Natural Gas Demand
Natural Gas Prices Rise As More Expensive Resources Are Produced
Average lower 48 wellhead prices for natural gas generally increase in
the reference case, as more expensive domestic resources are used to meet
demand. Prices decline for a brief period after the Alaska pipeline begins
operation in 2020, but the market quickly absorbs the additional natural
gas supplies from Alaska, and prices resume their rise (Figure 64).
Henry Hub spot market prices and delivered end-use natural gas prices generally
follow the trend in lower 48 wellhead prices; however, delivered prices
also are subject to variation in average transmission and distribution
rates and resulting margins, as reflected in the difference between the
average delivered price and the average supply price for natural gas. Some
new pipelines are built to bring supplies to market and to reach new customers,
but the bulk of the pipeline system is already in place, and revenue requirements
for those segments decline as capital is depreciated. Consequently, transmission
and distribution margins for natural gas delivered to the industrial and
electric power sectors either remain flat or decline.
Natural gas distribution rates are determined in large part by consumption
levels per customer, which decline in the residential and commercial sectors
over the projection period. As a result, fixed costs are distributed over
a smaller customer base, leading to slight increases in transmission and
distribution margins in those sectors. In the transportation sector, transmission
and distribution margins for natural gas used as fuel in CNG vehicles decline
in real terms, as motor fuels taxes remain constant in nominal terms.
Prices Vary With Economic Growth and Technology Progress Assumptions
The extent to which natural gas prices increase in the AEO2009 reference
and alternative cases depends on assumptions about economic growth rates
and the rate of improvement in natural gas exploration and production technologies.
Technology improvements reduce drilling and operating costs and expand
the economically recoverable resource base.
Technology improvement is particularly important in the context of growing
investment in production of natural gas from shale formations, which generally
can be produced more efficiently than the natural gas contained in conventional
formations, but which require relatively high capital expenditures. The
reference case assumes that annual technology improvements follow historical
trends. In the rapid technology case, exploration and development costs
per well decline at a faster rate, which allows for more growth in production.
More rapid technology improvement puts downward pressure on natural gas
prices, mitigated somewhat by higher levels of consumption than in the
reference case. In the slow technology case, slower declines in exploration
and development costs lead to higher natural gas prices than in the reference
case.
In the AEO2009 high economic growth case, natural gas consumption grows
more rapidly, and natural gas prices rise more sharply, than in the reference
case. In the low economic growth case, natural gas consumption grows more
slowly, and natural gas prices are lower, than in the reference case (Figure
65).
Largest Source of U.S. Natural Gas Supply Is Unconventional Production
From 2007 to 2030, total natural gas production in
the reference case increases by more than 4 trillion
cubic feet,, even as onshore lower
48 conventional production (from smaller and deeper deposits) continues
to taper off. Unconventional natural gas is the largest contributor to
the growth in U.S. natural gas production, as rising prices and improvements
in drilling technology provide the economic incentives necessary for exploitation
of more costly resources. Unconventional natural gas production increases
from 47 percent of the U.S. total in 2007 to 56 percent in 2030 (Figure
66).
Natural gas in tight sand formations is the largest source of unconventional
production, accounting for 30 percent of total U.S. production in 2030,
but production from shale formations is the fastest growing source. With
an assumed 267 trillion cubic feet of undiscovered technically recoverable
resources, production of natural gas from shale formations increases from
1.2 trillion cubic feet in 2007 to 4.2 trillion cubic feet, or 18 percent
of total U.S. production, in 2030. The expected growth in natural gas production
from shale formations is far from certain, however, and continued exploration
is needed to provide additional information on the resource potential.
Offshore production also makes up a significant portion of domestic natural
gas supply, accounting for 15 percent of total domestic production in 2007
and 21 percent in 2030. The increase in offshore production is largely
from deepwater formations and OCS areas recently released from Congressional
moratoria.
World Oil Prices and Technology Progress Affect Natural Gas Supply
Improvements in natural gas exploration and development technologies reduce
drilling costs, increase production capacity, and ultimately lower wellhead
prices, increasing both production levels and end-use consumption. More
rapid technology improvement raises the potential level of natural gas
production and offsets the effects of depletion of the resource base, particularly
for onshore conventional resources. In the rapid technology case, natural
gas production in 2030 is 1.4 trillion cubic feet higher than in the reference
case; in the slow technology case, it is 1.5 trillion cubic feet lower
than in the reference case.
The impact of world oil prices on domestic natural gas production is indirect,
affecting natural gas consumption and, to a lesser degree, LNG imports.
In the high oil price case, natural gas production in 2030 is 1.7 trillion
cubic feet higher than in the reference case (Figure 67), with most of
the additional supply, 1.2 trillion cubic feet, being used for GTL production.
In addition, higher oil prices reduce liquids consumption, leading to a
decline in crude oil processing at refineries, so that more natural gas
is consumed at refineries to replace still gas that otherwise would be
available for refinery use. Higher levels of natural gas consumption for
CTL production and refinery use in the high price case are offset to some
extent by a decline in natural gas use for electricity generation.
In the low oil price case, refineries use less natural gas. Also, with
less expensive crude oil taking a larger share in world energy markets,
more natural gas is available for export to the United States as LNG. Domestic
natural gas production is therefore lower, and LNG imports are higher,
than in the reference case.
U.S. Net Imports of Natural Gas Decline in the Projection
U.S. net imports of natural gas decline in the AEO2009 reference case from
16 percent of supply in 2007 to 3 percent in 2030. The reduction is a result
primarily of lower imports from Canada and higher exports to Mexico because
of growing demand for natural gas in each of those countries. In addition,
with relatively high prices and advances in technology, the potential for
U.S. domestic natural gas production (particularly from unconventional
sources) increases, providing a competitive alternative to imports of LNG.
Conventional natural gas production from Canada’s Western Sedimentary Basin
has been declining in recent years. In the reference case, Canada’s unconventional
production does not increase rapidly enough to keep up with domestic demand
growth while maintaining current export levels. For Mexico, U.S. pipeline
exports are needed to meet the country’s growth in demand for natural gas,
which is not matched by increases in domestic production and LNG imports.
In the United States, LNG imports peak at 1.5 trillion cubic feet in 2018
before declining to 0.8 trillion cubic feet in 2030 (Figure 68), despite
projected U.S. regasification capacity of 5.2 trillion cubic feet. The
near-term increase is the result of growth in world liquefaction capacity,
which temporarily exceeds world demand, making LNG available to the U.S.
market— particularly in the summer to fill storage facilities. In the longer
term, high LNG prices (which are tied to oil prices in many markets) and
ample domestic natural gas supplies reduce U.S. demand for LNG imports;
however, the amount of LNG available to U.S. markets could change if world
natural gas consumption differs from the levels projected in the reference
case.
With No Alaska Pipeline, Lower 48 Prices for Natural Gas Are Higher
The AEO2009 reference case assumes that a proposed pipeline to transport
natural gas from Alaska’s North Slope to Alberta, Canada, and ultimately
to the lower 48 States will be built in 2020, and that Alaska’s natural
gas production will increase by 1.6 trillion cubic feet as a result. The
no Alaska pipeline case assumes that the pipeline will not be built, leading
to higher prices in lower 48 natural gas markets, more lower 48 production
and imports of natural gas, and lower consumption.
The largest impact on natural gas prices in the no Alaska pipeline case
occurs when the pipeline reaches full capacity in 2022, two years after
the pipeline begins operating in the reference case. In 2022, Henry Hub
spot market prices for natural gas (in 2007 dollars) are higher by $0.63
per thousand cubic feet in the no Alaska pipeline case than in the reference
case. After 2022 the price impact lessens gradually, to $0.13 per thousand
cubic feet in 2030 (Figure 69). In 2026, total natural gas consumption
is 0.8 trillion cubic feet lower in the no pipeline case than in the reference
case, and consumption for electricity generation is 0.3 trillion cubic
feet lower.
Higher natural gas prices and reduced supply in the no pipeline case lead
to more unconventional production and LNG imports in the lower 48 States.
Pipeline imports from Canada, which in the no pipeline case do not compete
with Alaska natural gas in lower 48 markets, are 0.5 trillion cubic feet
above the reference case level in 2028. LNG imports are only slightly higher
in the no pipeline case, as a result of increased competition in world
markets and the availability of domestic natural supplies at competitive
prices.
U.S. Crude Oil Production Increases With Rising Oil Prices
The long-term decline in total U.S. crude production has slowed over the
past few years, as higher world oil prices have spurred drilling. In the
projections, total U.S. domestic crude oil production, which has been falling
for many years, begins to increase in 2009. Most of the near-term increase
is from the deepwater offshore. Growth is limited after 2010, however,
because newer discoveries are smaller, and capital expenditures rise as
development moves into deeper waters.
A number of deepwater discoveries in the Gulf of Mexico have begun to ramp
up production recently or are expected to begin production by the end of
2009. The largest include Shenzi, Atlantis, Blind Faith, and Thunder Horse.
Expiration of the Congressional moratoria on the Eastern Gulf of Mexico,
Atlantic, and Pacific regions of the OCS also allow crude oil production
to increase in the Atlantic and Pacific OCS after 2014 and in the Eastern
Gulf of Mexico OCS after 2025. Total offshore production increases at an
average annual rate of 2.8 percent, from 1.4 million barrels per day in
2007 to 2.7 million barrels per day in 2030.
U.S. onshore crude oil production also increases throughout the projection,
primarily as a result of increased application of CO2-enhanced oil recovery
techniques, exploitation of oil from the Bakken shale formation [98], and
the startup of liquids production from oil shale, which is supported by
favorable world oil prices and continued advances in oil shale extraction
technology. Total onshore production of crude oil increases from 2.9 million
barrels per day in 2007 to 4.1 million barrels per day in 2030 (Figure
70).
U.S. Oil Production Depends on Prices, Access, and Technology
U.S. crude oil production is highly sensitive to world crude oil prices,
because the remaining domestic resource base generally requires more costly
secondary or tertiary recovery techniques, which are likely to be uneconomical
when world oil prices are low. Even when prices are higher, however, high-cost
projects typically involve long lead times from discovery to production,
which limit their impact on total production levels. In the high oil price
case, U.S. crude oil production in 2030 is 1.1 million barrels per day higher
than in the reference case, mostly as a result of increased production from
onshore CO2-enhanced oil recovery projects and offshore deepwater projects.
In the low oil price case, crude oil production in 2030 is 2.0 million
barrels per day lower than in the reference case, primarily because of
lower production from CO2-enhanced recovery projects, and because fewer
projects in the lower 48 offshore and Alaska’s North Slope are economical
when world oil prices are relatively low.
Both onshore and offshore production generally increase as technology advances
reduce the costs of exploration and development. In the rapid technology
case, U.S. crude oil production in 2030 is 0.3 million barrels per day
higher than in the reference case, with most of the increase coming from
resources in the lower 48 offshore. In the slow technology case, crude
oil production in 2030 is 0.7 million barrels per day lower than in the
reference case (Figure 71). Most of the difference between the 2030 production
levels in the reference and slow technology cases results from lower levels
of production from CO2-enhanced oil recovery in the slow technology case.
BTL, CTL, and Oil Shale Production Grows With Technology Improvement
Production of liquid fuels from oil shale, coal, natural gas, and biomass
becomes viable over time in the reference case as a result of continued
technology improvements and rising oil prices. Growth in their production
can be moderated, however, by rising capital costs and by the enactment
of more stringent environmental regulations affecting water and land use—which
increase production costs—and GHG emissions. Consequently, penetration
rates vary for the different production processes.
BTL production begins in 2012 in the reference case and grows by an average
of 29 percent per year through 2030 (Figure 72). CTL production begins
in 2011 and grows by an average of 19 percent per year. The increase in
CTL production would be larger if it were not constrained by the reference
case assumption that growing concern about GHG emissions will limit investment
in the carbon-intensive CTL technology.
Oil shale production begins later, in 2023, but increases rapidly, averaging
35 percent per year from 2023 to 2030. Research and development efforts
are expected to provide the necessary technology improvements to yield
commercial quantities of liquids from oil shale production that, over time,
can be further increased in scale. Although no GTL production is expected
before 2030 in the reference case, GTL production in Alaska begins in 2017
in the high oil price case and then grows by an average of 21 percent per
year from 2017 to 2030.
Transportation Sector Dominates Liquid Fuels Consumption
The transportation sector continues to dominate liquid fuels consumption
in the projections (Figure 73), with large increases in the use of diesel
fuel and biofuels. In the reference case, total consumption of petroleum-based
motor gasoline in 2030, including E10 but excluding E85, is 1.3 million
barrels per day below the 2007 total, whereas both consumption of diesel
fuel and consumption of E85 increase, by about 1.5 million barrels per
day each. Biofuel consumption grows with the EISA2007 mandates, and diesel
fuel consumption expands as more light-duty diesel vehicles are produced
by automotive manufacturers seeking to comply with new CAFE standards.
Diesel fuel use for freight trucks also increases as industrial output
expands.
In the other sectors, liquid fuels consumption declines through 2030. Industrial
use of liquids drops by 19 percent, despite a 47-percent increase in industrial
shipments. Much of the decline from 2007 to 2030 results from changes in
the chemical industry, where there is a shift in the production mix, and
energy efficiency improves. Liquid fuels consumption in the buildings sector
continues to fall, as fewer buildings use oil for heating, and efficiency
improves as older systems are replaced with more efficient equipment.
Liquid fuels consumption in the electric power sector declines as a result
of slowing growth in demand for electricity from 2007 to 2030. With Federal
and State efficiency standards minimizing the need for new generating capacity,
little new oil-fired capacity is installed, and generation from older oil-fired
capacity is offset by production from new capacity using coal, natural
gas, nuclear, and renewable fuels.
EISA2007 RFS Mandate for 2022 Is Met in 2027
EISA2007 mandates a total RFS credit requirement of 36 billion gallons
in 2022. Credits are equal to gallons produced, except for fatty acid methyl
ester biodiesel and BTL diesel, which receive a 1.5-gallon credit for each
gallon produced. The renewable fuels can be grouped into two categories:
conventional biofuels (ethanol produced from corn starch) and advanced
biofuels (including cellulosic ethanol, biodiesel, and BTL diesel). In
total, 15 billion gallons of credits from conventional biofuels and 21
billion gallons from advanced biofuels are required in 2022.
In the AEO2009 reference case, the credit requirement for conventional
biofuels is met in 2022, but the requirement for advanced fuels is not.
In that event, EISA2007 provides for both the application of waivers and
modification of applicable credit volumes. The RFS mandates are achieved
in 2027 in the reference case, and as BTL production grows, the overall
target of 36 billion gallons is exceeded in 2030 (Figure 74).
Progress toward meeting the RFS is complicated by slowing growth in U.S.
petroleum use through 2030. The push for more fuel-efficient automobiles,
which slows the increase in motor gasoline consumption in the reference
case, also slows progress toward meeting the RFS, because more efficient
gasoline engines and growing penetration of hybrids reduce the demand for
ethanol in gasoline fuel blends. A 10-percent limit on ethanol in gasoline
for most of the current fleet of passenger vehicles delays further market
penetration until more E85-compatible vehicles are in use and the market
infrastructure for E85 and other biofuels is expanded to accommodate the
distribution and sale of growing volumes.
Biofuels Displace Conventional Fuels in the Transportation Mix
As a result of the RFS in EISA2007, CAFE standards, and higher liquid prices,
biofuels in the form of ethanol and biodiesel displace a growing portion
of the fossil fuel component of transportation fuel use in the reference
case (Figure 75). With biofuels representing all the growth in motor fuel
supply, there is virtually no growth in petroleum consumption through 2030,
as demand for petroleum-based gasoline declines and demand for petroleum-based
diesel grows modestly. The growing share for diesel fuel is similar to
recent trends in Europe, where increases in diesel use have outpaced the
growth in gasoline use for some time, causing European refineries to be
reconfigured for more diesel production.
U.S. production of biofuels grows from less than 0.5 million barrels per
day in 2007 to 2.3 million barrels per day in 2030. Ethanol production
provides the largest share of that growth, as ethanol use for gasoline
blending grows to more than 0.8 million barrels per day and ethanol consumption
in E85 increases to 1.1 million barrels per day in 2030. Much of the growth
in demand for E85 occurs after 2015, when the market for E10 blending is
saturated. Although most of the ethanol consumed is produced domestically,
net imports of ethanol also increase, to 0.5 million barrels per day in
2030.
To meet RFS and CAFE standards, the vehicle fleet changes dramatically
in the reference case. In 2030, 60 percent of the new LDVs sold are E85,
flex-fuel, conventional hybrid, or PHEVs.
Ethanol Prices Compete on a Btu Basis To Meet the EISA2007 RFS
With crude oil prices rising in the reference case, prices for both gasoline
and diesel fuel increase by an average of 1.4 percent per year, to about
$4 per gallon (2007 dollars) in 2030 (Figure 76). The average increase
in E85 prices is 0.5 percent per year over the same period, and the E85
price in 2030 is less than $3 per gallon. As a result, the difference between
gasoline and E85 prices increases from roughly 30 cents per gallon in 2007
to more than a dollar per gallon in 2030.
In the reference case, ethanol is used initially as a blending component
with gasoline, but the U.S. market for ethanol blending with gasoline to
make E10 is near saturation by 2012. Meeting the EISA2007 RFS after 2012
therefore requires increased consumption of E85. To encourage the use of
E85, its price (in terms of energy content) must be equivalent to or below
the price of motor gasoline. E85 prices increase only moderately in the
reference case, to $2.72 per gallon in 2012 and $2.79 in 2022, on the path
to achieving the sales volume needed to meet the RFS mandate.
The increase in ethanol sales requires construction of a sufficient base
of E85 fueling stations and distribution infrastructure to ensure the commercial
viability of a growing fleet of E85 vehicles. AEO2009 assumes that the
average cost to modify an existing service station for E85 sales will be
about $46,000. Assuming no intermediate ethanol blends, E85 prices must
be subsidized by refiners and marketers through high prices for gasoline
and diesel fuel in order to meet the mandated ethanol level in the RFS
once the E10 market is saturated and E85 is the primary contributor.
Imports of Liquid Fuels Vary With World Oil Price Assumptions
U.S. imports of liquid fuels, which grew steadily from the mid-1980s to
2005, decline sharply from 2007 to 2030 in the reference and low oil price
cases, even as they continue to provide a major part of total U.S. liquids
supply. Increasing use of biofuels, much of which are domestically produced,
tighter CAFE standards, and higher energy prices moderate the growth in
demand for liquids. A combination of higher prices and mandates leads to
increased domestic production of oil and biofuels. In the reference case,
there is essentially no growth in the use of liquid fuels from 2007 to
2030.
The net import share of U.S. liquid fuels consumption fell from 60 percent
in 2005 to 58 percent in 2007. That trend continues in the reference case,
with a net import share of 41 percent in 2030, and in the high oil price
case, with a 30-percent share in 2030. In the low price case, the net import
share falls in the near term before rising to 57 percent in 2030. With
lower prices for liquid fuels, demand increases while domestic production
decreases, and more imports are needed to meet demand. With higher prices,
the need for imports is smaller but still substantial (Figure 77). Increased
penetration of biofuels in the liquids market reduces the need for imports
of crude oil and petroleum products in the high price case.
Market Trends End Notes |
