Air Pollution Control Equipment Services, Coal

Diversifying the Fleet at American Electric Power

Issue 11 and Volume 116.

AEP's new John W. Turk, Jr. coal-fired power plant in Arkansas is expected to be commissioned by the end of 2012. Photo courtesy of American Electric Power.
AEP’s new John W. Turk, Jr. coal-fired power plant in Arkansas is expected to be commissioned by the end of 2012. Photo courtesy of American Electric Power.

By Brian Wheeler, Senior Editor

With over 38,000 MW of installed power generation across 11 states, American Electric Power (AEP) is one of the United States’ largest generators of electricity. AEP uses over 80 power generation facilities to cover its 197,500-square-mile service territory. The 106-year-old company, headquartered in Columbus, Ohio, began providing electric, gas, water, and steam services in 1906 under the name American Gas and Electric.

AEP is adjusting to changes in its operations, starting from the top. This year, Nick Akins, president and CEO, delivered his first address at an AEP shareholders meeting in April after being named leader of the utility in November 2011. Akins, who took over for Mike Morris, became the sixth CEO and 10th president in the company’s long history. Prior to being elected president, Akins served as executive vice president of generation where he was responsible for all of AEP’s generation activities.

A shift is also being seen in AEP’s generation portfolio. AEP generates about 25,000 MW from coal-fired power plants, a capacity that is expected to drop due to proposed regulations from the U.S. Environmental Protection Agency.

“We are about two-thirds coal today,” said Mark McCullough, executive vice president of generation for AEP.”That is going to change over the next eight years, with the primary impact being the MATS (Mercury Air Toxics Standard) rule.”

In March, the utility announced its plan to retire more than 4,600 MW of coal-fired generation in order to comply with the EPA regulations.

“We continue to have serious concerns about the potential impact of these plant retirements – and retirements of generation announced by other utilities – will have on the reliability of the electricity grid,” Akins said in March. McCullough emphasized the local and regional reliability concerns are due to the short compliance timeframes required in the EPA regulations.

In addition to the announced retirements, AEP has made plans to install or upgrade emissions control systems on about 13,000 MW at coal-fueled plants. Since 1980, AEP has invested more than $7 billion to install environmental controls on its power plants. Between 2003 and 2011, AEP installed nine scrubbers on about 7,900 MW of coal-fired generation it owns and operates. The company has also installed selective catalytic reduction systems on more than 11,000 MW since 2001. These projects have reduced sulfur dioxide (SO2) emissions by 73 percent and nitrogen oxide (NOx) emissions by about 80 percent from 1990 levels.

“The co-benefit of scrubbing and installing SCR is that we are compliant for mercury under the new MATS rule,” said McCullough.

AEP has more work to do and more money to spend to comply. Akins, speaking from the annual shareholders meeting in April, said the utility will spend about $6 billion over the next decade on pollution control systems and to convert coal-fired plants to natural gas.

“We have to position the generation resource of the future, and that’s a big issue for us because we have almost 40,000 MW of generation,” Akins said during the Barclays Capital CEO Energy/Power Conference in New York City in early September.”We have the EPA requirements that are coming down the pipe, but we also have natural gas becoming prevalent in our service territory.”

New Coal in Arkansas

AEP is nearing completion on its newest, full-scale power plant project. Construction on the 600 MW, ultra-supercritical, coal-fired John W. Turk, Jr. Power Plant in Arkansas started in November 2008. When complete, the plant, which will be the first ultra-supercritical plant to enter service in the U.S., will be one of the cleanest coal plants in the country as ultra-supercritical technology requires less coal and produces fewer emissions to generate the same amount of power as existing coal-fired facilities.

“Turk brings a very reliable, low-cost, stable supply of electricity to the customers of SWEPCO in Arkansas, Texas and Louisiana,” said McCullough.

As AEP marked 92 percent completion this June, the utility also celebrated the first coal train delivery to the plant. The 135-unit coal train from Wyoming reached the Turk plant May 30. Each coal car carried about 120 tons of coal, with the Turk plant expected to burn about 2.6 million tons annually.

The Turk project, though, did not move forward without opposition. The Sierra Club, the National Audubon Society and Audubon Arkansas brought legal actions against AEP related to the Turk plant. In December 2011, AEP and its operating unit Southwestern Electric Power Co. (SWEPCO) said all legal challenges were settled. In order for opposition to withdraw their legal filings, AEP agreed to not construct any additional units at the Turk site, as well as no additional coal-fired units at any location in Arkansas within 30 miles of the Turk plant for the duration of its service life. AEP also agreed to limit the capacity of the 528 MW Welsh Unit 2 plant in Texas to 60 percent once Turk begins commercial operations, with future plans to retire the Welsh unit by December 2014. SWEPCO will also build or secure 400 MW of renewable energy. AEP currently generates about 6 percent of its total capacity with wind, hydro, pumped storage and other sources.

“The provisions of the agreement are consistent with our commitment to renewable energy, energy efficiency and overall environmental stewardship,” Akins said at the time of the settlement.

The Shaw Group won a $700 million EPC contract in 2007 to build the Turk plant. Peak construction was reached in May 2011 with 2,200 workers on-site. The $1.7 billion project, which is expected to be commissioned by the end of 2012, will produce 109 permanent jobs. The Turk project achieved its first gas fire to generate steam in August, and AEP planned to burn the first coal in the October to November timeframe.

“Then it’s off to the races with synchronization and commissioning of all systems,” said McCullough.

CCS at Mountaineer

In 2009, AEP and its technology partner Alstom commissioned the world’s first carbon capture and storage (CCS) project at AEP’s 1,300 MW Mountaineer coal-fired power plant in New Haven, W.Va. The power plant was retrofitted with Alstom’s chilled ammonia CO2 capture technology on a 20 MW portion of the plant in order to validate the technology and benefits of CCS. The demonstration project was designed to capture at least 100,000 tons of CO2 annually and store it roughly 1.5 miles below the plant in deep geological formations. AEP began capturing CO2, about 90 percent of what was generated in the 20 MW demo, in September 2009 and storing it in those formations in October.

In 2009, AEP and its technology partner Alstom commissioned the world's first carbon capture and storage project at AEP's 1,300 MW Mountaineer coal-fired power plant in West Virginia. Photo courtesy of Alstom.
In 2009, AEP and its technology partner Alstom commissioned the world’s first carbon capture and storage project at AEP’s 1,300 MW Mountaineer coal-fired power plant in West Virginia. Photo courtesy of Alstom.

As planned, AEP and Alstom closed the demo project in May 2011 after meeting project goals. Between October 2009 and May 2011, the CCS project operated more than 6,500 hours, captured more than 50,000 metric tons of CO2 and stored more than 37,000 metric tons. But the demo was only one step in a four-phase project to reach utility-scale in 2015. After validating the technology, AEP was to move into the first phase of the project, which included front-end engineering and design, development of the environmental impact statement and development of a detailed Phase II and Phase III schedule.

Just under two years later, AEP placed the CCS project on hold citing the uncertain status of the U.S. climate policy and economics. The project was not cheap from the beginning. In 2009, AEP was awarded up to $334 million in funding from the U.S. Department of Energy through the Clean Coal Power initiative to pay for a portion of the costs to install and operate a 235 MW commercial-scale CCS system at Mountaineer.

“We have advanced CCS technology more than any other power generator with our successful two-year project to validate the technology,” then chairman and CEO Mike Morris said.

While the Mountaineer project came to a halt, hope for CCS is not completely gone. Testifying before U.S. House of Representatives’ Energy and Commerce Committee, Robert Hilton, Alstom Power’s vice president of Power Technologies for Governmental Affairs told members of the committee “CCS is, within the realm of innovation, no different than any other technology under development. It is required to move through various stages of development at consistently larger scale or size.”

Even though its Mountaineer project has been canceled as of now, AEP is a project partner in the National Carbon Capture Center (NCCC), a DOE project Southern Co. manages and operates. The NCCC was developed to test technologies for extended periods of time to reduce greenhouse gas emissions from coal-fired power plants, while accelerating the deployment of CO2 capture technologies. AEP supports the project and is involved in efforts in its territory states to back projects however possible. But the company will not invest in projects like it did with Mountaineer because recovery of costs is not possible in the states it services.

“We have to find a way to support an actual all-of the-above energy policy,” said McCullough.”If we are going to do that, we need to address carbon capture utilization and storage…and move the technology to commercial state.”

It could be another 15 to 20 years before the technology is cost-competitive, said McCullough, but given the vast reserve of coal in the U.S., “we should be right on the leading edge as a nation in supporting this technology.”

Keeping Nuclear in the Fleet

Indian Michigan Power (I&M), AEP’s northern-most subsidiary, operates AEP’s only nuclear power asset, the Donald C. Cook Nuclear Plant in Bridgman, Mich. The plant generates over 2,100 MW with the use of two Westinghouse pressurized water reactors that entered service in 1974 and 1977. In an effort to keep the plant operating for an additional 20 years, I&M in April filed a proposal with the Indiana Utility Regulatory Commission, stating its plans to spend up to $1.17 billion to conduct a Life Cycle Management Project.

In an effort to keep the plant operating for an additional 20 years, AEP plans to spend up to $1.17 billion to conduct a Life Cycle Management Project at the Cook nuclear power plant in Michigan. Photo courtesy of American Electric Power.
In an effort to keep the plant operating for an additional 20 years, AEP plans to spend up to $1.17 billion to conduct a Life Cycle Management Project at the Cook nuclear power plant in Michigan. Photo courtesy of American Electric Power.

Both units, Cook 1 and Cook 2, received the needed license extensions from the U.S. Nuclear Regulatory Commission in 2005 to continue operating for an additional 20 years beyond its original license shutdown date.

“The Cook Plant plays a significant role in enabling I&M to provide our customers with the lowest cost power among all investor-owned utilities in Indiana,” said Paul Chodak III, president and chief operating officer for I&M.

The Cook plant also produces the lowest fuel-cost electricity in AEP’s entire fleet. The Life Cycle Management Project will consist of multiple projects over a six-year timeframe with the majority of work being completed during schedule refueling outages. The Shaw Group won the contract from I&M to provide engineering, procurement and construction services to extend the life of major components at the Cook station.

Shale Plays in AEP Territory

As natural gas continues to hover around historically low prices, utilities in the U.S. are redefining the amount of gas-fired generation in its fleets. Over the past decade, AEP had added over 4,800 MW of gas-fired capacity to its system and expects natural gas to account for about 29 percent of its total output by 2020. Currently, AEP has about 10,000 MW of gas-fired generation, accounting for about 24 percent of its total capacity.

Speaking at the Barclays conference in September, Akins said natural gas is becoming more prevalent, and AEP is now focused on transforming its fleet.

“We cover several of the shale gas plays which have contributed to the economic recovery in our various jurisdictions,” he said.”But at the same time it brings up questions as to what our resource mix of the future is going to be.”

Since early 2007, AEP has started commercial operation on two separate natural gas-fired power plants.

SWEPCO, in July 2007, started service of Units 3 and 4 of the Harry D. Mattison Power Plant in Tontitown, Ark. Several months later, in December, Units 1 and 2 were commissioned. The four, simple-cycle gas-fired combustion turbines were completed at a cost of $131 million and have a total capacity of 340 MW. The intent to build these peaking projects was announced in 2006, and SWEPCO completed all four gas turbines a year before schedule. After purchasing the partially-constructed Dresden gas-fired plant from Dresden Energy LLC in 2007 for $85 million, AEP completed the 580 MW combined-cycle unit in February 2012. The plant, near Dresden, Ohio, will supply power to customers in West Virginia, Virginia and Tennessee.

And with gas prices still sitting in the $2 to $3 mmBtu range, gas remains an attractive option for AEP. And the utility is now running its gas-fired plants more frequently than in the past. AEP’s gas units are now running at 80-plus percent capacity factors.

“More megawatt hours are coming from gas than historically,” said McCullough.

While the low price is attractive, AEP will not rely solo on gas, due to historic fluctuations in pricing.

“When you compare the cost of a new gas plant to a new coal plant, gas is clearly the winner right now because of lower capital costs and competitive fuel costs,” added McCullough.”But when you compare a new gas plant to retrofitting an existing coal plant, it is a much tougher decision, until someone can guarantee gas prices for 30 years that are clearly below the cost of all other choices.

The newly-discovered shale plays are helping.

AEP is taking advantage of these new gas discoveries, such as the Utica Shale and the Marcellus Shale in the Appalachian Basin area covering Ohio and Pennsylvania.

Today, AEP has about 3,500 MW of gas in its eastern footprint, whereas, historically AEP’s gas generation was in its western footprint in states like Oklahoma.

“Natural gas will become an increasing part of AEP’s generating portfolio in the coming decades as a result of the development of shale gas reserves and new environmental regulations,” said Akins when commissioning of Dresden took place in February.”But we continue to believe our company and our nation need a diverse electricity generating portfolio that also includes investment in cleaner coal technologies, nuclear and renewable power.”