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Monday, January 30, 2012

Fukushima Nuclear Disaster

Mark Holt
Specialist in Energy Policy

Richard J. Campbell
Specialist in Energy Policy

Mary Beth Nikitin
Specialist in Nonproliferation

The huge earthquake and tsunami that struck Japan’s Fukushima Daiichi nuclear power station on March 11, 2011, knocked out backup power systems that were needed to cool the reactors at the plant, causing three of them to undergo fuel melting, hydrogen explosions, and radioactive releases. Radioactive contamination from the Fukushima plant forced the evacuation of communities up to 25 miles away and affected up to 100,000 residents, although it did not cause any immediate deaths.

Tokyo Electric Power Company (TEPCO) operates the Fukushima nuclear power complex in the Futaba district of Fukushima prefecture in Northern Japan, consisting of six nuclear units at the Fukushima Daiichi station and four nuclear units at the Fukushima Daini station. All the units at the Fukushima complex are boiling water reactors, with reactors 1 to 5 at the Fukushima Daiichi site being the General Electric Mark I design, which is also used in the United States. The Fukushima Daiichi reactors entered commercial operation in the years from 1971 (reactor 1) to 1979 (reactor 6). The Fukushima Daini reactors shut down automatically after the earthquake and were able to maintain sufficient cooling.

When the earthquake struck, Fukushima Daiichi units 1, 2, and 3 were generating electricity and shut down automatically. The earthquake caused offsite power supplies to be lost, and backup diesel generators started up as designed to supply backup power. However, the subsequent tsunami flooded the electrical switchgear for the diesel generators, causing most AC power in units 1 to 4 to be lost. Because Unit 4 was undergoing a maintenance shutdown, all of its nuclear fuel had been removed and placed in the unit’s spent fuel storage pool. One generator continued operating to cool units 5 and 6.

The loss of all AC power in units 1 to 3 prevented valves and pumps from operating that were needed to remove heat and pressure that was being generated by the radioactive decay of the nuclear fuel in the reactor cores. As the fuel rods in the reactor cores overheated, they reacted with steam to produce large amounts of hydrogen, which escaped into the unit 1, 3, and 4 reactor buildings and exploded (the hydrogen that exploded in Unit 4 is believed to have come from Unit 3). The explosions interfered with efforts by plant workers to restore cooling and helped spread radioactivity. Cooling was also lost in the reactors’ spent fuel pools, although recent analysis has found that no significant overheating took place.

Radioactive material released into the atmosphere produced extremely high radiation dose rates near the plant and left large areas of land uninhabitable, especially to the northwest of the plant. Contaminated water from the plant was discharged into the sea, creating international controversy.

The United States and other countries, as well as the International Atomic Energy Agency, are providing assistance to Japan to deal with the nuclear disater. U.S. assistance has included transport of pumps, boron, fresh water, remote cameras, use of Global Hawk surveillance drones, evacuation support, medical support, and decontamination and radiation monitoring equipment.

Studies of the Fukushima disaster have identified design changes, response actions, and other safety improvements that could have reduced or eliminated the amount of radioactivity released from the plant. As a result, Fukushima has prompted a reexamination of nuclear plant safety requirements around the world, including in the United States.

Date of Report: January 1
8, 2012
Number of Pages:
Order Number: R41
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

In 2008, Canadian pipeline company TransCanada 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 on the U.S. Gulf Coast. Keystone XL would ultimately 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. TransCanada plans to build a pipeline spur so that oil from the Bakken formation in Montana and North Dakota can also be carried on Keystone XL.

As a facility connecting the United States with a foreign country, the pipeline requires a Presidential Permit from the State Department. In evaluating such a permit application, after consultation with other relevant federal agencies and public input, the department must determine whether a proposal is in the “national interest.” This determination considers the project’s potential effects on the environment, economy, energy security, foreign policy, and other factors. Pursuant to the National Environmental Policy Act, the State Department considered potential environmental impacts of the proposed Keystone XL project in a final Environmental Impact Statement (EIS) issued on August 26, 2011. A wide range of public comments both for and against the pipeline were received during a subsequent 90-day review period. The State Department noted, in particular, concerns about the pipeline’s route through the Sand Hills region of Nebraska, an extensive sand dune formation with highly porous soil and shallow groundwater.

On November 10, 2011, in response to concerns regarding the pipeline route and related actions by the Nebraska legislature, the State Department announced a delay until 2013 of a national interest determination to gather additional information needed to assess a new pipeline route avoiding the Sand Hills. The Temporary Payroll Tax Cut Continuation Act of 2011(P.L. 112-78), enacted on December 23, 2011, included provisions requiring the Secretary of State to issue a permit for the project within 60 days, unless the President determined the project not to be in the national interest. The act allowed for future changes to the Nebraska route if approved by the Governor of Nebraska. On January 18, 2012, the State Department, with the President’s consent, denied the Keystone XL permit, citing insufficient time under the 60-day deadline to obtain all the necessary information to assess the reconfigured project. TransCanada has stated that it will reapply for a Presidential Permit after a new proposed route through Nebraska is determined. In keeping with an agreement reached between TransCanada and Nebraska before the State Department’s announcement, the company expects to establish the new route by October 2012. If the permit application process starts anew, a new draft EIS potentially could build upon the August 2011 final EIS, incorporating necessary analysis associated with a new Nebraska route.

International pipeline projects like Keystone XL are not subject to the direct authority of Congress. Nonetheless, several legislative proposals have sought to influence or alter the permit process for Keystone XL. Several bills, like P.L. 112-78, would have required the President to issue a final order granting or denying the Presidential Permit for the Keystone XL pipeline by a specific deadline (S. 1932, H.R. 3400, H.R. 3537, and H.R. 3630). These provisions have been mooted by the State Department’s denial of the permit. The North American Energy Access Act (H.R. 3548) would transfer permitting authority over the Keystone XL pipeline project from the State Department to the Federal Energy Regulatory Commission (FERC), and would require the commission to issue a permit for the project within 30 days of enactment. Attempting to change the State Department’s role in issuing cross-border infrastructure permits may be problematic, however, raising questions about the President’s executive authority.

Date of Report: January 19, 2012
Number of Pages:
Order Number: R41
Price: $29.95

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Friday, January 27, 2012

Nuclear Power Plant Design and Seismic Safety Considerations

Anthony Andrews
Specialist in Energy and Defense Policy

Peter Folger
Specialist in Energy and Natural Resources Policy

The earthquake and subsequent tsunami that devastated Japan’s Fukushima Daiichi nuclear power station and the earthquake that forced the North Anna, VA, nuclear power plant’s temporary shutdown have focused attention on the seismic criteria applied to siting and designing commercial nuclear power plants. Some Members of Congress have questioned whether U.S nuclear plants are more vulnerable to seismic threats than previously assessed, particularly given the Nuclear Regulatory Commission’s (NRC’s) ongoing reassessment of seismic risks at certain plant sites.

The design and operation of commercial nuclear power plants operating in the United States vary considerably because most were custom-designed and custom-built. Boiling water reactors (BWRs) directly generate steam inside the reactor vessel. Pressurized water reactors (PWRs) use heat exchangers to convert the heat generated by the reactor core into steam outside of the reactor vessel. U.S. utilities currently operate 104 nuclear power reactors at 65 sites in 31 states; 69 are PWR designs and the 35 are BWR designs.

One of the most severe operating conditions a reactor may face is a loss of coolant accident (LOCA), which can lead to a reactor core meltdown. The emergency core cooling system (ECCS) provides core cooling to minimize fuel damage by injecting large amounts of cool water containing boron (borated water slows the fission process) into the reactor coolant system following a pipe rupture or other water loss. The ECCS must be sized to provide adequate makeup water to compensate for a break of the largest diameter pipe in the primary system (i.e., the socalled “double-ended guillotine break” (DEGB)). The NRC considers the DEGB to be an extremely unlikely event; however, even unlikely events can occur, as the magnitude 9.0 earthquake and resulting tsunami that struck Fukushima Daiichi proves.

U.S. nuclear power plants designed in the 1960s and 1970s used a deterministic statistical approach to addressing the risk of damage from shaking caused by a large earthquake (termed Deterministic Seismic Hazard Analysis, or DSHA). Since then, engineers have adopted a more comprehensive approach to design known as Probabilistic Seismic Hazard Analysis (PSHA). PSHA estimates the likelihood that various levels of ground motion will be exceeded at a given location in a given future time period. New nuclear plant designs will apply PSHA.

In 2008, the U.S Geological Survey (USGS) updated the National Seismic Hazard Maps (NSHM) that were last revised in 2002. USGS notes that the 2008 hazard maps differ significantly from the 2002 maps in many parts of the United States, and generally show 10%-15% reductions in spectral and peak ground acceleration across much of the Central and Eastern United States (CEUS), and about 10% reductions for spectral and peak horizontal ground acceleration in the Western United States (WUS). Spectral acceleration refers to ground motion over a range, or spectra, of frequencies. Seismic hazards are greatest in the WUS, particularly in California, Oregon, and Washington, as well as Alaska and Hawaii.

In 2010, the NRC examined the implications of the updated NSHM for nuclear power plants operating in the CEUS, and concluded that NSHM data suggest that the probability for earthquake ground motions may be above the seismic design basis for some nuclear plants in the CEUS. In late March 2011, NRC announced that it had identified 27 nuclear reactors operating in the CEUS that would receive priority earthquake safety reviews.

Date of Report: January 12, 2012
Number of Pages: 42
Order Number: R41805
Price: $29.95

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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 ethanol and biomass-based diesel fuels expired at the end of 2011, along with an added duty on certain ethanol imports. Tax incentives for biofuels (including ethanol) produced from cellulosic feedstocks (e.g., grasses, trees, waste products) expire at the end of 2012.

While tax incentives for these fuels have expired or are expiring, 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. On February 3, 2010, the Environmental Protection Agency (EPA) finalized new rules for this mandate—the Renewable Fuel Standard (RFS). In 2011, the RFS required the use of 13.95 billion gallons of ethanol and other biofuels in transportation fuel. Within that mandate, the RFS required the use of 1.35 billion gallons of advanced biofuels, including 6.6 million gallons of cellulosic biofuels. For 2012, the RFS mandate is 15.2 billion gallons, including 8.65 million gallons of cellulosic fuel. EISA also requires that advanced biofuels (as well as conventional biofuels from newly built refineries) meet certain lifecycle greenhouse gas reduction requirements. EPA’s methodology and conclusions on various biofuels’ lifecycle emissions have been controversial.

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.

The 112th Congress has debated alternative fuels and advanced technology vehicles directly and as it has addressed other key topics. For example, the role of tax incentives for biofuels has been contentious. On June 16, 2011 the Senate approved S.Amdt. 476 which would have eliminated the excise tax credit for blending ethanol in gasoline before its December 31, 2011 expiration date. Although the underlying legislation failed a cloture vote in the Senate, the amendment was approved 73-27. The prospects for further action increasing or extending biofuels and alternative fuels tax incentives may be limited in light of that vote.

Date of Report: January 19, 2012
Number of Pages: 19
Order Number: R40168
Price: $29.95

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Tuesday, January 24, 2012

Loan Guarantees for Clean Energy Technologies: Goals, Concerns, and Policy Options

Phillip Brown
Specialist in Energy Policy

Government guaranteed debt is a financial tool that has been used to support a number of federal policy objectives: home ownership, higher education, and small business development, among others. Loan guarantees for new energy technologies date back to the mid-1970s, when rapidly rising energy prices motivated the development of alternative, and renewable, sources of energy. Recently, the Energy Policy Act of 2005 created a loan guarantee program for innovative clean energy technologies (nuclear, clean coal, renewables) commonly known as Section 1703. The American Recovery and Reinvestment Act of 2009 created Section 1705, a temporary loan guarantee program focused on deployment of renewable energy technologies and projects.

Loan guarantee authority for the Department of Energy Loan Programs Office (LPO) Section 1705 program ended on September 30, 2011, prior to which approximately $16.15 billion of loans were guaranteed for a variety of clean energy projects. In August 2011, the high-profile bankruptcy of Solyndra, the first company to receive a Section 1705 loan guarantee, resulted in a congressional investigation and increased scrutiny of the DOE Loan Guarantee Program. As a result, Congress may decide to evaluate the use of loan guarantees as a mechanism for supporting the development and deployment of clean energy technologies. This report analyzes goals and concerns associated with innovative clean energy loan guarantees.

Fundamentally, loan guarantees can provide access to low-cost capital for projects that might be considered high risk by the commercial banking and investment community. There are many goals for using loan guarantees to support innovative energy technology commercialization and deployment. Commercializing new technologies that may increase the performance and reduce the cost of clean energy generation is one objective. Also, the potential global market for clean energy technologies and systems is substantial (trillions of dollars over the next 25 years by some estimates) and loan guarantees could help position U.S. manufacturers to supply product for this growing market. Loan guarantees may also result in near and long-term job creation as well as contribute toward reducing emissions of various pollutants.

The high-risk nature of clean energy projects, however, raises some concerns about the use of loan guarantees as a mechanism to encourage the deployment of new technologies. First, loan repayment demands cash flow from development stage companies at a time when they may already have high cash flow requirements, so loan repayment obligations could actually increase the risk of default for certain projects. Second, at a project level, the government’s potential return is not commensurate with the risk being assumed. Third, loan guarantees for clean energy technologies are essentially long-term commitments in a dynamic and evolving marketplace. As a result, technologies supported today could be obsolete in less than a decade, thereby increasing the risk of loan default. Finally, federally managed loan guarantee programs may be subject to certain pressures that could result in less-than-optimal decision making.

Should Congress decide to continue the use of government financial tools as a clean energy technology deployment support mechanism, it may wish to consider various policy options for future initiatives. Some policy options could include (1) using grants or tax expenditures instead of loan guarantees (2) taking equity positions in new technologies and projects through a new government-backed venture-capital-like organization (3) authorizing the use of flexible management tools such as stock warrants, portfolio management, and convertible equity, and (4) creating a dedicated clean energy financial support authority to manage federal clean energy deployment investments. Each of these policy options is explored and discussed in this report.

Date of Report: January 17, 2012
Number of Pages:
Order Number: R421
Price: $29.95

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