COLUMBUS, Ohio, July 14, 2011 – American Electric Power (NYSE: AEP) is terminating its cooperative agreement with the U.S. Department of Energy and placing its plans to advance carbon dioxide capture and storage (CCS) technology to commercial scale on hold, citing the current uncertain status of U.S. climate policy and the continued weak economy as contributors to the decision.
“We are placing the project on hold until economic and policy conditions create a viable path forward,” said Michael G. Morris, AEP chairman and chief executive officer. “With the help of Alstom, the Department of Energy and other partners, we have advanced CCS technology more than any other power generator with our successful two-year project to validate the technology. But at this time it doesn’t make economic sense to continue work on the commercial-scale CCS project beyond the current engineering phase.
“We are clearly in a classic ‘which comes first?’ situation,” Morris said. “The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share.”
In 2009, AEP was selected by the Department of Energy (DOE) to receive funding of up to $334 million through the Clean Coal Power Initiative to pay part of the costs for installation of a commercial-scale CCS system at AEP’s Mountaineer coal-fueled power plant in New Haven, W.Va. The system would capture at least 90 percent of the carbon dioxide (CO2) from 235 megawatts of the plant’s 1,300 megawatts of capacity. The captured CO2, approximately 1.5 million metric tons per year, would be treated and compressed, then injected into suitable geologic formations for permanent storage approximately 1.5 miles below the surface.
Plans were for the project to be completed in four phases, with the system to begin commercial operation in 2015. AEP has informed the DOE that it will complete the first phase of the project (front-end engineering and design, development of an environmental impact statement and development of a detailed Phase II and Phase III schedule) but will not move to the second phase.
DOE’s share of the cost for completion of the first phase is expected to be approximately $16 million, half the expenses that qualify under the DOE agreement.
AEP and partner Alstom began operating a smaller-scale validation of the technology in October 2009 at the Mountaineer Plant, the first fully-integrated capture and storage facility in the world. That system captured up to 90 percent of the CO2 from a slipstream of flue gas equivalent to 20 megawatts of generating capacity and injected it into suitable geologic formations for permanent storage approximately 1.5 miles below the surface. The validation project, which received no federal funds, was closed as planned in May after meeting project goals. Between October 2009 and May 2011, the life of the validation project, the CCS system operated more than 6,500 hours, captured more than 50,000 metric tons of CO2 and permanently stored more than 37,000 metric tons of CO2.
“The lessons we learned from the validation project were incorporated into the Phase I engineering for the commercial-scale project,” Morris said.
American Electric Power is one of the largest electric utilities in the United States, delivering electricity to more than 5 million customers in 11 states. AEP ranks among the nation’s largest generators of electricity, owning nearly 38,000 megawatts of generating capacity in the U.S. AEP also owns the nation’s largest electricity transmission system, a nearly 39,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP’s transmission system directly or indirectly serves about 10 percent of the electricity demand in the Eastern Interconnection, the interconnected transmission system that covers 38 eastern and central U.S. states and eastern Canada, and approximately 11 percent of the electricity demand in ERCOT, the transmission system that covers much of Texas. AEP’s utility units operate as AEP Ohio, AEP Texas, Appalachian Power (in Virginia and West Virginia), AEP Appalachian Power (in Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company (in Arkansas, Louisiana and east Texas). AEP’s headquarters are in Columbus, Ohio.
This report made by American Electric Power and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate and growth in, or contraction within, AEP’s service territory and changes in market demand and demographic patterns; inflationary or deflationary interest rate trends; volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing AEP’s ability to finance new capital projects and refinance existing debt at attractive rates; the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material; electric load and customer growth; weather conditions, including storms, and AEP’s ability to recover significant storm restoration costs through applicable rate mechanisms; available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters; availability of necessary generating capacity and the performance of AEP’s generating plants; AEP’s ability to recover Indiana Michigan Power’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process; AEP’s ability to recover regulatory assets and stranded costs in connection with deregulation; AEP’s ability to recover increases in fuel and other energy costs through regulated or competitive electric rates; AEP’s ability to build or acquire generating capacity, including the Turk Plant, and transmission line facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates; new legislation, litigation and government regulation, including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of AEP’s plants; timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance); resolution of litigation (including AEP’s dispute with Bank of America); AEP’s ability to constrain operation and maintenance costs; AEP’s ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities; changes in the creditworthiness of the counterparties with whom AEP has contractual arrangements, including participants in the energy trading market; actions of rating agencies, including changes in the ratings of debt; volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities; changes in utility regulation, including the implementation of electric security plans and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP; accounting pronouncements periodically issued by accounting standard-setting bodies; the impact of volatility in the capital markets on the value of the investments held by AEP’s pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements; prices and demand for power that AEP generates and sells at wholesale; changes in technology, particularly with respect to new, developing or alternative sources of generation; and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.