U.S. Natural Gas Exports: New Opportunities, Uncertain Outcomes

Michael Ratner
Specialist in Energy Policy


Paul W. Parfomak
Specialist in Energy and Infrastructure Policy


Ian F. Fergusson
Specialist in International Trade and Finance


Linda Luther
Analyst in Environmental Policy


As estimates for the amount of U.S. natural gas resources have grown, so have the prospects of rising U.S. natural gas exports. The United States is expected to go from a net importer of natural gas to a net exporter by 2020. Projects to export liquefied natural gas (LNG) by tanker ship have been proposed—cumulatively accounting for about 12.5% of current U.S. natural gas production—and are at varying stages of regulatory approval. Projects require federal approval under Section 3 of the Natural Gas Act (15 U.S.C. §717b), with the U.S. Department of Energy’s Office of Fossil Energy and the Federal Energy Regulatory Commission being the lead authorizing agencies. Pipeline exports, which accounted for 94% of all exports of U.S. produced natural gas in 2010, are also likely to rise.

What effect exporting natural gas will have on U.S. prices is the central question in the debate over whether to export. A significant rise in U.S. natural gas exports would likely put upwards pressure on domestic prices, but the magnitude of any rise is currently unclear. There are numerous factors that will affect prices: export volumes, economic growth, differences in local markets, and government regulations, among others. With today’s natural gas prices relatively low compared to global prices and historically low for the United States, producers are looking for new markets for their natural gas. Producers contend that increased exports will not raise prices significantly as there is ample supply to meet domestic demand, and there will be the added benefits of increased revenues, trade, and jobs, and less flaring. Consumers of natural gas, who are being helped by the low prices, fear prices will rise if natural gas is exported.

Electric power generation represents potentially the greatest increase in natural gas consumption in the U.S. economy, primarily for environmental reasons. Natural gas emits much less carbon dioxide and other pollutants than coal when combusted. Other types of consumption are not likely to increase natural gas demand domestically for a long time. Use in the transportation sector to displace oil is likely to be small because expensive new infrastructure and technologies would be required. There is discussion of a possible revival of the U.S. petrochemicals sector, but the potential extent of a change is unclear.

Getting natural gas to markets where it can be consumed, whether domestically or internationally, may be the industry’s biggest challenge. Infrastructure constraints, environmental regulations, and other factors will influence how the market adjusts to balance supply and demand.

Environmental groups are split regarding natural gas use, with some favoring increased use to curb emissions of certain pollutants, while others oppose expanded use of natural gas because it is not as clean as renewable forms of energy, such as wind or solar. The use of hydraulic fracturing to produce shale gas has also raised concerns among environmental groups particularly concerned with its possible impacts on water quality.

The possibility of a significant increase in U.S. natural gas exports will factor into ongoing debates on the economy, energy independence, climate change, and energy security. As the proposed projects continue to develop, policymakers are likely to receive more inquiries about these projects. Proposals to expedite and expand LNG exports have already been raised in the 113th Congress, including in S. 192 and H.R. 580. Two other bills, H.R. 1189 and H.R. 1191, would reform the DOE’s process for determining the public interest regarding LNG exports and prohibit exports of natural gas produced on federal lands.

Date of Report: April 8, 2013
Number of Pages: 30
Order Number: R42074
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Keystone XL Pipeline Project: Key Issues

Paul W. Parfomak
Specialist in Energy and Infrastructure Policy

Robert Pirog
Specialist in Energy Economics

Linda Luther
Analyst in Environmental Policy

Adam Vann
Legislative Attorney

TransCanada’s proposed Keystone XL Pipeline would transport oil sands crude from Canada and crude produced in North Dakota and Montana to a market hub in Nebraska for further delivery to Gulf Coast refineries. The proposed pipeline would consist of 875 miles of 36-inch pipe with the capacity to transport 830,000 barrels per day. Because it would cross the Canadian-U.S. border, construction of Keystone XL requires a Presidential Permit from the State Department. A decision to issue or deny a Presidential Permit is based on a determination that a project would serve the national interest, considering potential impacts on the environment, the economy, energy security, foreign policy, and other factors. Environmental impacts are evaluated and documented in an Environmental Impact Statement (EIS) under the National Environmental Policy Act (NEPA).

TransCanada originally applied for a Presidential Permit for the Keystone XL Pipeline in 2008. The initial proposal included a southern segment from Oklahoma to the Gulf Coast. After a final EIS for the original project was released in August 2011, the State Department began a 90-day public review period to make its national interest determination. A key issue that arose during this review was concern over environmental impacts in the Sand Hills region of Nebraska. This concern led the Nebraska legislature to enact new state pipeline siting requirements that would alter the pipeline route through Nebraska. In January 2012, the State Department concluded that it would not have sufficient information to evaluate an altered pipeline route before a deadline imposed by Congress and denied the permit. The southern segment of the original Keystone XL proposal, now called the Gulf Coast Project, was subsequently separated from the original proposal because it did not require a Presidential Permit. It has been approved by the relevant states and is currently under construction.

In May 2012, TransCanada reapplied to the State Department for a Presidential Permit to build the northern, cross-border segment of Keystone XL. The new permit application initiated a new NEPA process. The governor of Nebraska approved a new route through the state avoiding the Sand Hills on January 22, 2013. On March 6, 2013, notice was published in the Federal Register that the State Department draft EIS for the reconfigured Keystone XL Project was available for public comment until April 22, 2013. Public comments must be addressed by the State Department before a final EIS can be issued. After that, the 90-day public review period for the national interest determination begins.

Development of the Keystone XL Pipeline has been controversial. Proponents base their arguments supporting the pipeline primarily on increasing the diversity of the U.S. petroleum supply and economic benefits, especially jobs. Pipeline opposition stems in part from concern regarding the greenhouse gas emissions associated with the development of Canadian oil sands, continued U.S. dependency on fossil fuels, and the risk of a potential release of heavy crude. The Energy Production and Project Delivery Act of 2013 (S. 17), the Keystone for a Secure Tomorrow Act (H.R. 334), a bill to approve the Keystone XL Pipeline (S. 582), and the Northern Route Approval Act (H.R. 3) would all effectively approve the Keystone XL Pipeline. The Strategic Petroleum Supplies Act (S. 167) would suspend sales of petroleum products from the Strategic Petroleum Reserve until the pipeline is approved. On March 22, 2013, the Senate passed an amendment to the Fiscal 2014 Senate Budget Resolution (S.Con.Res. 8) that would provide for the approval and construction of the Keystone XL Pipeline (S.Amdt. 494).


Date of Report: April 9, 2013
Number of Pages: 44
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Alternative Fuels and Advanced Technology Vehicles: Issues in Congress

Brent D. Yacobucci
Section Research Manager

Alternative fuels and advanced technology vehicles are seen by proponents as integral to improving urban air quality, decreasing dependence on foreign oil, and reducing emissions of greenhouse gases. However, major barriers—especially economics—currently prevent the widespread use of these fuels and technologies. Because of these barriers, and the potential benefits, there is continued congressional interest in providing incentives and other support for their development and commercialization.

Key tax incentives for the use of biofuels, for the expansion of alternative fuel infrastructure, and for the purchase of certain electric vehicles expired at the end of 2011, along with an added duty on certain ethanol imports. Some of these incentives were extended through the end of 2013 although the main tax credit for conventional ethanol—the Volumetric Ethanol Excise Tax Credit (VEETC)—was not extended.

While tax incentives for these fuels have expired or are set to expire at the end of 2013, a mandate to use biofuels in transportation that was expanded by the Energy Independence and Security Act of 2007 (EISA, P.L. 110-140) is set to increase yearly through 2022. In 2012, the RFS required the use of 15.2 billion gallons of ethanol and other biofuels in transportation fuel. Within that mandate, the RFS required the use of 2.0 billion gallons of advanced biofuels, including 8.65 million gallons of cellulosic biofuels (although only about 20,000 gallons of cellulosic fuel were actually registered in the program). For 2013, the RFS mandate is 16.55 billion gallons, including a proposed 14 million gallons of cellulosic fuel. At the end of each year, covered entities must submit credits (called Renewable Identification Numbers, or RINs) equal to their obligations for that year. Cases of fraud in the market for biodiesel RINs has led to criminal prosecutions and the development of quality-assurance guidelines from EPA. Further, recent volatility in the spot market for ethanol RINs has raised additional concerns about implementation of the RFS.

In January 2011, EPA finalized a partial waiver petition from Growth Energy to allow blends of up to 15% ethanol in gasoline (E15): before then ethanol content in all gasoline was limited to 10% (E10). EPA approved the use of E15 in model year 2001 and later passenger cars and light trucks, but prohibited its use in all other applications (e.g., motorcycles, heavy trucks, nonroad engines). Allowing higher blends of ethanol under the Clean Air Act removes one component of the “blend wall,” which limits the total amount of ethanol that can be blended in gasoline nationwide; other blend wall components include vehicle and pump certification and warranties, and state and local fire codes and other laws.

Attention has also focused on government-backed loans for the development and deployment of new energy technologies. One such program, the Advanced Technology Vehicles Manufacturing (ATVM) Loan Program, has been controversial as some critics question whether other existing policies, such as stricter vehicle fuel economy standards, already promote the same technologies.

Other potential issues before Congress include how much the federal government should support the expansion of natural gas vehicles and the infrastructure to fuel them, and how much the government should support the deployment of plug-in electric vehicles.


Date of Report: April 4, 2013
Number of Pages: 20
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FutureGen: A Brief History and Issues for Congress

Peter Folger
Specialist in Energy and Natural Resources Policy

A decade after the George W. Bush Administration announced FutureGen—its signature clean coal power initiative—the program is still in early development. Since its inception in 2003, FutureGen has undergone changes in scope and design. As initially conceived, FutureGen would have been the world’s first coal-fired power plant to integrate carbon capture and sequestration (CCS) with integrated gasification combined cycle (IGCC) technologies. FutureGen would have captured and stored carbon dioxide (CO2) in deep underground saline formations and produced hydrogen for electricity generation and fuel cell research. Increasing costs of development, among other considerations, caused the Bush Administration to discontinue the project in 2008. In 2010, under the Obama Administration, the project was restructured as FutureGen 2.0: a coalfired power plant that would integrate oxy-combustion technology to capture CO2. FutureGen 2.0 is the U.S. Department of Energy’s (DOE) most comprehensive CCS demonstration project, combining all three aspects of CCS technology: capturing and separating CO2 from other gases, compressing and transporting CO2 to the sequestration site, and injecting CO2 in geologic formations for permanent storage.

Congressional interest in CCS technology centers on balancing the competing national interests of fostering low-cost, domestic sources of energy like coal against mitigating the effects of CO2 emissions in the atmosphere. FutureGen would address these interests by demonstrating CCS technology. Among the challenges to the development of FutureGen 2.0 are rising costs of production, ongoing issues with project development, lack of incentives for investment from the private sector, time constraints, and competition with foreign nations. Remaining challenges to FutureGen’s development include securing private sector funding to meet increasing costs, purchasing the power plant for the project, obtaining permission from DOE to retrofit the plant, performing the retrofit, and then meeting the goal of 90% capture of CO2.

The FutureGen project was conceived as a public-private partnership between industry and DOE with agreements for cost-share and cooperation on development, demonstration, and deployment of CCS technology. The public-private partnership has been criticized for leading to setbacks in FutureGen’s development, since the private sector lacks incentives to invest in costly CCS technology. Regulations, tax credits, or policies such as carbon taxation or cap-and-trade that increase the price of electricity from conventional power plants may be necessary to make CCS technology competitive enough for private sector investment. Even then, industry may choose to forgo coal-fired plants for other sources of energy that emit less CO2, such as natural gas.

A proposed rule by the Environmental Protection Agency (EPA) to limit CO2 emissions from new fossil-fuel power plants may provide some incentive for industry to invest in CCS technology. Alternatively, critics of the proposed rule have expressed concern over the loss of American competitiveness in a global market not subject to similar regulations. These critics point to China’s increasing CO2 emissions and argue that Chinese industries will surpass American industries in productive competitiveness and that this will lead to American companies outsourcing jobs and production. Delays in FutureGen’s project development may have made full-scale demonstration of CCS technology by 2015—the year that federal stimulus funding for FutureGen expires—difficult to accomplish.


Date of Report: April 3, 2013
Number of Pages: 15
Order Number: R43028
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