Keeping America’s Pipelines Safe and Secure: Key Issues for Congress

Paul W. Parfomak
Specialist in Energy and Infrastructure Policy

Nearly half a million miles of pipeline transporting natural gas, oil, and other hazardous liquids crisscross the United States. While an efficient and fundamentally safe means of transport, many pipelines carry materials with the potential to cause public injury and environmental damage. The nation’s pipeline networks are also widespread and vulnerable to accidents and terrorist attack. Recent pipeline accidents in Marshall, MI, San Bruno, CA, Allentown, PA, and Laurel, MT, have heightened congressional concern about pipeline risks. Both government and industry have taken numerous steps to improve pipeline safety and security over the last 10 years. While many stakeholders agree that federal pipeline safety programs have been on the right track, recent pipeline incidents suggest there continues to be room for improvement. Likewise, the threat of terrorist attack on U.S. pipelines remains a concern.

The federal pipeline safety program was authorized through the fiscal year ending September 30, 2010, and is currently operating under a continuing resolution. The Pipeline Transportation Safety Improvement Act of 2011 (S. 275) would reauthorize the program through FY2014.

The 112th Congress is considering new legislation to improve the safety and security of the U.S. pipeline network. The Strengthening Pipeline Safety and Enforcement Act of 2011 (S. 234) would increase the number of federal pipeline safety inspectors, would require automatic shutoff valves for natural gas pipelines, and would mandate internal inspections of transmission pipelines, among other provisions. S. 275 would increase federal pipeline safety inspectors, would require automatic or remote controlled shutoff valves on new gas pipelines, would require public access to pipeline emergency response plans, would require a review of current regulation for pipelines transmitting “tar sands crude oil,” and would increase civil penalties for pipeline safety violations, among other provisions. The Pipeline Safety and Community Empowerment Act of 2011 (H.R. 22) would require automatic or remote shut-off valves for many pipelines and public disclosure of pipeline locations, among other provisions.

As Congress debates reauthorization of the federal pipeline safety program and oversees the federal role in pipeline security, key questions may be raised concerning pipeline agency staff resources, automatic pipeline shutoff valves, penalties for pipeline safety violations, safety regulations for oil sands crudes, and the possible need for pipeline security regulations, among other concerns. In addition to these specific issues, Congress may wish to assess how the various elements of U.S. pipeline safety and security activity fit together in the nation’s overall strategy to protect transportation infrastructure. Pipeline safety and security necessarily involve many groups: federal agencies, oil and gas pipeline associations, large and small pipeline operators, and local communities. Reviewing how these groups work together to achieve common goals could be an oversight challenge for Congress.

Date of Report: July 11, 2011
Number of Pages: 35
Order Number: R41536
Price: $29.95

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Oil Industry Financial Performance and the Windfall Profits Tax

Robert Pirog
Specialist in Energy Economics

Molly F. Sherlock
Analyst in Economics

Over the past 13 years, surging crude oil and petroleum product prices have increased oil and gas industry revenues and generated record profits, particularly for the top five major integrated companies, ExxonMobil, Royal Dutch Shell, BP, Chevron, and ConocoPhillips. These companies, which reported a predominant share of those profits, generated more than $104 billion in profit on nearly $1.8 trillion of revenues in 2008, before declining as a result of the recession and other factors. From 2003 to 2008, revenues increased by 86%; net income (profits) increased by 66%. Oil output by the five major companies over this time period declined by more than 7%, from 9.85 million to 9.12 million barrels per day. In 2010 the companies’ oil production was 9.4 million barrels per day. Being largely price-driven, with no accompanying increase in output resulting from increased investment in exploration and production, some believe that a portion of the increased oil industry income over this period represents a windfall and unearned gain. A windfall income is not earned as a result of additional production effort on the part of the firms, but due primarily to record crude oil prices, which are set in the world oil marketplace.

Since the 109th Congress, numerous bills have been introduced seeking to impose a windfall profits tax (WPT) on oil. An excise-tax based WPT would tax only domestic production and, like the one in effect from 1980-1988, would increase marginal oil production costs. Theoretically, such a policy could reduce domestic oil supply, which could raise petroleum imports, making the United States more dependent on foreign oil, undermining goals of energy independence and energy security. By contrast, an income-tax based WPT would likely be more economically neutral (less economic distortion) in the short-run. Sizeable tax revenues could potentially be raised without reducing domestic oil supplies. Neither the excise-tax based nor income-tax based WPT are expected to have significant price effects. Neither tax would increase the price of crude oil, which means that refined petroleum product prices, such as pump prices for gasoline, would likely not increase.

In lieu of these two types of WPT, an administratively simple way of increasing the tax burden on the oil industry, and therefore recouping some of any excess or windfall profits, particularly from major integrated producers, would be to raise the effective corporate tax rate. One option would be repealing or reducing the domestic manufacturing activities deduction under IRC § 199. The 112th Congress voted on this measure as part of the Close Big Oil Tax Loopholes Act (S. 940). Going forward, in the context of deficit reduction, the 112th Congress may continue evaluating various methods for increasing taxes on the oil and gas industry to address concerns surrounding possible windfall profits.


Date of Report: July 13, 2011
Number of Pages: 25
Order Number: RL34689
Price: $29.95

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Keystone XL Pipeline Project: Key Issues

Paul W. Parfomak
Specialist in Energy and Infrastructure Policy

Neelesh Nerurkar
Specialist in Energy Policy

Linda Luther
Analyst in Environmental Policy

Adam Vann
Legislative Attorney

Canadian pipeline company TransCanada has filed an application with the U.S. Department of State to build the Keystone XL pipeline, which would transport crude oil from the oil sands region of Alberta, Canada, to refineries in the United States. Keystone XL would have the capacity to transport 830,000 barrels per day, delivering crude oil to the market hub at Cushing, OK, and further to points in Texas. The project is expected to cost more than $7.0 billion, of which at least $5.4 billion would be spent on the U.S. portion. TransCanada is planning to build a short additional pipeline so that oil from the Bakken formation in Montana and North Dakota can also be carried on the Keystone XL pipeline.

As a facility connecting the United States with a foreign country, Keystone XL requires a Presidential Permit from the State Department. Issuance of a permit is dependant upon a finding that the project would serve the national interest. That finding is based, in part, on the environmental impacts of the project as determined in an environmental impact statement (EIS) prepared pursuant to the National Environmental Policy Act (NEPA). A draft EIS issued in April 2010 was rated “inadequate” by the U.S. Environmental Protect Agency (EPA).

To respond to comments from EPA, as well as the public and other agencies, the State Department issued a supplement draft EIS in April 2011. EPA found the supplement draft included insufficient information to determine environmental impacts and recommended additional data and analysis to be included in the final EIS. Once a final EIS is issued, the State Department plans to hold six public hearings to gather additional comments on whether authorization of a Presidential Permit for Keystone XL would be in the national interest. The State Department expects to make that decision before the end of 2011.

Opponents to the Keystone XL pipeline project, primarily environmental groups and affected communities along the route, object to the project principally on the grounds that it supports “dirty” Canadian oil sands development, that a potential spill could pose a risk to groundwater, that alternative pipeline routes avoiding the Ogallala Aquifer have not been fully considered, and that it promotes continued U.S. dependency on fossil fuels. Arguments criticizing the greenhouse gas emissions of oil sands production, generally, are based to some degree on the assumption that limiting pipeline capacity to U.S. markets may limit output from Canada’s oil sands.

Proponents of the Keystone XL pipeline, including Canadian agencies and petroleum industry stakeholders, point to energy security and economic benefits, such as job creation. Some contend that the Keystone XL project would secure growing Canadian oil supplies for the U.S. market, which could offset imports from less dependable foreign sources. They also claim that if oil sands output cannot flow to the United States, infrastructure to export it to Asia will likely develop.

International pipeline projects like Keystone XL are not subject to the direct authority of Congress, but numerous Members of Congress have expressed support for, or opposition to, the pipeline proposal because of its potential environmental, energy security, and economic impacts. Congress may have an oversight role stemming from federal environmental statutes that govern the pipeline’s application review process. The North American-Made Energy Security Act (H.R. 1938) would direct the President to issue a final order granting or denying the Presidential Permit for the Keystone XL pipeline by November 1, 2011. Whatever the State Department’s decision, legal challenges appear likely.


Date of Report: June 29, 2011
Number of Pages: 22
Order Number: R41668
Price: $29.95

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U.S. Offshore Oil and Gas Resources: Prospects and Processes

Marc Humphries
Specialist in Energy Policy

Robert Pirog
Specialist in Energy Economics

Gene Whitney
Section Research Manager

Access to potential oil and gas resources under the U.S. Outer Continental Shelf (OCS) continues to be controversial. Moratoria on leasing and development in certain areas were largely eliminated in 2008 and 2009, although a few areas remain legislatively off limits to leasing. The 112th Congress may be unlikely to reinstate broad leasing moratoria, but some Members have expressed interest in protecting areas (e.g., the Georges Bank or Northern California) or establishing protective coastal buffers. Pressure to expand oil and gas supplies and protect coastal environments and communities will likely lead Congress and the Administration to consider carefully which areas to keep open to leasing and which to protect from development.

The oil spill that occurred on April 20, 2010, in the Gulf of Mexico brought increased attention to offshore drilling risks. Consideration of offshore development for any purpose has raised concerns over the protection of the marine and coastal environment. In addition to the oil spill, historical events associated with offshore oil production, such as the large oil spill off the coast of Santa Barbara, CA, in 1969, cause both opponents and proponents of offshore development to consider the risks and to weigh those risks against the economic and social benefits of the development.

On December 1, 2010, the Obama Administration announced its Revised Program (RP) for the remainder of the 2007-2012 OCS Leasing Program. Among other components, the RP eliminates five Alaskan lease sales (sales 209, 212, 214, 217, and 221) that had been contemplated in the current lease program. Lease sale 219 in the Cook Inlet (scheduled to be held in 2011) was cancelled because of a lack of industry interest. Further, the Obama Administration, under executive authority, withdrew the North Aleutian Basin Planning Area from oil and gas leasing activity until June 30, 2017. Public hearings began in 2010 on the scope of the 2012-2017 OCS oil and gas leasing program, but the RP excludes all three Atlantic and all four Pacific Coast planning areas at least through 2017. Three planning areas in Alaska (Cook Inlet, Chukchi, and Beaufort Sea) are being scoped as well. Since the Deepwater Horizon oil spill, President Obama has cancelled the August lease sale (215) and the Mid-Atlantic lease sale (220).

Three bills that were passed in the House in May 2011 would address permitting efficiencies (H.R. 1229), enforce certain lease sales in the current five-year planning period (H.R. 1230) and require lease sales in the “most promising” OCS Planning Areas during the 2012-2017 Lease Program (H.R. 1231).

Exploration and production proceed in stages during which increasing data provide increasing certainty about volumes of oil and gas present. Prior to discovery by drilling wells, the estimated volumes of oil and gas are termed undiscovered resources. The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) conducts assessments of undiscovered technically recoverable resources (UTRR) on the U.S. OCS. The statistical certainty of these assessment estimates varies by region because the availability of geologic data varies widely by region. One characteristic of the U.S. oil market, as well as of world oil markets, is that the access to supply tends to be sequential. Normally, the first source of oil used by a nation is domestic production, if available. The ultimate impact of oil and gas development in offshore areas will depend on oil and gas prices, volumes of resources actually discovered, infrastructure development, and restrictions placed on development, all of which currently carry significant uncertainties.


Date of Report: June 30, 2011
Number of Pages: 34
Order Number: R40645
Price: $29.95

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Intermediate-Level Blends of Ethanol in Gasoline, and the Ethanol “Blend Wall”

Brent D. Yacobucci
Specialist in Energy and Environmental Policy

On March 6, 2009, Growth Energy (on behalf of 52 U.S. ethanol producers) applied to the Environmental Protection Agency (EPA) for a waiver from the Clean Air Act (CAA) limitation on ethanol content in gasoline. Ethanol content in gasoline for all uses had been capped at 10% (E10); the application requested an increase in the maximum concentration to 15% (E15). A broad waiver would allow the use of more ethanol in gasoline than is currently permitted.

On October 13, 2010, EPA issued a partial waiver for the use of E15 in model year (MY) 2007 and later passenger cars and light trucks. At the same time EPA denied the waiver request for the use of E15 in MY2000 and older vehicles, and in motorcycles, heavy trucks, and non-road applications, citing a lack of sufficient data to alleviate concerns about potential emissions increases from these engines. EPA deferred a decision on MY2001-MY2006 cars and light trucks until January 2011, when the agency expanded the waiver for those vehicles after analyzing final testing data from the Department of Energy (DOE). Concerned about potential damage by E15 to equipment not designed for its use, a group of vehicle and engine manufacturers has challenged the partial waiver in court.

Of key concern before the waiver decision was made is the fact that a 10% limitation on ethanol content leads to an upper bound of roughly 15 billion gallons of ethanol in all U.S. gasoline. This “blend wall” will likely limit the fuel industry’s ability to meet an Energy Independence and Security Act (EISA, P.L. 110-140) requirement to use increasing amounts of renewable fuels (including ethanol) in transportation. To meet the high volumes mandated by EISA, EPA recognized in a November 2009 letter to Growth Energy that “it is clear that ethanol will need to be blended into gasoline at levels greater than the current limit of 10 percent.” The partial waiver for MY2001 and later vehicles—roughly two-thirds of the cars and light trucks on the road in 2011—will allow the use of more ethanol going forward, assuming other conditions are met.

To receive a waiver, the petitioner must establish to EPA that the increased ethanol content will not “cause or contribute to a failure of any emission control device or system” to meet emissions standards. In addition to the emissions concerns, other factors affecting consideration of the blend wall include vehicle and engine warranties and the effects on infrastructure. Currently, no automaker warrants its vehicles to use gasoline with higher than 10% ethanol. Small engine manufacturers similarly limit the allowable level of ethanol. In addition, most gasoline distribution systems (e.g., retail pumps and tanks) are designed to dispense up to E10. While some of these systems may be able to operate effectively on E15 or higher, their warranties/certifications would likely need to be modified. Further, many current state laws prohibit the use of blends higher than E10. Questions have been raised whether fuel suppliers would be willing to sell E15 alongside or in lieu of E10.

As EPA’s waiver only applies to newer vehicles, a key question is how fuel pumps might be labeled to keep owners from using E15 in older vehicles and other equipment. Along with the waiver decision, EPA proposed new rules, including pump labeling, to prevent misfueling of E15 in vehicles not approved for its use. EPA finalized those rules in June 2011. EPA also sought comment (through December 17, 2010) on how to update guidance for underground storage tank (UST) owners, who must demonstrate compatibility of UST components with E15 before they may sell the fuel. Further, for EPA to allow the sale of E15, a fuel supplier would still need to register E15 with EPA and submit health effects testing for EPA to review—a process that had not been started as of late June 2011.


Date of Report: July 1, 2011
Number of Pages: 17
Order Number: R40445
Price: $29.95

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