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
Order Number: RL33404
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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
Order Number: R40806
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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
Order Number: R43011
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Europe’s Energy Security: Options and Challenges to Natural Gas Supply Diversification

Michael Ratner, Coordinator
Specialist in Energy Policy

Paul Belkin
Analyst in European Affairs

Jim Nichol
Specialist in Russian and Eurasian Affairs

Steven Woehrel
Specialist in European Affairs

Europe as a major energy consumer faces a number of challenges when addressing future energy needs. Among these challenges are rapidly rising global demand and competition for energy resources from emerging economies such as China and India, persistent instability in energy producing regions such as the Middle East, a fragmented internal European energy market, and a growing need to shift fuels in order to address climate change policy. As a result, energy supply security has become a key concern for European nations and the European Union (EU).

A key element of the EU’s energy supply strategy has been to shift to a greater use of natural gas. Europe as a whole is a major importer of natural gas. Russia is Europe’s most important natural gas supplier, accounting for 36% of Europe’s natural gas imports. Europe’s natural gas consumption is projected to grow while its own domestic natural gas production continues to decline. If trends continue as projected, Europe’s dependence on Russia as a supplier is likely to grow. And, while it could be in Europe’s interest to explore alternative sources for its natural gas needs, it is uncertain whether Europe as a whole can, or is willing to, replace a significant level of imports of Russian natural gas. Some European countries that feel vulnerable to potential Russian energy supply manipulation may work harder to achieve diversification than others.

Russia has not been idle when it comes to protecting its share of the European natural gas market. Moscow, including the state-controlled company Gazprom, has attempted to stymie Europeanbacked alternatives to pipelines it controls by proposing competing pipeline projects and attempting to co-opt European companies by offering them stakes in those and other projects. It has attempted to dissuade potential suppliers (especially those in Central Asia) from participating in European-supported plans. Moscow has also raised environmental concerns in an apparent effort to hinder other alternatives to its supplies, such as unconventional natural gas.

Successive U.S. administrations and Congresses have viewed European energy security as a U.S. national interest. Promoting diversification of Europe’s natural gas supplies, especially in recent years through the development of a southern corridor of gas from the Caspian region as an alternative to Russian natural gas, has been a focal point of U.S. energy policy in Europe and Eurasia. The George W. Bush Administration viewed the issue in geopolitical terms and sharply criticized Russia for using energy supplies as a political tool to influence other countries. The Obama Administration has also called for diversification, but has refrained from openly expressing concerns about Russia’s regional energy policy, perhaps in order to avoid jeopardizing the “reset” of ties with Moscow. Nevertheless, although supplying natural gas to Europe from the Caspian Region and Central Asia has been a goal of multiple U.S. administrations and the EU, it is far from being achieved in volumes significant to counter Russian exports.

This report focuses on potential approaches that Europe might employ to diversify its sources of natural gas supply, Russia’s role in Europe’s natural gas policies, and key factors that could hinder efforts to develop alternative suppliers of natural gas. The report assesses the potential suppliers of natural gas to Europe and the short- to medium-term hurdles needed to be overcome for those suppliers to be credible, long-term providers of natural gas to Europe. The report looks at North Africa, potentially the most realistic supply alternative in the near-term, but notes that the region will have to resolve its current political, economic, and security instability as well as the internal structural changes to the natural gas industry. Central Asia, which may have the greatest amounts of natural gas, would need to construct lengthy pipelines through multiple countries to move its natural gas to Europe.


Date of Report: March 15, 2013
Number of Pages: 33
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Meeting the Renewable Fuel Standard (RFS) Mandate for Cellulosic Biofuels: Questions and Answers

Kelsi Bracmort Specialist in Agricultural Conservation and Natural Resources Policy

The Renewable Fuel Standard (RFS) was expanded under the Energy Independence and Security Act of 2007 (EISA; P.L. 110-140) in an effort to reduce dependence on foreign oil, promote biofuel use, and stabilize transportation fuel prices, among other goals. Over 15 years, the RFS requires that increasing amounts of biofuels—36 billion gallons by 2022—be used in transportation fuel. The mandate is to be accomplished in part with advanced biofuels, including cellulosic biofuels—fuels produced from cellulosic materials including grasses, trees, and agricultural and municipal wastes—which would increase over time to comprise some 44% of the RFS in 2022.

The U.S. Environmental Protection Agency (EPA) is required to set the annual standard for cellulosic biofuels under the RFS for the following year by November 30. If projected cellulosic biofuel production is less than the volume specified in the statute, EPA can lower the cellulosic biofuels standard. EPA concluded that the nation lacked sufficient production capacity to meet the RFS cellulosic biofuels mandate for 2010, 2011, 2012, and 2013. EPA reduced the mandate (actual volume) for 2010 (from 100 million gallons to 5 million gallons), 2011 (from 250 million gallons to 6.6 million gallons), and 2012 (from 500 million gallons to 8.65 million gallons, later vacated by a federal court decision). EPA proposes to lower the 2013 mandate from 1.0 billion gallons to 11 million gallons.

The 2010, 2011, and 2012 reduced mandates were not met by actual cellulosic biofuel production, which EPA reports was limited. Instead, these mandates were met with renewable identification numbers (RINs) generated under the original RFS, and with cellulosic biofuel waiver credits. The cellulosic biofuels industry may be able to produce the EPA mandates if certain obstacles are overcome: lowering the cost of conversion technology at the initial stages of commercial application, easing access to financing, removing feedstock supply uncertainties, and creating certainty for tax incentives. EPA reports that the industry front-runners—eight production facilities—have addressed many of these concerns, and that their success “will significantly decrease the perceived risk associated with similar future facilities and could potentially lead to the rapid deployment of cellulosic biofuel production facilities around the United States.” Another challenge for the cellulosic biofuels industry—and all biofuels industries—is the petroleum industry’s opposition to the RFS, in part because it views the RFS as unworkable. Other industries—livestock and poultry in particular—have joined the petroleum industry in requesting that the RFS be modified. Another constraint is the need to comply with the blend wall—the upper limit to the total amount of ethanol that by law can be blended into U.S. gasoline.

Several federal programs assist the cellulosic biofuels industry, including the U.S. Department of Agriculture’s (USDA’s) Biorefinery Assistance Program and Biomass Crop Assistance Program, and the U.S. Department of Energy’s (DOE’s) Loan Guarantee Program. EPA reports that some of the cellulosic biofuels front-runners received or were offered significant federal financial support (approximately $637 million) in the form of grants and loan guarantees from USDA and DOE between 2009 and 2012.

Many questions regarding cellulosic biofuels and the RFS may arise as Congress debates energy legislation. Can the RFS mandate for cellulosic biofuels be met? If so, when would it be met? What impact will the continued lowering of the cellulosic biofuels mandate by EPA have on investment in production? Should Congress continue to provide support for cellulosic biofuels, and if so, how? Might Congress statutorily increase the number of qualified feedstocks for the RFS cellulosic biofuels category, given the 112th Congress amendment of the definition of cellulosic biofuels to include algae for some tax incentives? What impact will other legislative discussions (e.g., military support for biofuels) have on the RFS cellulosic biofuels mandate?

This report, in a question and answer format, discusses some challenges facing the cellulosic biofuels community, including feedstock supply estimates, and potential legislative options to address cellulosic biofuels production uncertainty for the RFS.

Date of Report: March 11, 2013
Number of Pages: 21
Order Number: R41106
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