cable systems, as well as
multi-function digital video recorders (DVRs) contributes to the increase
in set-top boxes over the projection period.
There are many uncertainties that could affect future growth in electricity
use for TVs. Although it is certain that screen sizes have increased over
time in the past, and likely that they will continue to increase, it is
far less certain which technology will come to dominate the market. Plasma,
liquid crystal display, and digital light processing screen technologies
all have footholds in the current market for TVs, and they vary in electricity
use. Moreover, future technologies, such as carbon nanotube displays, may
use significantly less power than today’s technologies, and TVs with point-of-deployment
slots could make set-top boxes obsolete.
The projections in Table 5 assume that all TVs will meet the current ENERGY
STAR requirements for off power (less than 1 watt); however, overall electricity
use for TVs is largely insensitive to that assumption, because hours of
use and screen size predominantly determine their electricity use. As shown
in Table 6, bigger TVs with high-definition screens that require more energy
per unit are projected to double in market share from 2005 to 2015, resulting
in a 24-percent increase in active power draw per set, on average.
The eight other devices listed in Table 5 contribute little (about 20 percent)
to the projected growth in total miscellaneous electricity use for the
residential sector. Their functions are diverse, ranging from common appliances
(microwave ovens) to less common products (spas). Their annual electricity
consumption also varies widely, from 74 kilowatthours per year for security
systems to more than 2,500 kilowatthours per year for spas.
Of the eight other devices, electricity use for ceiling fans (not including
attached lights) is projected to increase the most through 2030, as newly
constructed homes tend to have more ceiling fans installed, and more new
homes are built in warmer areas where ceiling fans are used more intensively.
Microwave ovens show a slight increase in household saturation, from 96
percent in 2005 to 98 percent in 2030, but energy use will grow faster
as the number of households increases. For spas, electricity use per unit
is expected to decrease as efficiency standards tighten [104], but more
units are expected to be installed, leading to an overall increase in electricity
consumption. Hand-held rechargeable devices (mobile phones, cordless phones,
hand-held power tools, and others) also are projected to use less electricity
per unit, again, in response to tighter efficiency standards.
Commercial Sector
The 10 commercial uses evaluated in the TIAX study currently account for
137 billion kilowatthours of electricity demand (about 470 trillion Btu),
or approximately 37 percent of miscellaneous electricity use in the commercial
sector (Table 7). Two well-established areas of commercial electricity
use, distribution transformers used to decrease the voltage of electricity
received from suppliers to usable levels and water services (purification,
distribution, and wastewater treatment) account for a large share of the
electricity consumption evaluated in the study. Although those two uses
are expected to continue accounting for a significant amount of commercial
electricity use, neither shows rapid growth in the projections. EPACT2005
includes efficiency standards to limit electricity losses from low-voltage
dry-type distribution transformers—the type most prevalent in the commercial
sector—which should limit their contribution to growth in commercial electricity
use. Trends in water conservation and wastewater reuse are expected to
offset the increasing energy intensity of treatment, resulting in total
projected growth in electricity use for public water services of more than
15 percent from 2005 to 2030—slightly less than the growth implied by the
0.8-percent average annual rate of population growth projected in the AEO2007
reference case.
Growth rates in electricity use for the remaining commercial uses included
in the TIAX study are governed by the specific market segments serviced
and by technology advances. The electricity requirements for medical imaging
equipment—magnetic resonance imaging systems (MRIs), computed tomography
(CT) scanners, and fixed-location x-ray machines—are expected to grow more
quickly than consumption for the other commercial services studied. MRIs
and CT scanners are relatively new technologies. They are expected to continue
penetrating the healthcare arena, and the technology is expected to advance,
leading to future increases in their total electricity use. Although x-ray
machines have been in use for many years, the move toward digital x-ray
systems and steady growth in the healthcare sector are expected to increase
their electricity use as well.
Electricity use for non-road electric vehicles, including lift trucks,
forklifts, golf carts, and floor burnishers, is projected to grow slightly
faster than commercial floorspace in the AEO2007 reference case, led by
growing sales of electric golf carts. Commercial-style coffee makers are
expected to grow with the food service and office segments, reflecting
the two major markets for commercial coffee services. Electricity consumption
for vertical transport (elevators and escalators) is expected to follow
growth in the commercial sector, tempered by the expectation that increasing
numbers of elevators will have the capability to enter standby mode, turning
off lights and ventilation, for up to 12 hours per night.
Industrial Sector Energy Demand: Revisions for Non-Energy-Intensive Manufacturing
For the industrial sector, EIA’s analysis and projection efforts generally
have focused on the energy-intensive industries—food, bulk chemicals, refining,
glass, cement, steel, and aluminum—where energy cost averages 4.8 percent
of annual operating cost. Detailed process flows and energy intensity indicators
have been developed for narrowly defined industry groups in the energy-intensive
manufacturing sector. The non-energy-intensive manufacturing industries,
where energy cost averages 1.9 percent of annual operating cost, previously
have received somewhat less attention, however. In AEO2006, energy demand
projections were provided for two broadly aggregated industry groups in
the non-energy-intensive manufacturing sector: metal-based durables and
other non-energy-intensive. In the AEO2006 projections, the two groups
accounted for more than 50 percent of the projected increase in industrial
natural gas consumption from 2004 to 2030.
With the non-energy-intensive industries making up such a significant share
of industrial natural gas demand, a more detailed review of the individual
industries that made up the two groups has been conducted. The review showed
that aggregation within those groups created a bias that contributed strongly
to the projected increase in their natural gas use in AEO2006. The least
energy-intensive component (computers and electronics) had the highest
projected growth rate for value of shipments, whereas the more energy-intensive
components had lower growth projections. To address the disparity, the
AEO2007 projections are based on more narrowly defined subgroups in the
non-energy-intensive manufacturing sector, as shown in Table 8.
Among the non-energy-intensive industry subgroups analyzed for AEO2007,
the computers and electronics group has the lowest energy intensity in
the metal-based durables manufacturing sector (Figure 16) and the highest
projected growth rate (Figure 17). Conversely, fabricated metals has the
highest energy intensity and the lowest projected growth rate in value
of shipments. Consequently, although the projected growth in value of shipments
for metal-based durables as a whole is higher in AEO2007 than it was in
AEO2006, because of the disaggregation, its delivered energy consumption
in 2030 is 15 percent lower in AEO2007 than in AEO2006 (Figure 18), and
its natural gas consumption in 2030 is nearly 200 trillion Btu (19 percent)
lower.
In the “other non-energy-intensive” sector of the non-energy-intensive
manufacturing industries, data limitations and the lack of a dominant energy
user make it more difficult to disaggregate industry subgroups. Based on
EIA’s 2002 MECS data, however, two specific industries—wood products (North
American Industry Classification System [NAICS] 321) and plastics manufacturing
(NAICS 326)—have been separated in the AEO2007 projections, with the remainder
of the other non-energy-intensive sector treated as a third subgroup. Wood
products is of interest because that industry derives 58 percent of the
energy it consumes (209 trillion Btu out of a total 361 trillion Btu in
2002) from biomass in the form of wood waste and residue. In the plastics
manufacturing industry, which produces goods by processing plastic materials
(it does not produce the plastic), one-half of the energy consumed (182
trillion Btu out of a total 344 trillion Btu in 2002) is in the form of
electricity. Together, the two industries account for 4 percent of the
total energy demand for all manufacturing (about 700 trillion Btu) and
7 percent of the value of shipments for all manufacturing.
In addition to the disaggregation described above, EIA has also reexamined
the use of steam as an energy source in the non-energy-intensive manufacturing
industries. For the other non-energy-intensive group, it was found that
steam is used primarily for space heating in buildings rather than in manufacturing
processes. As a result, AEO2007 projects slower growth in its demand for
steam than was projected in AEO2006. In combination, the two revisions described
here result in a significantly lower projection of energy demand for non-energy-intensive
manufacturing in 2030 in the AEO2007 reference case, about 20 percent lower
than was projected in AEO2006 (Figure 19).
Loan Guarantees and the Economics of Electricity Generating Technologies
The loan guarantee program authorized in Title XVII of EPACT2005 is not
included in AEO2007, because the Federal Credit Reform Act of 1990 requires
congressional authorization of loan guarantees in an appropriations act
before a Federal agency can make a binding loan guarantee agreement. As
of October 2006, Congress had not provided the legislation necessary for
DOE to implement the loan guarantee program (see “Legislation and Regulations”).
In August 2006, however, DOE invited firms to submit “pre applications”
for the first $2 billion in potential loan guarantees.
The EPACT2005 loan guarantee program could provide incentives for a wide
array of new energy technologies. Technologies potentially eligible for
loan guarantees include renewable energy systems, advanced fossil energy
technologies, hydrogen fuel cell technologies, advanced nuclear energy
facilities, CCS technologies, efficient generation, transmission, and distribution
technologies for electric power, efficient end-use technologies, production
facilities for fuel-efficient vehicles, pollution control technologies,
and new refineries.
In the electric power sector, the loan guarantee program could substantially
affect the economics of new power plants, for three reasons. First, Federal
loan guarantees would allow lenders to be reimbursed in cases of default,
but only for certain electric power sector technologies. Consequently,
they would be willing to provide loans for power plant construction at
lower interest rates, which would reduce borrowing costs. For example,
a number of private companies guarantee loans made by State and local governments.
Such insured loans typically are rated AAA (very low risk) and therefore
have relatively low yields. Indeed, municipalities purchase such insurance
because the decrease in interest rate is greater than the insurance premiums.
Second, firms typically finance construction projects by using a capital
structure that consists of a mix of debt (loans) and equity (funds supplied
from the owners of the firm). Debt financing usually is less expensive
than equity financing, and up to some point, the average cost of capital
(the weighted average cost of debt and equity financing) can be reduced
by substituting debt for equity financing. (The substitution of debt for
equity is called leveraging.) After that point, however, projects financed
with large amounts of debt can be very risky, and additional debt financing
can increase the average cost of capital rather than lower it. Thus, there
are constraints on the use of leverage. In many industries, capital structures
tend to include 40 to 60 percent debt. With loan guarantees, however, the
risks of highly leveraged projects are shifted to the guarantor, and more
leveraging can be used to reduce the average cost of capital for construction
projects.
Federal loan guarantees also can allow potential sponsors to participate
in one or more major projects while avoiding the risk of possible failure,
which might be caused by factors such as construction cost overruns or
lower than expected electricity prices and, potentially, could threaten
the financial viability of the sponsoring firm. To avoid this problem,
beginning in the 1990s, many firms used project financing to build electric
power plants, including a number of merchant natural-gas-fired plants that
were built in the late 1990s and early 2000s.
Under project financing, a power plant under construction is treated as
if it were owned by a separate entity whose sole asset is that new power
plant. Thus, the loan is secured only by the new plant. This is also referred
to as non-recourse financing. Because lenders for the plant’s construction
have claims only on the power plant in case of default, the project’s risk
is quarantined. That is, the lenders have no claims on the firm’s other
assets in case of default, and the project’s failure will have only limited
effect on the firm’s creditworthiness and overall financial health.
From the firm’s perspective, there are clear advantages to using project
financing. From the lender’s perspective, however, project (non-recourse)
financing can be very risky, especially if the project is highly leveraged.
If the project fails and the firm defaults on its loans, the power plant
will be sold; but if market electricity prices and thus the value of the
asset are depressed at the time of the sale, the lender may not be able
to recover all its costs. In addition, the administrative costs associated
with bond default can be substantial. Consequently, given the inherent
risk of large-scale projects, it could be very difficult to obtain project
financing for a multi-billion-dollar power plant at a cost that would allow
the project to remain economical. Federal loan guarantees would thus provide
an incentive program for potential lenders.
To examine the potential impacts of DOE’s loan guarantee program on the
economics of various capital-intensive electricity generating technologies,
the levelized costs of electricity generation from newly built power plants
financed with and without loan guarantees were computed, using plant cost
and performance assumptions from the AEO2007 reference case. In the case
without guarantees, financial assumptions from the reference case were
also used, including average equity financing costs of about 14 percent
over the 2006-2030 period, average debt financing costs of about 8.0 percent,
capital structures consisting of 55 percent equity and 45 percent debt,
and a capital recovery period of 20 years. In the case with loan guarantees,
capital structures of 20 percent equity and 80 percent debt were assumed.
The capital structure assumption in the loan guarantees case is typical
of the financing for construction projects for some merchant natural-gas-fired
power plant that have been built by companies with long-term power purchase
contracts. In addition, DOE has stated that its loan guarantees under the
new program will cover no more than 80 percent of the debt for any project.
It was assumed that the yields on such guaranteed debt would be halfway
between risk-free 10-year Treasury bonds and very low but not riskless
AAA corporate bonds. Based on average yields over the past 25 years, this
assumption implies that, with the loan guarantees, the cost of the insured
portion of the debt would fall by about 1.5 percentage points, to about
6.5 percent on average over the 2006-2030 period.
The uninsured portion of the debt (20 percent of 80 percent) would be relatively
risky, however, and probably would be rated below investment grade. Thus,
it was assumed that the cost of the uninsured debt would be at the lower
end of the yields to high-yield (fairly risky) corporate bonds, or about
1.5 percentage points higher than the 8.0 percent assumed in the case without
guarantees. In total, the cost of debt averaged over the insured and uninsured
portions of project debt financing in the case with loan guarantees would
be 7.1 percent—about 0.9 percentage point below the 8.0 percent assumed
in the case without loan guarantees.
Projections from the two alternative cases are shown in Table 9 for the
levelized costs of generating electricity from various technologies at
power plants becoming operational in 2015. The results show that loan guarantees
would significantly lower the levelized costs for eligible generating technologies.
(Conventional coal-fired and combined-cycle natural-gas-fired plants do
not qualify for the loan guarantee program.) In addition, because the loan
guarantee program reduces financing costs, the greater a technology’s capital
intensity, the greater would be the percentage reduction in total generation
costs. For a (capital-intensive) new nuclear power plant or wind farm that
received a loan guarantee, the levelized cost of its electricity production
is reduced by about 25 percent under the assumptions outlined above.
Impacts of Increased Access to Oil and Natural Gas Resources in the Lower
48 Federal Outer Continental Shelf
The OCS is estimated to contain substantial resources of crude oil and
natural gas; however, some areas of the OCS are subject to drilling restrictions.
With energy prices rising over the past several years, there has been increased
interest in the development of more domestic oil and natural gas supply,
including OCS resources. In the past, Federal efforts to encourage exploration
and development activities in the deep waters of the OCS have been limited
primarily to regulations that would reduce royalty payments by lease holders.
More recently, the States of Alaska and Virginia have asked the Federal
Government to consider leasing in areas off their coastlines that are off
limits as a result of actions by the President or Congress. In response,
the Minerals Management Service (MMS) of the U.S. Department of the Interior
has included in its proposed 5-year leasing plan for 2007-2012 sales of
one lease in the Mid-Atlantic area off the coastline of Virginia and two
leases in the North Aleutian Basin area of Alaska. Development in both
areas still would require lifting of the current ban on drilling.
For AEO2007, an OCS access case was prepared to examine the potential impacts
of the lifting of Federal restrictions on access to the OCS in the Pacific,
the Atlantic, and the eastern Gulf of Mexico. Currently, except for a relatively
small tract in the eastern Gulf, resources in those areas are legally off
limits to exploration and development. Mean estimates from the MMS indicate
that technically recoverable resources currently off limits in the lower
48 OCS total 18 billion barrels of crude oil and 77 trillion cubic feet
of natural gas (Table 10).
Although existing moratoria on leasing in the OCS will expire in 2012,
the AEO2007 reference case assumes that they will be reinstated, as they
have in the past. Current restrictions are therefore assumed to prevail
for the remainder of the projection period, with no exploration or development
allowed in areas currently unavailable to leasing. The OCS access case assumes
that the current moratoria will not be reinstated, and that exploration
and development of resources in those areas will begin in 2012.
Assumptions about exploration, development, and production of economical
fields (drilling schedules, costs, platform selection, reserves-to-production
ratios, etc.) in the OCS access case are based on data for fields in the
western Gulf of Mexico that are of similar water depth and size. Exploration
and development on the OCS in the Pacific, the Atlantic, and the eastern
Gulf are assumed to proceed at rates similar to those seen in the early
development of the Gulf region. In addition, it is assumed that local infrastructure
issues and other potential non-Federal impediments will be resolved after
Federal access restrictions have been lifted. With these assumptions, technically
recoverable undiscovered resources in the lower 48 OCS increase to 59 billion
barrels of oil and 288 trillion cubic feet of natural gas, as compared
with the reference case levels of 41 billion barrels and 210 trillion cubic
feet.
The projections in the OCS access case indicate that access to the Pacific,
Atlantic, and eastern Gulf regions would not have a significant impact
on domestic crude oil and natural gas production or prices before 2030.
Leasing would begin no sooner than 2012, and production would not be expected
to start before 2017. Total domestic production of crude oil from 2012
through 2030 in the OCS access case is projected to be 1.6 percent higher
than in the reference case, and 3 percent higher in 2030 alone, at 5.6
million barrels per day. For the lower 48 OCS, annual crude oil production
in 2030 is projected to be 7 percent higher—2.4 million barrels per day
in the OCS access case compared with 2.2 million barrels per day in the
reference case (Figure 20). Because oil prices are determined on the international
market, however, any impact on average wellhead prices is expected to be
insignificant.
Similarly, lower 48 natural gas production is not projected to increase
substantially by 2030 as a result of increased access to the OCS. Cumulatively,
lower 48 natural gas production from 2012 through 2030 is projected to
be 1.8 percent higher in the OCS access case than in the reference case.
Production levels in the OCS access case are projected at 19.0 trillion
cubic feet in 2030, a 3-percent increase over the reference case projection
of 18.4 trillion cubic feet. However, natural gas production from the lower
48 offshore in 2030 is projected to be 18 percent (590 billion cubic feet)
higher in the OCS access case (Figure 21). In 2030, the OCS access case
projects a decrease of $0.13 in the average wellhead price of natural gas
(2005 dollars per thousand cubic feet), a decrease of 250 billion cubic
feet in imports of liquefied natural gas, and an increase of 360 billion
cubic feet in natural gas consumption relative to the reference case projections.
In addition, despite the increase in production from previously restricted
areas after 2012, total natural gas production from the lower 48 OCS is
projected generally to decline after 2020.
Although a significant volume of undiscovered, technically recoverable
oil and natural gas resources is added in the OCS access case, conversion
of those resources to production would require both time and money. In
addition, the average field size in the Pacific and Atlantic regions tends
to be smaller than the average in the Gulf of Mexico, implying that a significant
portion of the additional resource would not be economically attractive
to develop at the reference case prices.
Alaska Natural Gas Pipeline Developments
The AEO2007 reference case projects that an Alaska natural gas pipeline
will go into operation in 2018, based on EIA’s current understanding of
the project’s time line and economics. There is continuing debate, however,
about the physical configuration and the ownership of the pipeline. In
addition, the issue of Alaska’s oil and natural gas production taxes has
been raised, in the context of a current market environment characterized
by rising construction costs and falling natural gas prices. If rates of
return on investment by producers are reduced to unacceptable levels, or
if the project faces significant delays, other sources of natural gas,
such as unconventional natural gas production and LNG imports, could fulfill
the demand that otherwise would be served by an Alaska pipeline.
The primary Alaska North Slope oil and natural gas producers—BP, ExxonMobil,
and ConocoPhillips— became interested in building an Alaska natural gas
pipeline after natural gas prices began to increase substantially during
2000. In May 2002, they released a report on the expected costs of building
a pipeline along two different routes. Since then, construction of a pipeline
has been stalled by differences of opinion within Alaska regarding the
ultimate destination of the pipeline and the level of taxation applied
to the State’s oil and natural gas production. Recent increases in construction
costs and trends in natural gas prices are important factors that will
determine the economic viability of the pipeline.
Physical Configuration of the Pipeline
There are three different visions for the physical configuration of the
Alaska natural gas pipeline. One vision—the southern route—supports the
construction of a pipeline that would serve lower 48 natural gas markets
exclusively, following the TransAlaska Pipeline System to Fairbanks and
then the Alaska Highway into Canada. A second vision—the northern route—as
proposed by the North Slope producers, advocates a pipeline route going
east along the Alaska’s north coast to the Mackenzie Delta in Canada and
then proceeding south to the lower 48 States. In 2002, the producers estimated
that the northern route would cost approximately $800 million less to build
than the southern route, because it would be about 338 miles shorter and
would traverse less mountainous terrain. In 2001, Alaska enacted legislation
to foreclose the northern route. A third view—the south central design—supports
the construction of a pipeline that would transport natural gas to south
central Alaska, both to serve local consumers and to provide LNG to overseas
consumers.
The three pipeline proposals are based on fundamentally different priorities.
The northern and southern routes are premised on the notion that an Alaska
natural gas pipeline would be economically feasible only if it captured
the greatest possible economies of scale (the greatest pipeline throughput),
thereby ensuring the highest possible wellhead price for North Slope natural
gas and the greatest State royalty collection. The south central design
is premised largely on the idea that, because natural gas reserves in the
Cook Inlet region are declining, North Slope production should be transported
to south central Alaska to ensure the future availability of natural gas
to that region’s consumers.
Production Taxes
The Alaska Stranded Natural Gas Development Act was signed in 1998 to make
a natural gas pipeline project in Alaska commercially feasible. When the
Act was passed, lower 48 wellhead natural gas prices averaged $1.96 per
thousand cubic feet. Since then, as lower 48 prices have increased, the
political climate in Alaska has changed from one in which financial incentives
were thought to be crucial to the construction of a pipeline to one in
which some interests believe that State taxes on oil and natural gas production
are not high enough.
In May 2006, a draft stranded gas contract was made publicly available.
In the draft, the North Slope producers and the State agreed to a 20-percent
production tax with a 20-percent tax credit for future investments in Alaska’s
oil and natural gas development. The terms and conditions were negotiated
to remain in effect for the next 30 years. After the release of the draft
contact, opponents argued that the contract’s production tax rate was too
low and the investment credits too large.
In August 2006, the Alaska legislature in a special session passed an oil
and natural gas production tax, which raised the oil production tax from
the negotiated 20 percent up to 22.5 percent. The legislation, which was
signed into law that same month, also reduced the level of investment tax
credits that North Slope producers could use to offset their production
tax liabilities.
At a minimum, the discrepancy between the provisions in the August 2006
law and the draft standard gas contract will necessitate renegotiation
between the producers and the State. The governor who negotiated the draft
contract and signed the August 2006 law was defeated in his bid for reelection.
The pipeline was a major issue in the campaign, and the new governor may
not want to use the existing draft contract as the starting point for negotiation.
Other Issues
Until the State of Alaska and the North Slope producers come to some agreement
on an Alaska natural gas pipeline, a number of other issues will remain
unresolved. One issue is whether the State should be an equity investor
and owner of the pipeline [105]. Another involves the issuing of environmental
permits for the pipeline route, a process that has been contentious for
other pipeline projects, sometimes resulting in significant delays.
A third issue is who will construct, own, and operate the portion of an
Alaska natural gas pipeline that runs through Canada. TransCanada Pipelines
maintains that it has the legislated right to be the owner and operator
of the Canadian portion, as specified in Canada’s Northern Pipeline Act
of 1978 [106]. Finally, the pipeline’s regulatory framework could prove
contentious. For the portion located within the confines of the State, Alaska’s
Regulatory Commission will have jurisdiction over rates and tariffs, including
the terms and conditions associated with third-party access to the pipeline.
These other issues will not be fully addressed until after all the issues
between the State and the North Slope producers have been resolved, and
it is not clear how contentious the issues will be or how quickly they
can be settled.
Construction Costs and Natural Gas Prices
In May 2002, the three primary Alaska North Slope producers estimated the
cost of construction for a proposed southern route pipeline to the Chicago
area and its associated facilities at approximately $19.4 billion [107].
On the basis of that capital cost, they estimated a pipeline transportation
tariff of $2.39 per thousand cubic feet for natural gas moving from the
North Slope to Chicago. From May 2002 to June 2006, however, iron and steel
prices increased by 72 percent [108]. Although it has been estimated that
only 25 percent of the total pipeline cost would be associated with steel
pipe, construction costs have been increasing across the board, as equipment,
labor, and contractor costs have also risen.
A Federal law enacted in 2004 permits the Secretary of Energy to issue
Federal loan guarantees for the construction of an Alaska natural gas pipeline.
The guarantees would be limited to 80 percent of the pipeline’s total cost,
up to a maximum of $18 billion. Because the Federal loan guarantees would
lower the risk associated with recovery of the project’s capital costs,
pipeline sponsors would be able to secure debt financing at a lower interest
rate than they could in the absence of such guarantees, and the pipeline’s
financial viability would be enhanced.
Recent increases in natural gas prices, which began in 2000, have also
improved the economic outlook for an Alaska natural gas pipeline. Lower
48 wellhead prices, which averaged $2.19 per thousand cubic feet in 1999,
rose to an average of $7.51 per thousand cubic feet in 2005. Although prices
have declined since then, the AEO2007 reference case price projections
are at a level at which an Alaska natural gas pipeline would remain economically
viable if other issues surrounding the project could be resolved in a manner
that met the needs of all parties. The parties would have to agree on a
division of the projected benefits before the pipeline could be built.
Coal Transportation Issues
Most of the coal delivered to U.S. consumers is transported by railroads,
which accounted for 64 percent of total domestic coal shipments in 2004
[109]. Trucks transported approximately 12 percent of the coal consumed
in the United States in 2004, mainly in short hauls from mines in the East
to nearby coal-fired electricity and industrial plants. A number of minemouth
power plants in the West also use trucks to haul coal from adjacent mining
operations. Other significant modes of coal transportation in 2004 included
conveyor belt and slurry pipeline (12 percent) and water transport on inland
waterways, the Great Lakes, and tidewater areas (9 percent) [110].
Rail is particularly important for long-haul shipments of coal, such as
the transport of subbituminous coal from mines in Wyoming to power plants
in the eastern United States. In 2004, rail was the primary mode of transportation
for 98 percent of the coal shipped from Wyoming to customers in other States.
Rail Transportation Rates
When the railroad industry was deregulated in the early 1980s, consumers
benefited from a long period of declining coal transportation rates. For
coal shipments to electric utilities, rates in constant dollars per ton
fell by 42 percent from 1984 to 2001 [111]. More recently, railroads have
been raising base transportation rates and implementing fuel surcharge
programs. There are also concerns that railroads are failing to meet their
common carrier obligation with regard to reliability of service [112].
The national average rate for coal transportation in 2005 was approximately
6 percent higher (in constant dollars) than in 2004 [113]; and according
to BNSF, average revenue per car in the first 6 months of 2006 was 7 percent
higher than in the same period of 2005 as a result of contract rate escalations,
fuel surcharges, and increases in hauling distances [114]. Recent increases
in rates have caused shippers to question their fairness and to raise the
possibility that the railroads may be exercising market power. Since deregulation,
four railroads have dominated rail transportation of coal: CSX Transportation
(CSX) and NS in the East and UP and BNSF in the West.
The concentration of coal freight business among a few carriers has led
to claims of pricing power, in particular from coal shippers that have
no alternative to relying on a single railroad. In 2004, when both UP and
BNSF made their rates public by posting them on their web sites, some called
it price collusion, in that the two companies could see each other’s rates
and, potentially, harmonize them. In February 2005, the U.S. Department
of Justice initiated an investigation of their pricing activities. In October
2006, while not drawing any conclusions, the Government Accountability
Office recommended that the state of competition in the freight railroad
industry be analyzed [115].
The U.S. Department of Transportation’s Surface Transportation Board (STB)
has also been asked to review the reasonableness of rates imposed on some
captive customers. Typically, for a rate case to be brought before the
STB, there must be evidence suggesting not only that the railroads charge
more than 180 percent of their variable cost to the captive shipper but
also that construction of a new rail line to serve the captive customer’s
needs would be more economical than the prices currently charged. In cases
decided from 2004 through June 2006, one showed an unreasonable rate, three
were settled voluntarily, and two were decided in favor of the railroads
[116]. Because concerns have been raised about the cost and time involved
in preparing rate cases, the STB instituted a series of rulemakings in
2006 to improve the process by modifying its methods and procedures for
large rail rate disputes and revising its simplified guidelines for smaller
rate disputes.
A number of factors, including railroad profitability, the need for more
investment, and increased fuel expenses in recent years, may be contributing
to the recent increase in coal transportation rates. One motive for price
increases by the railroads is to improve their rate of return on investment.
The STB identifies a railroad as “revenue adequate” if its return on investment
exceeds the industry’s average cost of capital, as estimated by the STB.
By this standard, only NS was considered revenue adequate in 2004 and 2005,
whereas none of the railroads was considered revenue adequate in 2003 [117].
The railroads have argued that, after deregulation, savings resulting from
consolidation of redundant infrastructure were passed on to their customers,
but that such savings are no longer attainable. Instead, they typically
state that higher prices are needed to add infrastructure in order to keep
pace with demand. Most recently, each of the railroads has instituted a
fuel surcharge program in response to rising fuel prices. The surcharge
programs have been cited by many of the railroads as a success, and they
have contributed to record-breaking profits. UP, for instance, reported
profits for the fourth quarter of 2005 that were triple those of the fourth
quarter of 2004 [118]. Some rail customers in the coal industry have in
turn claimed that the railroads are “double dipping,” recovering more through
the surcharges than they spend on fuel.
The railroads have maintained that their fuel surcharge programs are transparent,
but most customers appear to disagree. Each of the railroads has implemented
its program differently, choosing different fuel price targets and thresholds
that trigger the surcharge. For instance, BNSF and UP use EIA’s on-highway
diesel price as the basis for determining whether a fuel surcharge will
be implemented, whereas NS and CSX use the WTI crude oil price. As of July
1, 2006, NS was applying a surcharge when the monthly WTI average price
exceeded $64 per barrel [119]. CSX begins its price adjustments when the
WTI price reaches $23.01 per barrel [120].
The STB has stated that the surcharge programs, while not unreasonable,
were implemented in an unreasonable manner that lacked transparency. It
simultaneously recommended the use of a program that would be linked more
tightly to actual fuel usage and would require all carriers to use the
same fuel index [121]. The response from the railroads has been mixed,
with BNSF stating that the STB lacks authority to make a ruling unless
a formal shipper’s complaint is brought forward [122] and CSX expressing
a willingness to comply “under future guidance from the STB” [123].
Wyoming Powder River Basin
One of the most important U.S. coal-producing areas is Wyoming’s Powder
River Basin. Almost all the coal produced there is carried out by rail,
and disruptions in the rail transportation network can have significant
effects on the flow of coal from the region. Key factors that can lead
to disruptions include the need to perform major maintenance on important
segments of a rail corridor and the development of bottlenecks due to unforeseen
growth in the demand for rail transportation services. The problems that
arose in the Powder River Basin in 2005 and 2006 illustrate the potential
impact of these factors.
In May 2005, adverse weather conditions and accumulated coal dust in the
roadbed of the Joint Line railroad combined to create track instability
that contributed to two train derailments. The Joint Line Railroad, a 103-mile
stretch of dedicated coal railway, is jointly owned and operated by BNSF
and UP. It serves 8 of the 14 active coal mines in Wyoming’s Powder River
Basin and is one of the most heavily used sections of rail line in the
world.
During 2005 and 2006, coal shippers expressed their concerns about operating
conditions on the Joint Line in testimony before both houses of Congress
and the FERC. Some power plant operators indicated that inadequate shipments
of coal from the Powder River Basin had forced them to draw down their
on-site stockpiles of coal to unprecedented levels in early to mid-2006.
Others said they were forced to dispatch more expensive generating capacity,
purchase electricity from other generators to meet customer demand, or
buy high-priced coal on the spot market or from offshore suppliers. In
testimony before the U.S. Senate in May 2006, EIA indicated that monthly
data reported by electric power plants did show a drop in inventories of
subbituminous coal (most of which comes from Wyoming) from mid-2005 through
early 2006, consistent with press reports that generators relying on subbituminous
coal were taking steps to conserve coal supplies [124].
A study recently produced for the U.S. Bureau of Land Management found
that capacity utilization of the Joint Line in 2003 exceeded 88 percent,
as compared with 22 percent for the BNSF rail line that served five active
Wyoming mines north of the Joint Line in 2003 (Wyodak, Dry Fork, Rawhide,
Eagle Butte, and Buckskin). The combined output of those mines has increased
significantly, from 55 million tons in 2003 to 65 million tons in 2005,
and is likely to surpass 70 million tons in 2006. As a result, utilization
of the BNSF line is now slightly higher than it was in 2003. The mines
served by the Joint Line produced and shipped 325 million tons of coal
in 2005, accounting for 29 percent of the year’s total U.S. coal production.
Joint Line shipments for the year were 3 million tons higher than in 2004
but still 20 million tons less than had been planned [125].
BNSF and UP have completed maintenance work related to the 2005 train derailments
and have embarked on major upgrades to increase haulage capacity on the
Joint Line; however, demand in 2006 was expected to exceed the capability
of the railroads and mines to supply coal from the area to the market.
In mid-2006, a representative from BNSF indicated that the potential demand
for Powder River Basin coal for the year probably would exceed supply by
20 to 25 million tons [126]. Through August 2006, coal shipments on the
Joint Line were 9 percent higher than in the same period of 2005, corresponding
to an annualized increase of approximately 25 million tons.
Beyond 2006, investments in new track and rail equipment for the Joint
Line indicate an improved outlook for shipping capacity. Recently announced
plans for investments in 2005 through 2007, totaling about $200 million,
will add nearly 80 miles of third and fourth mainline track to the Joint
Line, increasing annual shipping capacity to almost 420 million tons [127].
In a recent study for BNSF and UP, the consulting firm CANAC identified
investments that could further increase the Joint Line’s capacity to approximately
500 million tons by 2012 [128]. The potential increase in shipments was
arrived at through discussions with individual mine operators along the
Joint Line. According to the study, an additional 80 million tons of shipping
capacity after 2007 would require the construction of 12 new loading spots
at mines and 45 additional miles of mainline track. Also key to meeting
the target of 500 million tons is the expectation that railroads will be
able to move gradually to longer trains over the next few years, from current
lengths of 125 to 130 cars to approximately 150 cars [129].
The authors of the CANAC report indicated that the timing of investments
will depend on the market for Powder River Basin coal in coming years and
could deviate from the schedule outlined. Although production from mines
on the Joint Line were not explicitly modeled by EIA, the projected growth
of coal production from Wyoming’s Powder River Basin in the AEO2007 reference
case is not inconsistent with the expansion potential identified in the
CANAC report. In all the cases modeled for AEO2007, the projected increase
in annual coal production from active mines in Wyoming’s Powder River Basin
is less than 175 million tons (the sum of Joint Line expansion projects
identified in the report) until after 2019.
Another potential investment under consideration is an expansion of the
Dakota Minnesota & Eastern Railroad (DM&E) westward to the Powder River
Basin. The project would include 280 miles of new construction and provide
an alternative rail option for Wyoming coal. It would provide access to
the mines currently active south of Gillette, Wyoming, and would be independent
of the existing Joint Line [130]. The extension would provide enough rail
capacity for the transport of 100 million tons of coal annually according
to DM&E, which is seeking a loan from the Federal Railroad Administration
to support it.
Coal Production and Consumption Projections in AEO2007
In the AEO2007 reference case, coal remains the primary fuel for electricity
generation through 2030. Coal production is projected to increase significantly,
particularly in the Powder River Basin. From 2005 to 2030, production in
the Wyoming Powder River Basin is projected to grow by 289 million tons,
but the projected annual increases do not exceed 30 million tons. The resulting
increase in coal transport requirements is not beyond the level of expansion
projects currently being discussed.
The Rocky Mountain, Central West, and East North Central regions are projected
to show the largest increases in coal demand, by about 100 million tons
each, from 2005 to 2030. The majority of the coal delivered to the Rocky
Mountain region is projected to continue to come from Colorado and Utah.
In addition, most of the growth in the region is projected to come from
new plants that are likely to be built as close as possible to supply sources,
potentially reducing the need for extensive new development of rail infrastructure.
At a minimum, new plants will be located only after careful consideration
of transportation options, to reduce the potential for rail bottlenecks.
For the Central West region, 42 percent of the increase in coal demand
is projected to be supplied by Wyoming Powder River Basin coal; however,
the largest supply increase (meeting 55 percent of the region’s total increase
in demand) is projected to come from the Dakota lignite supply region,
to provide feedstocks for new CTL plants that are likely to be situated
as close to their supply sources as possible.
In the East North Central region, most of the coal supply to meet the projected
growth in consumption (120 million tons from 2005 to 2030) is expected
to come from the Wyoming Powder River Basin. The increase in the region’s
demand for coal could lead to congestion on heavily traveled rail lines,
such as those surrounding the Chicago area, where coal and other bulk commodities
already make heavy use of the system. The strongest growth in the region’s
coal consumption is projected to occur between 2020 and 2025, when deliveries
from Wyoming’s Powder River Basin are projected to grow by 43 million tons,
with the largest single-year increase being 12 million tons.
Biofuels in the U.S. Transportation Sector
Sustained high world oil prices and the passage of the EPACT2005 have encouraged
the use of agriculture-based ethanol and biodiesel in the transportation
sector; however, both the continued growth of the biofuels industry and
the long-term market potential for biofuels depend on the resolution of
critical issues that influence the supply of and demand for biofuels. For
each of the major biofuels—corn-based ethanol, cellulosic ethanol, and
biodiesel—resolution of technical, economic, and regulatory issues remains
critical to further development of biofuels in the United States.
In the transportation sector, ethanol is the most widely used liquid biofuel
in the world. In the United States, nearly all ethanol is blended into
gasoline at up to 10 percent by volume to produce a fuel called E10 or
“gasohol.” In 2005, total U.S. ethanol production was 3.9 billion gallons,
or 2.9 percent of the total gasoline pool. Preliminary data for 2006 indicate
that ethanol use rose to 5.4 billion gallons. Biodiesel production was
91 million gallons, or 0.21 percent of the U.S. distillate fuel oil market,
including diesel, in 2005 (Table 11). All cars and light trucks built for
the U.S. market since the late 1970s can run on the ethanol blend E10.
Automakers also produce a limited number of FFVs for the U.S. market that
can run on any blend of gasoline and ethanol up to 85 percent ethanol by
volume (E85). Because auto manufacturers have been able to use FFV sales
to offset CAFE requirements, more than 5 million FFVs were produced for
the U.S. market from 1992 through 2005. E10 fuel is widely available in
many States. E85 has limited availability, at stations clustered mostly
in the midwestern States.
In the AEO2007 reference case, ethanol use increases rapidly from current
levels. Ethanol blended into gasoline is projected to account for 4.3 percent
of the total gasoline pool by volume in 2007, 7.5 percent in 2012, and
7.6 percent in 2030. As a result, gasoline demand increases more rapidly
in terms of fuel volume (but not in terms of energy content) than it would
in the absence of ethanol blending. Overall, gasoline consumption is projected
to increase by 32 percent on an energy basis, and by 34 percent on a volume
basis, from 2007 to 2030.
Ethanol can be produced from any feedstock that contains plentiful natural
sugars or starch that can be readily converted to sugar. Popular feedstocks
include sugar cane (Brazil), sugar beets (Europe), and maize/corn (United
States). Ethanol is produced by fermenting sugars. Corn grain is processed
to remove the sugar in wet and dry mills (by crushing, soaking, and/or
chemical treatment), the sugar is fermented, and the resulting mix is distilled
and purified to obtain anhydrous ethanol. Major byproducts from the ethanol
production process include dried distillers’ grains and solubles (DDGS),
which can be used as animal feed. On a smaller scale, corn gluten meal,
gluten feed, corn oil, CO2, and sweeteners are also byproducts of the ethanol
production process used in the United States.
With additional processing, plants and other biomass residues (including
urban wood waste, forestry residue, paper and pulp liquors, and agricultural
residue) can be processed into fermentable sugars. Such potentially low-cost
resources could be exploited to yield significant quantities of fuel-quality
ethanol, generically termed “cellulosic ethanol.” Cellulose and hemicellulose
in biomass can be broken down into fermentable sugars by either acid or
enzymatic hydrolysis. The main byproduct, lignin, can be burned for steam
or power generation. Alternatively, biomass can be converted to synthesis
gas (hydrogen and carbon monoxide) and made into ethanol by the Fischer-Tropsch
process or by using specialized microbes.
Capital costs for a first-of-a-kind cellulosic ethanol plant with a capacity
of 50 million gallon per year are estimated by one leading producer to
be $375 million (2005 dollars) [131], as compared with $67 million for
a corn-based plant of similar size, and investment risk is high for a large-scale
cellulosic ethanol production facility. Other studies have provided lower
cost estimates. A detailed study by the National Renewable Energy Laboratory
in 2002 estimated total capital costs for a cellulosic ethanol plant with
a capacity of 69.3 million gallons per year at $200 million [132]. The
study concluded that the costs (including capital and operating costs)
remained too high in 2002 for a company to begin construction of a first-of-its-kind
plant without significant short-term advantages, such as low costs for
feedstocks, waste treatment, or energy.
If future oil prices follow a path close to that in the AEO2007 reference
case, significant reductions in the capital cost and operating costs of
a cellulosic ethanol plant will be needed for cellulosic ethanol to be
economically competitive with petroleum-based fuels. The extent to which
costs can be reduced through a combination of advances in the production
process for cellulosic ethanol and learning as plants are constructed in
series will be important to the future competitiveness of cellulosic ethanol.
World oil price developments also will play a central role.
Currently, no large-scale cellulosic ethanol production facilities are
operating or under construction. EPACT2005 provides financial incentives
that in the AEO2007 reference case are projected to bring the first cellulosic
ethanol production facilities on line between 2010 and 2015, with a total
capacity of 250 million gallons per year. Cellulosic ethanol currently
is not cost-competitive with gasoline or corn-based ethanol, but considerable
R&D by the National Renewable Energy Laboratory and its partners has significantly
reduced the estimated cost of enzyme production. Although technological
breakthroughs are inherently unpredictable, further significant successes
in R&D could make cellulosic ethanol a viable economic option for expanded
ethanol production in the future.
Biodiesel is a renewable-based diesel substitute used in Europe with early
commercial market development in the United States. Biodiesel is composed
of mono-alkyl esters of long-chain fatty acids derived from vegetable oils
or animal fats [133]. It is similar to distillate fuel oil (diesel fuel)
and can be used in the same applications, but it has different chemical,
handling, and combustion characteristics. Biodiesel can be blended with
petroleum diesel in any fraction and used in compression-ignition engines,
so long as the fuel system that uses it is constructed of materials that
are compatible with the blend. The high lubricity of biodiesel helps to
offset the impact of adopting low-sulfur diesel.
Common blends of biodiesel are 2 percent, 5 percent, and 20 percent (B2,
B5, and B20). Individual engine manufacturers determine which blends are
warranted for use in their engines, but generally B5 blends are permissible
and some manufacturers support B20 blends. Blends of biodiesel are distributed
at stations throughout the United States. Some States have mandated levels
of biodiesel use when in-State production reaches prescribed levels.
Predominant feedstocks for biodiesel production are soybean oil in the
United States, rapeseed and sunflower oil in Europe, and palm oil in Malaysia.
Biodiesel also can be produced from a variety of other feedstocks, including
vegetable oils, tallow and animal fats, and restaurant waste and trap grease.
To produce biodiesel, raw vegetable oil is chemically treated in a process
called transesterification. The properties of the biodiesel (cloud point,
pour point, and cetane number) depend on the type of feedstock used. Crude
glycerin, a major byproduct of the reaction, usually is sold to the pharmaceutical,
food, and cosmetic industries.
Energy Content and Fuel Volume
On a volumetric basis, ethanol and biodiesel have lower energy contents
than do gasoline and distillate fuel oil, respectively. Table 12 compares
the energy contents of various fuels on the basis of Btu per gallon and
gallons of gasoline equivalent. The table shows both the low heating value
(the amount of heat released by the fuel, ignoring the latent heat of vaporization
of water) and the high heating value (the amount of heat released by the
fuel, including the latent heat of vaporization of water). The lower energy
content of ethanol and biodiesel generally results in a commensurate reduction
in miles per gallon when they are used in engines designed to run on gasoline
or diesel. Small-percentage blends of ethanol and biodiesel (E10, B2, and
B5) result in smaller losses of fuel economy than do biofuel-rich blends
(E85 and B20).
Today, most fuel ethanol is used in gasoline blends, where it accounts
for as much as 10 percent of each gallon of fuel—a level that all cars
can accommodate. In higher blends, ethanol can make up as much as 85 percent
of each gallon of fuel by volume. In the future, increased use of ethanol
as a transportation fuel will raise the issue of fuel volume versus energy
content. Ethanol contains less energy per gallon than does conventional
gasoline. A gallon of ethanol has only two-thirds the energy of a gallon
of conventional gasoline, and the number of miles traveled by a given vehicle
per gallon of fuel is directly proportional to the energy contained in
the fuel.
E10 (10 percent ethanol) has 3.3 percent less energy content per gallon
than conventional gasoline. E85 (which currently averages 74 percent ethanol
by volume) has 24.7 percent less energy per gallon than conventional gasoline.
AEO2007 assumes that engine thermal efficiency remains the same whether
the vehicle burns conventional gasoline, E10, or E85. This means that 1.03
gallons of E10 or 1.33 gallons of E85 are needed for a vehicle to cover
the same distance that it would with a gallon of conventional gasoline.
Although the difference is not expected to have a significant effect on
purchases of E10, AEO2007 assumes that motorists whose vehicles are able
to run on E85 or conventional gasoline will compare the two fuels on the
basis of price per unit of energy.
The issue of gasoline energy content first arose in the early 1990s with
the introduction of oxygenated gasoline made by blending conventional gasoline
with 15 percent MTBE or 7.7 percent ethanol by volume. When oxygenated
gasoline was introduced, MTBE was the blending agent of choice. Since then,
ethanol has steadily replaced MTBE in oxygenated and RFG blends. The fuel
economy impact of switching from MTBE-blended gasoline to an ethanol blend
is smaller than the impact of switching from conventional gasoline. For
example, changing from 15 percent MTBE to 7.7 percent ethanol in blended
gasoline results in a reduction in energy content of only 1.2 percent per
gallon of fuel, and changing from 15 percent MTBE to 10 percent ethanol
results in a reduction of 1.9 percent.
Current State of the Biofuels Industry
The nascent U.S. biofuel industry has recently begun a period of rapid
growth. Over the past 6 years, biofuel production has been growing both
in absolute terms and as a percentage of the gasoline and diesel fuel pools
(see Table 11). High world oil prices, firm government support, growing
environmental and energy security concerns, and the availability of low-cost
corn and soybean feedstocks provide favorable market conditions for biofuels.
Ethanol, in particular, has been buoyed by the need to replace the octane
and clean-burning properties of MTBE, which has been removed from gasoline
because of concerns about groundwater contamination. About 3.9 billion
gallons of ethanol and 91 million gallons of biodiesel were produced in
the United States in 2005. According to estimates based on the number of
plants under construction, ethanol production capacity could rise to about
7.5 billion gallons and biodiesel capacity to about 1.1 billion gallons
by 2008, possibly resulting in excess capacity in the near term (Figure
22).
The American Jobs Creation Act of 2004 established and extended blender’s
tax credits to reduce the final cost (in nominal terms) of pure ethanol
by $0.51 per gallon, biodiesel made from virgin oil by $1.00 per gallon,
and biodiesel made from waste grease by $0.50 per gallon [134]. The national
RFS legislated in EPACT2005 provides biofuels with a reliable market of
at most 7.5 billion gallons annually by 2012. Ethanol fuel is expected
to fulfill most of the RFS requirement.
In the AEO2007 reference case, ethanol demand is projected to exceed the
applicable RFS requirements between now and 2012, because of the need for
ethanol as a fuel oxygenate to meet Federal gasoline specifications and
as an octane enhancer and because of the blender’s tax credit. Ethanol
consumption is projected to rise to 11.2 billion gallons, representing
7.5 percent of the gasoline pool, by volume, in 2012. Current and projected
real oil prices far above those experienced during the 1990s, coupled with
the availability of significant tax incentives and the RFS requirement
have created a favorable market for biofuels. Accelerated investments in
biofuel production facilities and rapid expansion of existing capacity
underscore the attractiveness of biofuel investments.
Short-run production costs, which include feedstock costs, cash operating
expenses, producer subsidies, and byproduct credits but exclude capital
costs, transportation fees, tax credits, and fuel taxes, vary considerably
according to plant size, design, and feedstock supply. Assuming corn prices
of about $2 per bushel and excluding capital costs, corn-based ethanol
can be produced by the dry-milling process for approximately $1.00 to $1.06
per gallon (2005 dollars) or $11.90 to $12.60 per million Btu [135, 136].
Corn prices spiked to well above that level in 2006 because of tightness
in the supply-demand balance for corn, caused by farmers’ removing about
3 million acres from corn production and using it for soybean production
instead.
Biodiesel can be produced from soybean oil for $1.80 to $2.40 per gallon
($15.20 to $20.30 per million Btu) and from yellow grease for $0.90 to
$1.10 per gallon ($7.60 to $9.30 per million Btu) [137, 138]. Feedstock
costs for virgin soybean oil, which are dictated by commodity markets and
vary between $0.20 and $0.30 per pound, constitute 70 to 78 percent of
final production costs. Non-virgin feedstocks generally are cheaper, ranging
from virtually no cost (for reclaimed restaurant trap grease) to 70 percent
of the final production cost. For the production costs calculated above,
virgin soybean oil was assumed to cost $0.26 per pound, and yellow grease
was valued at 50 percent of the cost of an equivalent amount of soybean
oil.
When the blender’s tax credit for ethanol and biodiesel is subtracted from
the wholesale prices (which include capital recovery and transportation
fees), biofuels are price competitive with petroleum fuels on a volumetric
basis [139]. Figure 23 compares the rack price of ethanol (including the
blender’s tax credit) with the price of unleaded gasoline. The “rack price”
is defined as the wholesale price of ethanol fuel where title is transferred
at the terminal.
Profitability in the biofuels industry depends heavily on the cost of feedstocks.
For ethanol, corn feedstock made up nearly 57 percent of the total production
cost in 2002 [140]. For biodiesel, soybean oil makes up 70 to 78 percent
of the total production cost [141, 142]. Fluctuations in the price of either
feedstock can have dramatic effects on the production costs, and the industry
assumes considerable market risk by relying on a limited array of feedstocks.
The U.S. ethanol industry relies almost exclusively on corn, consuming
20 percent of the available corn supply in 2006 [143]. At current production
levels, corn— which is produced domestically in large volumes—is the most
attractive feedstock for ethanol. As ethanol production increases, competition
for corn supplies among the fuel, food, and export markets, along with
a decline in the marginal value of ethanol co-products, is expected to
make production more expensive [144].
Assuming the development of cost-effective production facilities, cellulosic
biomass feedstocks like switchgrass, agricultural residues, and hybrid
poplar trees could supply a growing ethanol industry with large quantities
of less expensive raw materials. To differentiate the current use of corn
with the future use of cellulosic biomass and the differences in production
technology, corn is generally characterized as a “first generation” energy
crop, whereas switchgrass and other cellulosic materials are “second generation”
energy crops.
The U.S. biodiesel industry relies almost exclusively on soybean oil as
a feedstock. Soybean oil has historically been a surplus product of the
oilmeal crushing industry, available in large quantities at relatively
low prices. At production levels nearing 300 to 600 million gallons of
biodiesel per year (less than 2 percent of the diesel fuel pool), the marginal
cost of using soybean oil as a feedstock rises to the point where other
oilseeds—canola, rapeseed, sunflower, and cottonseed—become viable feedstocks
[145]. There are no significant differences in processing for the numerous
biodiesel feedstocks, and they cannot easily be grouped into first- and
second-generation categories. The major differences among biodiesel feedstocks
are regional availability, co-product value, and the composition of fatty
acids in the refined vegetable oil.
Resource Utilization and Land Availability
Currently, corn and soybean feedstocks for biofuels are grown almost exclusively
on prime agricultural land in the Midwest. Increases in the supply of biofuel
feedstocks could come from a combination of three strategies: increasing
the amount of land used as cropland, boosting the yields of existing energy
crops, and replacing or supplementing corn with cellulosic biomass and
soybeans with oilseeds more appropriate for biodiesel production. All three
strategies may be required to overcome the constraints of currently available
feedstocks and sustain biofuel production levels that could displace at
least 10 percent of gasoline consumption.
According to the most recent Agricultural Census (2002), the amount of
cropland available in the lower 48 United States is 434 million acres [146],
or 23 percent of the total land area [147]. The total amount of cropland—defined
as the sum of land used for crops, idle land, and pasture—has been declining
for the past 50 years and, increasingly, is becoming concentrated in the
Midwest. The trend is expected to continue as population pressure leads
to permanent conversion of some agricultural lands to other uses. It is
unlikely that additional cropland will be added in the United States to
accommodate increases in the demand for biofuels. Instead, the cultivation
of biofuels will compete with other agricultural uses, such as pastureland
and idle land, much of which is in the Conservation Reserve Program (CRP)
[148].
The potential use of CRP acreage to grow corn and soybeans is constrained
by productivity, environmental, and contractual limitations. Nevertheless,
there may be significant opportunities in the future to use some CRP acres
to grow such “low-impact” energy crops as native grasses (switchgrass)
and short-rotation trees (willows or poplars) to generate cellulosic biomass.
Pilot programs are underway in Minnesota, Iowa, New York, and Pennsylvania
to determine whether CRP acres can be used to grow energy crops while preserving
the environmental mandate of the CRP.
Land Use and Productivity
With a limited supply of cropland available for biofuel feedstocks, increasing
yield (bushels per acre) on an annual basis could significantly boost available
supplies of corn and soybeans without requiring additional land. With more
than 81 million acres devoted to corn and nearly 72 million acres devoted
to soybeans (2005 U.S. planted acres), even small increases in annual yield
could boost supplies significantly [149].
There have been large annual increases in yields of both corn and soybeans
over the past 30 years. Corn yields increased from 86.4 bushels per acre
in 1975 to 151.2 bushels per acre in 2006, and soybean yields increased
from 28.9 bushels per acre to 43 bushels per acre over the same period
[150]. If corn yields continue to increase at the same rate (approximately
1.8 bushels per acre per year), production could increase by more than
3.1 billion bushels (29 percent) by 2030 without requiring any additional
acreage. Similarly, soybean production could increase by nearly 1.0 billion
bushels per year by 2030 with no additional acreage requirement if yields
continue to grow at the rate of 0.5 bushels per acre per year [151]. Improvements
in biofuel collection and refining and bioengineering of corn and soybeans
also could contribute to improved biofuel yields. Research on methods to
increase the starch content of corn and the oil content of soybeans is
also ongoing.
Crop Competition
A key uncertainty is the availability of sufficient land resources for
large-scale expansion of the cultivation of biofuel crops, given the intense
competition with conventional agricultural products for arable land. Competition
will favor those crops most profitable for farmers, accounting for such
factors as growing region, farming practice, and soil type. Currently,
corn and soybeans are competitive energy crops, because they provide high
value to farmers at prices low enough to allow the biofuel industry to
produce a product competitive with petroleum fuels.
Cellulosic biomass from switchgrass, hybrid willow and poplar trees, agricultural
residues, and other sources has significant supply potential, possibly
up to 4 times the potential of corn [152]. Switchgrass and poplars could
be grown on CRP lands, where corn cannot be grown economically, but they
would not be competitive with corn until corn prices rose or the capital
and non-feedstock production costs of cellulosic ethanol were significantly
reduced. To expand beyond a production level of 15 to 20 billion gallons
per year without seriously affecting food crop production and prices, the
industry must make a transition to crops with higher yields per acre and
grow crops in an environmentally permissible manner on CRP lands, while
continuing to provide profits for producers.
Role of Co-products in Biofuel Economics
The value of co-products will play a significant role in determining which
crops are most profitable for farmers to grow and biofuel producers to
use. High prices for raw crop material are desirable for farmers but undesirable
for biofuel producers. High prices for co-products, on the other hand,
increase revenues for agricultural processors, sustain high prices for
raw crop materials, and offset feedstock costs for biodiesel producers.
Corn and soybeans not only provide starch and oil for biofuel production
but also generate significant quantities of co-products, such as DDGS,
gluten feed, gluten meal, corn oil, and soybean oil meal with high protein
content (Table 13). As a result, corn grain and soybean oil can be offered
at prices lower than those of other feedstocks, and currently they are
the most competitive biofuel crops.
Co-products of the 3.9 billion gallons of ethanol produced in 2005 were
significant, including 10 million short tons of DDGS, 473,000 short tons
of corn gluten meal, 2.6 million short tons of corn gluten feed, and 283,000
short tons of corn oil [153]. As biofuel production continues to expand
to the level of 7.5 billion gallons per year mandated in EPACT2005, production
of DDGS, used primarily as animal feed, will grow to more than 12 million
short tons annually and may depress prices in the feed market.
Biodiesel production in 2005 was considerably less than ethanol production,
at 90.8 million gallons. Because U.S. biodiesel production currently uses
surplus soybean oil (generated as a co-product in the soybean meal industry),
it has little effect on other markets for soybeans; however, annual production
of 300 to 600 million gallons of biodiesel would begin to compete with
food and feed markets for soybeans [154]. For every 100 pounds of biodiesel
production, about 10 pounds of crude glycerin is generated as a co-product
[155]. The glycerin generated by a 300 to 600 million gallon per year biodiesel
industry could displace nearly one-half of the 692 million pounds of glycerin
produced domestically in North America [156] and result in substantial
oversupply.
Market Effects of Biofuel Growth
The feedstocks used to produce biofuels currently make up only 15 percent
of available crop matter and are located at the end of a long agricultural
supply chain. The markets for biofuels, biofuel co-products, and crop commodities
are linked and susceptible to changes in the prices and availability of
crops. Surging demand for biofuel feedstocks is likely to exert upward
price pressure on corn and soybean commodities and influence export, food,
and industrial feedstock markets, particularly in the short term.
Co-product production also increases with biofuel production. At higher
levels of biofuel production in the future, co-products may be oversupplied,
resulting in depressed prices for the co-products and lower revenues from
their sale to offset fuel production costs. Finding new, high-value uses
for co-products could ensure that market prices for co-products remain
stable. To the extent that other energy crops, such as switchgrass and
inedible oilseeds, could be grown on less productive land (like the CRP),
upward pressure on the prices of corn, soybeans, and other high-value food
crops could also be mitigated.
Some studies have suggested that up to 16 billion gallons of ethanol (slightly
more than 10 percent of the total gasoline pool by volume) can be produced
from corn in 2015 without adversely affecting the price of corn and upsetting
domestic food, feed, and export markets [157]. A growing corn supply—the
result of increasing yields and relatively slow growth in the demand for
corn in the food, feed, and export markets— contributes to stable corn
prices [158]. Between 33 and 38 percent of domestic corn production would
be needed to produce 12 to 16 billion gallons of ethanol in 2015/2016,
as compared with the 14.6 percent of domestic production that was used
for ethanol feedstocks in 2005 [159].
Biofuel Distribution Infrastructure
Another issue that could limit the growth of the U.S. biofuels industry
is development of the necessary infrastructure for collecting, processing,
and distributing large volumes of biofuels. Currently, nearly all U.S.
biofuel production facilities are located close to corn and soybean acreage
in the Midwest, minimizing the transportation costs for bulky, unrefined
materials. The facilities are far from the major biofuel consumption centers
on the East and West Coasts. Further complicating matters is the fact that
biodiesel and ethanol cannot be blended at the refinery and batched through
existing pipelines. Ethanol can easily be contaminated by water, and biodiesel
dissolves entrained residues in the pipelines. As a result, railroad cars
and tanker trucks made from biofuel-compatible materials are needed to
transport large volumes of biofuels to market.
Limited rail and truck capacity has complicated the delivery of ethanol,
contributing to regional ethanol supply shortages and price spikes between
April and June 2006. Feedstock and product transportation costs and concerns
remain problematic for the biofuel industry and have led many biofuel producers
to explore the prospect of locating near a dedicated feedstock supply or
large demand center to minimize transportation costs and susceptibility
to bottlenecks.
Distribution of biofuels to end-use markets is also hampered by a number
of other factors. Although E10 is readily obtainable throughout the United
States, there are limited numbers of fueling stations for biodiesel and
E85 (Table 14). Further, some station owners may be averse to carrying
B20 or E85, because the unique physical properties of the blends may require
costly retrofits to storage and dispensing equipment.
Recent EIA estimates for replacing one gasoline dispenser and retrofitting
existing equipment to carry E85 at an existing fueling station range from
$22,000 to $80,000 (2005 dollars), depending on the scale of the retrofit.
Some newer fueling stations may be able to make smaller upgrades, with
costs ranging between $2,000 and $3,000. Investment in an E85 pump that
dispenses one-half the volume of an average unleaded gasoline pump (about
160,000 gallons per year) would require an increase in retail prices of
2 to 7 cents per gallon if the costs were to be recouped over a 15-year
period. The costs would vary, depending on annual pump volumes and the extent
of the station retrofit. The installation cost of E85-compatible equipment
for a new station is nearly identical to the cost of standard gasoline-only
equipment.
Independent station owners may also be uncomfortable with the relative
novelty of biofuels and the murky regulatory environment that surrounds
their use and distribution at retail locations. For gasoline outlets operated
by major distributors, owners are more likely to be aware of the environmental
regulations and more willing to seek appropriate permits when confronted
with favorable biofuel economics. Awareness of various biofuels is limited,
and station operators will need to post appropriate labels, placards, and
warning signs to ensure that customers put the appropriate fuels in their
vehicles. With the rapid growth and change in the biofuels industry, quality
control programs are also critical to ensure that biofuels meet accepted
quality specifications from the American Society for Testing and Materials
for ethanol (ASTM D4806) and biodiesel (ASTM D6751).
Consumer Demand, Awareness, and Attitudes
Biofuel production capacity is expanding rapidly in response to heightened
market demand resulting from high petroleum prices, favorable tax incentives,
and consumer concerns over environmental and energy security issues. The
market potential for biofuel blends (E10, B5, and B20) remains significantly
larger than current production levels and will continue to absorb the biofuel
supply for the foreseeable future (Table 15). Consumer behavior, however,
will play an increasingly important role in determining demand for biofuels.
Consumer attitudes about fuel prices, relative fuel performance, biofuel-capable
vehicles, and the environment will affect the volume and type of biofuels
sold.
Price, availability, and familiarity are the primary attributes by which
many consumers judge the value of biofuels. Biofuel-rich blends, such as
E85 and B20, are much less common in the United States than are petroleum-rich
blends, such as gasohol (E10). Consistent with economic theories of adoption,
consumers who are generally unfamiliar with biofuels have been hesitant
to use them, even where they are available. On a gallon of gasoline equivalent
basis, biofuels have historically been more expensive than gasoline and
diesel. Because of high prices, low availability, and lack of familiarity,
there has been little consumer demand for biofuels for many years. Current
use of ethanol in E10 blends does not require any explicit consumer choice,
because E10 and conventional gasoline have similar attributes and are rarely,
if ever, offered as alternatives.
Availability of Biofuel Vehicles
The long-term market potential for biofuels will also depend on the availability
of light-duty vehicles capable of using rich biofuel blends. For ethanol
demand to grow beyond the market for E10, fuel containing up to 85 percent
ethanol must be marketed and sold. Although the incremental cost for vehicle
manufacturers to make some models E85-capable at the factory is low (about
$200 per vehicle), virtually all FFVs built since 1992 have been produced
for the sole purpose of acquiring CAFE credits. About 5 million FFVs have
been produced since 1992. There is also no regulatory requirement that
FFVs actually use E85, and buyers often are unaware that they own FFVs.
Currently, ethanol has higher value in the light-duty vehicle fuel market
as a blending component in E10 than as dedicated E85 fuel. Consequently,
the vast majority of the first 16 to 20 billion gallons of ethanol produced
per year is projected to be used in E10. When the E10 market is nearly saturated,
incremental ethanol production would presumably be consumed as E85, displacing
gasoline. The issue is similar for biodiesel. For biodiesel to penetrate
the light-duty vehicle fleet beyond the B10 or B5 blending levels, additional
biofuel-capable vehicles must be produced and marketed to consumers. Higher
consumer demand for biofuels—resulting from evolving market dynamics or
government intervention— would encourage expanded production of biofuel-capable
vehicles by auto manufacturers.
Market Effects of Government Policy
Federal and State government policy and regulation of biofuels will affect
the development of the biofuels industry, both now and in the future. Support
for biofuels has resulted in a number of Federal and State policies aimed
at reducing their cost, increasing their availability, and ensuring continued
market demand during periods of low petroleum prices. The RFS established
by EPACT2005 guarantees a market of 7.5 billion gallons per year for ethanol
by 2012, providing some long-term stability for the industry. In addition,
the blender’s tax credits reduce the cost of biofuels, making them more
competitive with petroleum fuels. Significant funding is also provided
by the Federal Government for research, development, and commercialization
of cellulosic ethanol technology.
State support for biofuels varies, but many States have instituted RFSs,
reduced fuel taxes, and provided grants and loans for distribution infrastructure.
Hawaii, Iowa, Louisiana, Minnesota, Missouri, Montana, and Washington have
enacted standards specifying that transportation fuels sold in the State contain a minimum
percentage of either ethanol or biodiesel [160], and similar legislation
has been proposed in California, Colorado, Idaho, Illinois, Indiana, Kansas,
New Mexico, Pennsylvania, Virginia, and Wisconsin.
Government support has fueled the rapid growth of the biofuel industry
and may have reduced long-term risk for biofuel investments. Changes in
laws and regulations can have large impacts on the sector. Preliminary
discussions surrounding the 2007 Farm Bill indicate that the final version
may contain significant provisions related to the role of energy crops
in the agricultural sector and how CRP lands can be used [161]. The Federal
and State RFS programs may be revised as more experience is gained in their
implementation and to accommodate shifts in the political and economic
environment. If R&D efforts on cellulosic ethanol significantly reduce
the costs of biofuels, tax and regulatory policy may need to be changed
to accommodate new market realities.
Finally, Federal and State budgetary issues could affect gasoline taxes
and the blender’s tax credit. At levels of 16 billion gallons of ethanol
and 1 billion gallons of biodiesel, the loss of Federal revenue as a result
of the blender’s tax credit would be roughly $8 billion for ethanol and
$1 billion for biodiesel in nominal terms, as compared with a current total
loss of about $2.4 billion. Increasing budgetary impacts may lead to future
reconsideration of the subsidy levels.
Tables 3 thru 15
Issues in Focus Section Notes |
