Duke Energy Indiana pushes back Edwardsport IGCC in-service date to late this year

A Duke Energy (NYSE: DUK) subsidiary now expects it will be the fourth quarter of this year and perhaps early 2013 before the $3bn-plus Edwardsport IGCC project in Indiana begins normal commercial operation.

This was part of the testimony provided by a Duke subsidiary official recently to a state commission. There are no red flags here, but a number of technical issues that must be ironed out, said Michael Womack, who works for Duke Energy Business Services LLC, a service company subsidiary that provides services to Duke Energy Indiana.

Womack, vice president for the Edwardsport IGCC Project, filed testimony June 8 at the Indiana Utility Regulatory Commission as part of an update on the status of the Edwardsport integrated gasification combined cycle repowering project.

During the testimony Womack said Duke and its vendors want to get the technical issues resolved before putting the new generation coal plant into service because the project continues to face much scrutiny. The official also noted a revised cost estimate for the project.

During the first quarter earnings conference call in May, Duke officials had indicated that they expected the 618 MW IGCC in service this fall.

The coal handing systems at the revamped Edwardsport power plant have been fully and successfully commissioned, and the unloading facility and conveyors have already been used to unload several trains of coal that have been arriving via the recently-completed railroad spur.

In the gasification island, the emphasis is on completing the remaining precommissioning activities and the commissioning of individual components of the area, Womack noted. For example, one of the two coal grinding rod mills has been tested and is ready to grind coal at the appropriate time, the four CO2 recycle compressors have all been tested and operated successfully, and two of the acid gas removal refrigeration compressors have been tested. Also, the blowers in the tail gas unit and the sulfur recovery unit have been started and run through several hours of testing.

In the power block, major progress has been made in commissioning and New Product Introduction (NPI) testing of the combustion turbine/generators (CTGs). CTG-2 was ignited on natural gas for the first time (first-fire) on March 14 and reached full speed, no load (FSNL) status that same day. CTG-1 achieved first-fire on March 21 and achieved FSNL, was synchronized to the grid, and generated approximately 25 MW during a very successful run of more than 8 hours on March 30. On April 18, CTG-1 reached full load, producing about 210 MW of power that day. CTG-1 continued to run during late April and early May in order to perform Phase 2 of the NPI testing, which concluded on May 5.

On May 14, equipment supplier General Electric (NYSE: GE) issued a technical release document to Duke Energy Indiana; a step which authorizes the further operation of both CTG-1 and CTG-2 on natural gas. With this release, Duke Energy Indiana has begun to operate both units simultaneously in order to complete the commissioning of the steam turbine and other power block equipment.

Womack said there have been a number of equipment problems that have turned up, but nothing that should have any major impact on longer-term plant operation. “Although there have been a number of challenges and issues, the Project team has proved to be well equipped to handle the challenges posed,” he added. “We have aggressively worked all of these issues to successful resolution in a safe manner while attempting to minimize the impact on schedule and costs and will continue to do so as additional challenges are uncovered. I would be remiss if I did not mention that the intense focus and scrutiny every issue, problem or challenge has gotten as a result of the extensive and extended regulatory review of the Project is beyond anything I have experienced in my long career. I hope that this increased focus, while understandable under the circumstances, does not unfairly burden this Project in a negative light. I am proud of the hard work done in Southern Indiana each and every day on this Project and of the team that is continuing to rise to meet the challenges we have experienced on the Project site.”

In-service date projection slips from September to late 2012

In 2010, when the project team developed the baseline schedule, a target date in September 2012 was set for declaring the plant in-service and a target date in December 2012 was set for “Substantial Completion.” Because of the commissioning and testing delays, the forecast dates for achieving those milestones have slipped to the late 4th quarter of 2012 and the 1st quarter of 2013, respectively, Womack noted. “Because new issues and associated delays arise frequently, forecasting a precise date for these two schedule milestones also changes frequently. Further, due to the unpredictable nature of the remaining commissioning and NPI activities, largely under GE’s control, it is difficult to forecast a specific date. We have now entered a stage of the Project where our efforts are focused on optimizing and minimizing our response time for resolving emerging issues and challenges.”

Another issue that contributes to uncertainty in the remaining project schedule activities is a lack of consensus between Duke Energy Indiana and GE regarding the sequence and timing of certain critical NPI and safety system testing, which will be performed by GE, Womack added. GE’s project leadership has generally asserted that Duke Energy Indiana’s commissioning schedule in the gasification island is “overly aggressive,” he wrote.

“We have conducted multiple work sessions between the Duke Energy Indiana commissioning schedulers and GE’s on-site scheduling and commissioning personnel but have not been able to successfully determine the causes of concern and schedule cautions,” Womack wrote. “If their assertions that we will not be able to achieve the schedule goals in this area are valid, then the in-service date may be additionally adversely affected.”

Duke Energy Indiana works to keep costs under a cap

As for project costs, in October 2011, the Duke Energy Board of Directors approved a revised cost budget for the project of $3.27bn. This amount includes a direct cost budget of $2.917bn plus a $62m contingency allowance and a $291m AFUDC allowance. As of the end of March 2012, the project team is still forecasting a final direct cost of $2.98bn (with $11.4m of remaining contingency). “Given the issues and challenges we have encountered so far during start-up and commissioning, there remains some risk of exceeding this budgeted amount,” Womack said. “The forecast amount for AFUDC has risen to about $355 million (under the most current assumptions), giving a total capital cost forecast as of the end of March 2012 of $3.35 billion.”

The company recently filed with the commission a settlement agreement reached with most of the parties in a project case before the commission. If approved, the settlement agreement provides for a hard cap of $2.595bn (plus additional accrued AFUDC on and after July 1, 2012), thus mitigating the potential impact to customers of any future budget exceedances at the project, Womack said.

Jack Stultz, who works at Duke Energy Business Services as General Manager II, Regulated Fossil Stations, noted in companion June 8 testimony that demolition of the old Edwardsport coal plant is scheduled to be completed in early October. The main coal conveyor and the early 1900s building structure have both been demolished, and asbestos abatement and waste removal throughout the plant is ongoing.

Stultz also noted that the new coal handling system has been receiving truck and train deliveries and performed as expected. The project currently has approximately 277,000 tons of coal in inventory, which will build to a level of approximately 400,000 tons of coal by the end of the year. “Coal is being received by train from Peabody’s Bear Run Mine with planned deliveries of four trains per month until planned gasification operation begin in late July 2012,” he added. “After that time, we expect deliveries to be set to match coal usage at the Project.”

Bear Run is a relatively new strip mine in Indiana that Peabody Energy (NYSE: BTU) is ramping up to a full run rate of about 8 million tons per year, making it the largest coal strip mine in the eastern U.S.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.