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
Order Number: R40168
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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
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Offshore Oil and Gas Development: Legal Framework

Adam Vann
Legislative Attorney

The development of offshore oil, gas, and other mineral resources in the United States is impacted by a number of interrelated legal regimes, including international, federal, and state laws. International law provides a framework for establishing national ownership or control of offshore areas, and domestic federal law mirrors and supplements these standards.

Governance of offshore minerals and regulation of development activities are bifurcated between state and federal law. Generally, states have primary authority in the three-geographical-mile area extending from their coasts. The federal government and its comprehensive regulatory regime govern those minerals located under federal waters, which extend from the states’ offshore boundaries out to at least 200 nautical miles from the shore. The basis for most federal regulation is the Outer Continental Shelf Lands Act (OCSLA), which provides a system for offshore oil and gas exploration, leasing, and ultimate development. Regulations run the gamut from health, safety, resource conservation, and environmental standards to requirements for production based royalties and, in some cases, royalty relief and other development incentives.

In 2008, both the President and the 110th Congress removed previously existing moratoria on offshore leasing on many areas of the outer continental shelf. As of the date of this report, Congress has not reinstated the appropriations-based moratoria that were not renewed by the 110th Congress. Other recent legislative and regulatory activity suggests an increased willingness to allow offshore drilling in the U.S. Outer Continental Shelf. In 2006, Congress passed a measure that would allow new offshore drilling in the Gulf of Mexico. Areas of the North Aleutian Basin off the coast of Alaska have also been made available for leasing by executive order. Most recently, the five-year plan for offshore leasing for 2012-2017 adopted by the Bureau of Ocean Energy Management (BOEM) scheduled 16 more lease sales in the Gulf of Mexico and off the coast of Alaska, but did not schedule new lease sales in other areas.

In addition to legislative and regulatory efforts, there has also been significant litigation related to offshore oil and gas development. Cases handed down over a number of years have clarified the extent of the Secretary of the Interior’s discretion in deciding how leasing and development are to be conducted.


Date of Report: March 21, 2013
Number of Pages: 26
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Energy Projects on Federal Lands: Leasing and Authorization

Adam Vann
Legislative Attorney

Recent concerns over energy supply and pricing have led some to look increasingly to federal lands as a potential energy source. This report explains the legal framework for energy leasing and permitting for onshore lands subject to the control of the federal government.

The report first reviews the laws and regulations affecting leasing of federal lands for exploration and production of oil, natural gas, and coal, as well as the permits that lessees must obtain in order to explore for and produce these resources. This leasing process has evolved over the last century under the framework established by the Mineral Leasing Act of 1920 (MLA). Oil, natural gas, and coal leasing and production on federal land pursuant to this act are currently overseen by the Bureau of Land Management (BLM), an agency within the U.S. Department of the Interior (DOI). Federal lands identified in the area’s Resource Management Plan (RMP) as amenable to oil, coal, or natural gas exploration and production may be leased by BLM, so long as such activities in that area are not prohibited by statute or regulation. Such lands are usually leased to the highest bidder as determined by competitive auction. Leaseholders are generally required to pay both rental fees and royalties (a percentage of the value of produced oil, natural gas, or coal) to the U.S. government.

The report also addresses existing laws and regulations that govern the use of federal lands for renewable energy projects, including geothermal, wind, and solar energy. BLM oversees permitting for these projects. Geothermal projects are leased in accordance with the requirements of the Geothermal Steam Act of 1970. That act functions similarly to the MLA; lands that are amenable to geothermal projects are leased to the highest qualified bidder. In contrast, wind and solar projects on federal lands are not authorized by leases, but rather by obtaining a right-of-way from BLM. These rights-of-way are issued pursuant to the requirements of Title V of the Federal Land Policy and Management Act (FLPMA), and holders of these rights-of-way must make monthly rental payments to the U.S. government.

This framework provides BLM and the federal government with flexibility to use federal lands to help satisfy the nation’s energy needs, while generating revenue for the federal government and protecting environmentally sensitive areas.


Date of Report: March 28, 2013
Number of Pages: 23
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U.S. and World Coal Production, Federal Taxes, and Incentives

Marc Humphries, Coordinator
Specialist in Energy Policy

Molly F. Sherlock
Specialist in Public Finance

Even though U.S. coal production remained strong over the past decade, reaching record levels of production, coal is losing its share of overall U.S. energy production primarily to natural gas. One of the big questions for the industry is how to penetrate the overseas market, particularly in steam coal, to compensate for declining domestic demand. As U.S. energy policy and environmental regulations are constantly debated, there is ongoing congressional interest in the role of coal in meeting U.S. and global energy needs. The question may not be whether the domestic production of coal is here to stay but, rather, how much U.S. coal will be mined, what type, and under what regulatory framework.

Energy Information Administration (EIA) statistics show that more than half (55%) of U.S. coal reserves are located in the West, dominated by Montana and Wyoming, which account for 43%. When including the top five producing states (three of which are in the East), 70% of U.S. coal reserves are accounted for. The United States government owns about one third, or 87 billion short tons (BST), of U.S. domestic reserves.

Coal production in the United States reached an all-time high of 1,174.8 million short tons in 2008, before declining to slightly under 1,100 million short tons from 2009 to 2011. Coal production on federal lands accounts for about 43% of U.S. production, according to the Bureau of Land Management (BLM). World coal production has increased by nearly 60% since 2002, most of the increase coming from China—up 130%.

Overall, U.S. coal production has been very strong over the past decade and if the industry is successful in penetrating the global market, primarily for steam coal, U.S. production may continue to grow faster than consumption. If recent trends continue, the U.S. coal industry will likely become more concentrated and produce more on federal lands. Businesses in the coal industry are subject to federal income taxes, but coal producers benefit from a number of federal tax provisions, commonly referred to as tax expenditures.

There are several congressional concerns related to coal production on federal lands. One concern is the potential for under-market-value coal auctions (sales), e.g., lease offers being accepted by the BLM with few competitive bids. In these cases, the federal government may not receive fair market value for the lease sale.


Date of Report: March 14, 2013
Number of Pages: 25
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