Short Answer: The main goal of the Energy Policy Act of 2005 is to solve some of

Question

Short Answer:

The main goal of the Energy Policy Act of 2005 is to solve some of the major energy problems in the United States. In addition to providing funding for renewable fuel technologies such as tidal power and geothermal energy, the legislation encourages the increase of coal as an energy source and provides incentives for companies that are drilling for oil. Do you think this legislation is likely to be effective in helping solve our country’s major energy problems? How might this legislation be made more effective?

Explanation / Answer

U.S. coal production has remained near 1.1 billion short tons annually since 1996. The Energy Information Administration (EIA) in its Annual Energy Outlook (AEO) projects U.S. coal production to increase (on average) 1.1 percent per year from 2004 to 2015; by 2015 U.S. coal production is forecast to reach 1.27 billion short tons. From 2015 to 2030, EIA projects that growth in U.S. coal demand will average 2 percent per year with coal production approaching 1.7 billion short tons annually by 2030.

The use of coal in industrial gasification and coal-to-liquids (CTL) technologies is also projected to increase significantly during the forecast period. The EIA estimates that by 2030, 180 million tons of coal will be used to produce high quality liquid fuels. Current technology yields approximately 1 barrel of liquid from .7 to .9 tons of coal. The AEO2006 forecast projects 800,000 barrels per day of domestic CTL production in the reference case and 1.7 million barrels be day in the high (oil) price case by 2030. This activity is initially concentrated in the Midwest in coal producing regions. These figures represent nearly one half of forecast worldwide CTL production in 2030.

A gasification plant transforms coal, coke and other materials into concentrated streams of various gases including hydrogen, carbon monoxide, carbon dioxide and other gases. At the same time sulfur, nitrogen and mercury present in those materials can be removed in the process. The sulfur and nitrogen can be sold commercially. The gases can then be made into liquid fuels such as diesel and jet fuel after passing through a Fischer-Tropsch synthesis process. Gases produced also may be refined through a synthesis process to produce feedstock for chemical manufacture or fuel gas. Or, the gas streams can be used to fire a gas turbine to generate electricity with waste heat from the turbine used to make steam to turn a steam turbine (which is know as Industrial Gasification Combined Cycle or IGCC).

Construction of CTL plants is highly dependent on relative fuel prices and the presence of adequate reserves, which includes geographic proximity. According to EIA, CTL is economically competitive at an oil price in the low to mid-$40 per barrel range and a coal cost in the range of $1 to $2 per million Btu, (depending on the coal quality and location).

Although EIA does not address the economics of an industrial gasification facility it does note that construction of a CTL plant requires several decades of coal reserves. (The EIA report assumes that gasification is the first step in a CTL process) Construction of a commercial scale CTL plant of 70 – 80,000 bbls per day would require 2 – 4 billion tons of coal reserves to be employed over the course of its useful life. Capital expenses for such a plant are estimated to be in the range of $50,000 – 70,000 (2004 dollars) per barrel of daily capacity.

Title XVII of the Energy Policy Act of 2005 established a loan guarantee program to help develop and deploy coal-to-liquids (CTL) and gasification technology. Loan guarantees may be granted for projects that avoid, reduce, or sequester emission of greenhouse gases and employ new or significantly improved technologies. Provisions seek to increase the use of coal, which has both economic and energy security benefits for the United States. The United States has been heralded the “Saudi Arabia of coal” with Illinois’ coal reserves alone containing a greater BTU content than all the oil in Iran, Iraq, Kuwait and Saudi Arabia.

As a direct result of the industrial gasification investment tax credit (Sec. 411), Rentech, Inc. plans to have a fully commercial, fully operational CTL plant up and running by 2010 in East Dubuque, Illinois, which will displace approximately 2,000 b/d and reduce regulated pollutant emissions, such as carbon dioxide, sulfur and mercury, by about 33 percent. Additionally, they are planning a second plant in Natchez, MI that would produce 11,000 b/d and store 100% of carbon emissions. This is the first large scale U.S. commercial capture and storage of man-made carbon emissions.

Section 417, which authorized funding for the development of a CTL facility from Illinois basin coal, has lead to a MOU being signed by the universities of Purdue, Southern Illinois, and Kentucky. The first step will be to establish a ½ b/d facility to test various technological options for the production of transportation fuels. Although details have not been finalized, plans have begun to take shape for the test facility prescribed in this section.

With the assistance of a loan guarantee, BRI Energy, using technology intended to produce ethanol from coal syngas, will have a 7 million gallon per year coal to ethanol facility constructed and operational within 15 to 18 months.

COAL

The Commission’s integrated licensing process to relicense these hydroelectric facilities takes approximately 7-7½ years to complete. Once issued, the licenses are valid for a period of 30-50 years.

The Departments of the Interior, Commerce, and Agriculture play a major role in the relicensing of hydropower projects that are located on federal lands. Pursuant to the Federal Power Act, any environmental conditions or fishways prescribed by a resource agency must be included in the final hydropower license.

Prior to enactment of the Energy Policy Act of 2005, the validity of the resource agencies’ mandatory conditions and fishway prescriptions could only be challenged at the appellate court level once the final license was issued. FERC had no authority to modify or reject an agency’s mandatory requirement, even if the condition or prescription rendered the project uneconomic. Section 241 reforms the hydropower licensing process. All parties to the license proceeding now have equal participation in the new procedures, which include: a trial-type hearing and alternative conditions or prescriptions.

All parties to a license proceeding may request an expedited agency trial-type hearing to examine any disputed issues of material fact relating to mandatory conditions or prescriptions. This provision provides the opportunity to test whether the agency’s requirements are supported by facts.

Any party to the proceeding may offer alternative conditions or prescriptions. The resource agency is required to adopt an alternative proposal if the alternative protects the resource and costs significantly less to implement than the agency’s initial requirement or results in improved project operations.

A number of positive outcomes have resulted from Section 241. At the Priest Rapids Project No. 2114, the licensee challenged the Bureau of Reclamation’s conditions. Subsequently, the Bureau withdrew these mandatory conditions and refilled them as recommendations. At the Rocky Reach Project No. 2145, the licensee submitted alternatives to the Department of Interior’s fishway prescriptions that lead to a comprehensive settlement agreement addressing fish passage concerns.

Section 1301 expanded the definition under the Section 45 production tax credit to recognize certain new hydropower projects as eligible renewable resources. Currently, FERC has received three requests from licensees to certify incremental hydropower for eligibility, which will result in a 2.6, 6.4, and 2.4 percent increase respectively in generation for those projects. Additionally, FERC has received nine license amendment applications for 124 megawatts of additional capacity which may qualify for the credit.

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