Over the 1995-2005 period, crude oil prices and U.S. natural gas prices tended to move together, which supported the conclusion that the markets for the two commodities were connected. Figure 26 illustrates the fairly stable ratio over that period between the price of low-sulfur light crude oil at Cushing, Oklahoma, and the price of natural gas at the Henry Hub on an energy-equivalent basis.
The AEO2010 Reference and High Oil Price cases, however, project a significantly longer and persistent disparity between the relative prices of low-sulfur light crude oil and natural gas on an energy-equivalent basis. The apparent disconnect in prices between seemingly similar commodities varies over a wide range between 2010 and 2035. Over much of the projection period in the Reference case, the crude oil price is about 2.8 times the natural gas price on an energy equivalent basis—115 percent higher than the historical average price ratio of 1.3 from 1995 to 2005. In the High Oil Price case, the ratio widens to as much as 4.8; in the Low Oil Price case, it narrows from nearly 3.0 in 2009 to 1.1 in 2035.
Such an apparent lack of responsiveness of natural gas prices to changes in crude oil prices in all cases reflects the changes that have occurred in the underlying uses of the two commodities. The divergence of crude oil and natural gas markets also reflects the fact that opportunities for the substitution of natural gas for crude oil products are limited by the large infrastructure investments that would be required to allow substitution on a significant scale and bring the prices of the two commodities closer together in the U.S. market in the Reference and High Oil Price cases. In the absence of such investments, EIA expects the gap between oil and natural gas prices in U.S. energy markets to remain wide.
Opportunities to substitute natural gas for petroleum
In the United States, the capability to substitute natural gas supplies directly for petroleum, particularly in the electric power sector, has eroded over time. In 1978, 4.0
quadrillion Btu of petroleum was consumed to produce electricity, representing nearly 17 percent of total energy use for U.S. electricity generation, as compared with 14 percent for
natural gas. In 2008, only 0.5 quadrillion Btu of petroleum was consumed for electricity generation, representing 1.2 percent of total energy use for generation, while natural gas
has grown to 17 percent of generation. The trend has been similar in the commercial and industrial sectors where there are a declining number of opportunities to substitute natural gas
Still, there are potential opportunities for natural gas to displace petroleum. First, direct use of natural gas in the U.S. transportation sector could provide an opportunity for substitution. Second, natural gas could be exported to countries where petroleum is widely used for thermal applications. Third, natural gas can be converted directly to petroleum-like liquid fuels that could be substituted for diesel and gasoline in the existing vehicle fleet using the existing distribution infrastructure.
The physical properties of natural gas are such that it is more difficult and costly than liquid fuels to transport and consume. As shown in Figure 27, the energy density of
natural gas is much lower than that of most liquid fuels. To match the energy equivalent of a 1-gallon container of diesel fuel, a balloon of natural gas at atmospheric pressure would
have to be nearly a thousand times larger than the gallon container. At a pressure of 3,600 pounds per square inch (psi), however, which is the pressure rating for the fuel tanks used in
CNG vehicles, only 4 times as much space is required to match the energy equivalent of 1 gallon of diesel fuel. And when the gas is converted to LNG by chilling to about -260
degrees Fahrenheit, its energy density increases to the point where it requires only 50 percent more volume to match the energy content of diesel fuel. However, the materials used for the
handling and storage of LNG differ significantly from those used for CNG or petroleum-like liquid fuels.
An expanded market for CNG or LNG would require additional investment in vehicles and infrastructure for compression and storage of CNG or for liquefaction and storage of LNG. Some of the issues, challenges, and opportunities surrounding the use of natural gas as a substitute for diesel fuel are described in the Issues in Focus section, “Natural gas as a fuel for heavy trucks: Issues and incentives.”
Barriers to U.S. exports of LNG
World crude oil and natural gas prices could converge if barriers to the flow of natural gas between U.S. and world markets were eliminated through the combined use of the existing pipeline network, existing LNG terminals, and investment in new U.S. LNG liquefaction capacity (and possibly LNG tankers) to allow exports of U.S. natural gas when it is economical. Currently, there is one liquefaction facility in Alaska that exports LNG from the United States. Investment in new U.S. liquefaction capacity would face significant risk, however, because there are large quantities of “stranded gas” in remote regions of the world that can be priced well below the expected cost of resources in the lower 48 States.
Potential for production of liquid fuels from natural gas
Another opportunity to substitute natural gas for crude oil would be to convert it to petroleum-like liquid products similar to gasoline and diesel fuel, for use in the liquid fuel infrastructure and end-use equipment. Such a transformation is possible through use of the GTL process.
There are several GTL processes, the best known using a Fischer-Tropsch reactor. The reactor produces a paraffin wax that is hydrocracked to form liquid products that resemble
petroleum liquids. Distillates, including diesel, heating oil, and jet fuel, are the primary products, making up 50 to 70 percent of the total volume produced, and naphtha usually
represents about 25 percent of the volume. The process efficiency is about 57 percent (43 percent of the energy content of the natural gas is lost in the process). Thus, the price ratio
of liquid products to natural gas would have to exceed about 1.8 to justify operation of the plant, excluding consideration of other operating costs and the cost of capital
investment. To appreciate the price risk faced by investors, one can consider the effects of recent fluctuations in energy prices on investments in U.S. natural gas turbine and
combined-cycle generating units and ethanol production facilities. Indeed, AEO2010 examines the potential impacts of lower energy prices in the Low Oil Price case, which shows the
ratio of crude oil prices to natural gas prices declining to 1.1 in 2035, indicating that if any GTL plants were built they would not be operated under those price conditions.
The technologies and equipment used in the best-known GTL technology are similar to those that have been employed for decades in methanol and ammonia plants, and most are relatively mature; however, the scale on which previous GTL plants have been implemented is relatively small. The newest GTL plants have been expanded to much larger sizes, including one in excess of 100,000 barrels per day, to take advantage of economies of scale, but recent attempts to build projects at those larger sizes have encountered technology or project execution risks. Currently, there are four GTL plants in operation worldwide, with 96,200 barrels per day of total capacity. In addition, two projects with 174,000 barrels per day of capacity are under construction or ready for startup. However, the construction of GTL plants at sites with available stranded gas reserves has been limited, indicating investor reluctance to pursue this option fervently, especially when investments in less capital-intensive LNG capacity are possible. Indeed, some GTL projects have been canceled or deferred in the past few years.
The overnight capital costs for a new GTL plant situated on the U.S. Gulf Coast would range from $50,000 per barrel-stream day of capacity to an estimated $104,000 per barrel-stream day. Accordingly, a relatively modest unit with a capacity of 34,000 barrels per day represents an estimated overnight capital cost of $1.7 billion to $3.5 billion. With financing included, the estimated total investment would be $2.2 billion to $4.4 billion. In addition, construction of the facility would take 4 years or more, imposing further market risk. The risk-adjusted discount factor used by investors will be critical to determining whether investors would proceed with GTL investments.
Figure 28 shows the maximum “breakeven” average price of natural gas that could be tolerated over a 10-year plant operating period in order to justify the risk associated with investing in a GTL facility, based on the range of capital costs discussed above and a 10-percent hurdle rate . Profitable cases lie below the line. At $100 per barrel for crude oil, the breakeven price for natural gas that would justify investment in a GTL facility is -$1.20 to $5.80 per million Btu. At higher crude oil prices, the range of the breakeven natural gas price also rises. At a crude oil price of $200 per barrel, the breakeven price for natural gas is $10.20 to $17.30 per million Btu. At a crude oil price of $60 per barrel, the breakeven natural gas price ranges from -$5.80 to $1.30 per million Btu, illustrating the substantial impact of oil price uncertainty on the profitability of investment in a GTL facility.
Figure 28 also shows how investment in a GTL facility would fare with the natural gas and crude oil price projections in the AEO2010 Reference, Low Oil Price, and High Oil Price cases. With the prices in the Low Oil Price case, GTL is a poor investment. With the prices in the Reference case, GTL is a marginal investment. Only with the highest prices in the Reference case and the low end of GTL plant costs do the breakeven economics favor the project. In the High Oil Price case, however, the combination of higher crude oil prices and lower natural gas prices implies that investment in a GTL plant on the U.S. Gulf Coast could be profitable.
A large investment in GTL would be needed in order to produce an appreciable effect on worldwide prices for crude oil and U.S. natural gas. Construction of sufficient new GTL
capacity to affect world crude oil prices, about 1 million barrels per day, would require a total investment between $50 billion and $135 billion. That level of capacity would still
represent only 1.2 percent of the 85.9 million barrels per day of the world’s estimated total liquids production in 2007, and less than 1 percent of projected 2035 production in the
Another option is the potential use of stranded natural gas in Alaska to produce GTL. Because of Alaska’s severe weather conditions, construction of GTL (or any other) facilities is likely to be much more expensive than the construction of GTL plants on the U.S. Gulf Coast or in the Middle East. Some estimates suggest that doubling the construction costs and extending the construction period by at least 2 years would be reasonable assumptions. Construction of GTL facilities in Alaska, therefore, seems unlikely given the cost uncertainties mentioned above and the crude oil price projections in the AEO2010
A large disparity between crude oil and natural gas prices, as projected in the AEO2010 Reference and High Oil Price cases, will provide incentives for innovators and entrepreneurs to pursue opportunities that, in the longer term, could increase domestic or international markets for U.S. natural gas. For example, a scenario with relatively high oil prices would tend to increase the value of CO2 used for EOR as well as GTL production. Because GTL processing plants can accommodate natural gas feedstocks with relatively high CO2 content and can target fields smaller than those required for LNG production, such circumstances would provide incentives for the development of smaller GTL systems that produce both liquid products and a valuable CO2 co-product. Because EIA cannot predict whether or when such innovations might arise, they are not included in the AEO2010 analysis cases.
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