Edwardsport project costs increase while AEP plans derailed

The cost estimate for Duke Energy's planned 630 MWe Edwardsport IGCC (integrated gasification combined cycle) plant in south west Indiana has - surprise, surprise - been revised upwards. According to a progress report filed on 1 May by Duke Energy with the Indiana Utility Regulatory Commission the increase is $365 million, which is ascribed to increased labour rates and "global competition for materials."

The Commission gave permission in November last year for the project to go ahead, but must approve any cost increases as it is receiving funding through electricity rate increases. The utility estimates this latest revision will "result in approximately an additional 2 percent rate impact between 2008 and 2013."

"In North America the cost of building all types of power plants has risen substantially in the past year," said James L Turner, president and chief operating officer, Duke Energy US Franchised Electric and Gas. "While we're not seeing as big an increase as some projects, the same pressures are driving up the costs of contracts from our major vendors. We're now in competition with developing nations such as China and India for materials, and we are seeing increased labour costs to build power plants."

Duke describes the plant as under construction – and site preliminary preparation is underway – but as yet there appears to have been no public announcement regarding major detailed design or equipment supply contracts or indeed that a final go/no go decision has been made by the utility.

In the current hyperinflationary climate even entering the construction phase is no guarantee that a project will go through to completion - as the curtailed Stanton IGCC project testifies. If the Indiana Utility Regulatory Commission does not approve the cost increase - and its decision is expected this summer - construction of the Edwardsport IGCC will be halted.

A front end engineering and design (FEED) study has been carried out by GE Energy and Bechtel Corporation and if the project goes ahead it would be the first to employ the standardised IGGC "reference plant" design developed under the GE/Bechtel alliance, employing GE (formerly Texaco) gasification technology.

Since completion of the FEED activities have included: negotiations with GE for an engineered equipment package and placing of a contract; negotiations with Bechtel for an EP/CM/C contract; work with Sargent & Lundy on non-proprietary scope; preliminary site work; relocation of transmission lines and upgrading of the Edwardsport substation; consideration of possible joint venture partners; and staffing up (engineers, project managers, construction, HSE).

The present plans anticipate detailed design and construction over the period 2008-2011, with major construction starting in spring 2008 and completion of the plant in 2012.

With the recent spate of cancellations, postponements and conversions of IGCC to plain old CC, Edwardsport would appear to currently be the front running IGCC project in the United States, taking over from Excelsior Energy's E-Gas based Mesaba project, which is bogged down in dealing with legal disputes about its economic viability. (Although it is interesting to note that on 7 May it was announced that Mesaba had been allocated $133.5 million in federal investment tax credits under the 2005 Energy Policy Act, of which the Edwardsport project has also been a beneficiary.)

"We continue to believe in the importance of this project," said Duke Energy Indiana President Jim Stanley. "When it's completed, this will be one of the cleanest, most efficient coal-fired plants in the world.”

"In the Midwest, coal is plentiful and relatively low-cost, and finding ways to burn it cleanly is fundamental to meeting our customers' demand for power," he added. "If we didn't pursue this project, our primary alternative would be to rely on natural gas. Natural gas is more costly than coal, and gas prices and supplies are volatile and unpredictable."

The new plant will produce 10 times as much power as the existing plant at Edwardsport, yet it will emit less sulphur dioxide, nitrogen oxide and mercury than the plant it replaces and due to the plant's superior efficiency, it also will emit 45% less carbon dioxide per MWh than the existing facility says Duke.

It would also be the first major new coal-fired power plant to be constructed in Indiana in more than 20 years. The Indiana State Utility Forecasting Group predicts that Indiana will need new power generation equal to five projects the size of this plant over the coming years.

The Edwardsport IGCC plant is slated to receive more than $460 million in local, state and federal tax incentives, which will "help reduce the customer cost impact," the utility points out. The project will result in an average customer electric rate increase of approximately 18%, phased in from 2008 to 2013.

The location of the IGCC project is an existing power plant site in Edwardsport, Indiana. Duke will retire the existing plant – with coal and oil units built between 1944 and 1951 – upon completion of the new facility.

"We believe this is the best alternative for reliably meeting our customers' power needs," Stanley said. "We think that greenhouse gases will be regulated, and coal gasification plants with carbon capture and sequestration technology hold tremendous promise to reduce carbon dioxide emissions and help address global climate change. Our goal is to make this one of the nation's first demonstrations of carbon capture and sequestration at a power plant."

In accordance with the Indiana Utility Regulatory Commission's requirements Duke Energy also filed on 1 May a request for approval of plans for studying partial carbon capture and underground storage at the new IGCC plant. If approved, the studies would look at the plant site's suitability and costs for capturing and storing carbon dioxide.

On 9 May it was announced that the Edwardsport IGCC project would receive approximately $1 million in federal funds to study the permanent storage of carbon dioxide from the plant near the site. The local geology, with sedimentary formations, looks suitable for this.

The storage research funding comes from the US Department of Energy Regional Carbon Sequestration Partnership Program, which addresses climate change by encouraging technology that reduces carbon dioxide emissions to the atmosphere from fossil fuel-fired processes.

Duke Energy's funds are part of a $61 million grant to the Midwest Regional Carbon Sequestration Partnership, a collaborative network of more than 35 members that includes eight states, state geologic surveys, universities, non-governmental organisations, state government organisations and many of the leading energy companies operating in the region. The partnership is led by Columbus, Ohio-based Battelle.

Duke Energy, one of the largest electric power companies in the United States, supplies and delivers electricity to approximately 4 million US customers in its regulated jurisdictions. The company has approximately 35 000 MWe of electric generating capacity in the Midwest and the Carolinas, and natural gas distribution services in Ohio and Kentucky. In addition, Duke Energy has more than 4000 megawatts of electric generation in Latin America.

Like most other utilities around the world Duke Energy is working hard to decarbonise its generating technology and notes, for example, that it is also meeting increased Indiana power demands through green power sources such as wind energy and in April began purchasing power from a wind farm in Benton County, Indiana.

Duke Energy Indiana also has experience with IGCC as its Wabash River Station is the site of the 260 MWe Wabash River Coal gasification project, one of the first demonstrations of the technology at large scale.

Permits received

It was in October 2004 that Cinergy/PSI (now Duke Energy Indiana), GE Energy and Bechtel Corporation signed a letter of intent to study the feasibility of constructing a commercial IGCC. It was judged that in the light of the volatile price of oil and limited supplies of natural gas available, coal was one of the most practical alternatives for addressing Duke Energy Indiana's additional baseload power needs.

According to Duke, the proposed Edwardsport IGCC plant includes the following features:

• Claus process sulphur removal system.

• An activated carbon bed for the absorption of mercury on each of the two gasifier trains.

• Two heat recovery steam generators, each equipped with selective catalytic reduction for nitrogen oxide control (providing a useful test of SCR with syngas).

• A multiple cell cooling tower.

• Collector well water supply.

• Significantly less water use and solid waste than PC coal fired plants of equivalent capacity.

• No thermal discharge into the White River.

• Potential for cost effective capture and geological storage of carbon dioxide - a feature of IGCC that GE is emphasising very much at the moment (along with low emissions of SOx, NOx, particulates and mercury).

• An alliance between Duke Energy Indiana, GE, and Bechtel to support the project. And

• Strong local support, in particular from the residents of Knox County.

In January of this year the Indiana Department of Environmental Management issued an air permit for the Edwardsport IGCC plant. "The decision on the air permit is the last approval we needed to start construction," said Jim Stanley.

A few months before, on 20 November 2007, the Indiana Utility Regulatory Commission gave its blessing to the project.

AEP projects in trouble

The attitude of the Indiana Utility Regulatory Commission to Edwardsport is somewhat in contrast to view taken by its Virginia equivalent, the State Corporation Commission (SCC), on the proposed Mountaineer IGCC project in West Virginia – also a 630 MWe plant employing the GE/Bechtel reference plant design.

On 14 April the SCC issued a statement saying it had denied a request from Appalachian Power Company (APCo) – a subsidiary of American Electric Power – to build the plant. The SCC also denied APCo's request for a rate increase to begin recovering construction costs for the new plant from its Virginia customers.

In legal terms, the SCC found that APCo's proposal was neither "reasonable" nor "prudent," a finding that must be made under Virginia law before Virginia consumers can be charged for the costs of a new power plant.

The SCC found that APCo's cost estimate of $2.23 billion was "not credible." The SCC noted that APCo's latest cost estimate was made in November 2006, had not been updated since then, and that the company had no plans to provide a detailed and updated cost estimate until after receiving all regulatory approvals.

The SCC further noted that APCo "has no fixed price contract for any appreciable portion of the total construction costs," that there were "no meaningful price or performance guarantees or controls for this project at this time," and that when APCo eventually attempted to obtain a "turn-key contract with firm pricing, it likely will be a sole-source contract with one bidder."

The SCC agreed with the Office of the Attorney General of Virginia, which opposed the proposal, that the capital cost for the proposed plant "is significantly higher than reported costs for other coal-fired units." The SCC stated, "This [proposal] represents an extraordinary risk that we cannot allow the ratepayers of Virginia in APCo's service territory to assume."

APCo had asserted that despite the uncertain cost, the value of the plant is its "potential" to capture and sequester carbon dioxide. The SCC noted, however, that the $2.23 billion cost estimate did not even include the potential cost to retrofit the plant at some uncertain future date with carbon capture and sequestration technology. APCo estimated the cost of such a retrofit at $200-300 million. The Attorney General estimated the retrofit costs at $300-500 million.

The SCC wrote, in response, that "[APCo] did not identify any commercial generation facility that has implemented carbon sequestration ... the record in this case indicates an absence of commercial deployment of carbon sequestration in generation plants such as the one proposed ... and the issues surrounding where the 'captured' carbon will be stored remain unresolved. Yet carbon capture alone, without the sequestration problem resolved, does not answer the question of what is to be done with the 'captured' carbon, and at what price. So it is literally impossible to develop a credible cost estimate for a future retrofit of this plant with both carbon capture and sequestration capability, making it likewise impossible to quantify the claimed benefits associated with IGCC technology for purposes of this application."

The SCC also indicated that, given the absence of a credible cost estimate, the use of IGCC technology for a coal-fired power plant of this size posed additional uncertainties and risks for Virginia ratepayers. The SCC noted that this would be the largest commercial power plant to use IGCC technology constructed to date, and that APCo had "confirmed that there are only two IGCC power plants operating in the United States and both plants are 'less than half' the size" of APCo's proposed plant.

"The record ... indicates that there is no proven track record for the development and implementation of large-scale IGCC generation plants like the one proposed by APCo," the SCC continued.

Finally, the SCC concluded, "We understand and appreciate ... APCo's good-faith desire to prepare for what it believes is the likelihood of a federal carbon capture and sequestration mandate for coal-fired plants. Yet neither APCo nor anyone else knows how such a future mandate may be structured, how it will affect existing plants, precisely how carbon sequestration technology and storage capacity on a massive scale will ultimately develop for large-scale generation plants, or whether it could be applied cost-effectively through a retrofit to this plant ... [APCo] also has not, at this time, provided a credible cost estimate for the proposed plant absent carbon capture and sequestration."

In the opinion of the Commission, "We cannot ask Virginia ratepayers to bear the enormous risks – and potential huge costs – of these uncertainties."

Only five weeks earlier, on 7 March, the Mountaineer project had received approval from the Public Service Commission of West Virginia (WV PSC), which granted it a "Certificate of Public Convenience and Necessity."

"West Virginia Governor Joe Manchin and the state's regulatory commissioners have wisely focused on the future of their state and our world by supporting IGCC technology," said Michael G. Morris, AEP chairman. He said he hoped for a similar decision from the members of the SCC, but that wasn't to be.

AEP's plans to build a similar 630 MWe IGCC plant in Ohio, at Great Bend, Meigs County, again using the GE/Bechtel reference plant technology – which was initially developed with bituminous eastern coals in mind – have also run into problems related to funding, this time in the Ohio Supreme Court.

The Ohio Supreme Court ruled in March 2008 that the Public Utilities Commission of Ohio must re-evaluate its decision to allow AEP to collect $23 million of preconstruction costs from its electricity customers before the plant is constructed.

Responding to the court decision American Electric Power reaffirmed its commitment to IGCC but indicated that "the company will have to wait for clarity about the future of electricity generation in Ohio before it can determine if it can build an IGCC plant in the state. "It's disappointing that the Ohio Supreme Court decision did not provide the clarity we need to move forward with construction of an IGCC plant in Ohio," said Robert Powers, president, AEP Utilities.

"We are committed to IGCC generation technology and will continue to pursue it in jurisdictions where there are conducive investment climates. We hope that the State of Ohio can resolve the path to move forward with new baseload generation, thereby bringing this technology and the associated jobs to Ohio," Powers said.

AEP has proposed IGCC technology for use as new baseload generation in the seven-state eastern portion of its service area. The company announced in August 2004 its intent to scale up IGCC technology and build approximately 1200 MWe of large, commercial-scale IGCC generation.

Other IGCC initiatives in the USA

Omaha-based independent power developer Tenaska is also pursuing the possibility of using the 630 MWe GE/Bechtel reference plant IGCC technology with high sulphur Illinois coal.

In June 2007, following a two year application process, the Illinois EPA granted an air permit for the Taylorville IGCC project, which is being developed by Christian County Generation (CCG) a joint venture of Tenaska and Louisville-based MDL Holding Co (formerly ERORA Group), with Tenaska managing member of the project. This was said to be the first US air quality permit for a commercially-sized IGCC plant.

The Sierra Club lodged an appeal an against the award of the permit but this was denied by the US Environmental Appeals Board in January 2008, paving the way for the project to move forward once enabling legislation is passed by the Illinois General Assembly (Tenaska, working with the Citizenís Utility Board, is proposing legislation – the Clean Coal Development Program Law – that would change the rules to allow developers to enter into long-term, cost-based contracts with large Illinois electric utilities).

In denying the Sierra Club’s appeal, primarily on the grounds that it failed to raise its objections in a timely way, the EAB noted that the Taylorville project’s environmental performance will set a new standard: CCG’s proposed IGCC facility is projected to have an SO2 removal efficiency of more than 99% and possibly as high as 99.8%. Similar improvements in pollutant removal will be obtained for particulates, nitrogen oxides, mercury and lead.

EAB questioned the Sierra Club’s arguments given the organisation’s numerous past statements supportive of IGCC technology. For a number of years, Sierra Club has argued that IGCC technology should be adopted as the best available control technology for limiting air pollutant emissions from coal generation.

In February, Luminant, the power generation subsidiary of Energy Future Holdings, announced it had received 14 expressions of interest in response to its request for proposals from companies offering IGCC “or other coal gasification technologies with the ability to capture carbon dioxide emissions.”

“We are very pleased to have received interest from virtually all the major suppliers of this type of equipment,” said Mike Greene, Luminant's CEO.

Luminant's timeline calls for detailed proposals to be submitted by June 2008, with a view to exploring the feasibility of building two commercial scale demonstration plants in Texas, fulfilling a commitment made by Kohlberg Kravis Roberts & Co. and Texas Pacific Group during their acquisition of TXU Corp, now Energy Future Holdings. In its deliberations EFH will benefit from the input of its newly formed Sustainable Energy Advisory Board.

While cost inflation remains an issue for IGCC (as well as other large power projects) in the USA, new proposals keep coming up. For example, as reported in this month's news, IGCC plus carbon capture and storage figures prominently in the US Department of Energy's restructured FutureGen programme.

Meanwhile in April Southern California Edison announced a major feasibility study which seems to bear a rather close resemblance to the FutureGen exercise as originally conceived, ie IGCC plus CCS with a strong emphasis on hydrogen.

Southern California Edison says it will conduct the USA's first feasibility study combining several advanced coal technologies at full commercial scale. The decision to move forward with the two-year, approximately $50 million technology assessment follows approval of the plan by the California Public Utilities Commission (CPUC) SCE will make the study results available to all interested parties.

SCE's advanced coal generation study combines the following elements:

• Capture of as much as 90% of the carbon dioxide by chemical means.

• Producing a mostly hydrogen fuel and emitting only 10% of the carbon released by an IGCC without carbon capture.

• Burning the hydrogen in a highly efficient, combined-cycle generation system.

• Sequestering the carbon dioxide in a deep saline formation or a depleted oil formation for enhanced oil recovery.

• The use of these technologies in a full-scale, 600 MW commercial generation facility.

Like Duke, SCE’s involvement with IGCC goes back a long way. In fact the first major use of coal gasification to generate electric power in the United States took place in the mid-1980s at Southern California Edison's 110 MWe Cool Water demonstration plant near Barstow, California.

In October last year the US Department of Energy announced a grant of more than $65 million to SCE and other participants in the Southwest Regional Partnership for Carbon Sequestration to inject carbon dioxide into the Entrada sandstone formation in the south western United States. This sequestration study is one of the elements of SCE’s advanced coal feasibility study.