Duke Energy will swallow $30 million in runaway costs associated with operating its five-year-old 618-MW integrated gasification combined cycle (IGCC) facility in Edwardsport, Indiana, if a settlement the company reached with Indiana consumer groups last week is approved.
Duke declared Edwardsport Generating Station “in service” in June 2013, despite a series of hiccups that delayed the project more than two years, prompting $1.5 billion in cost overruns, as well as legal challenges and an ethical scandal. In June 2013, the project’s price tag stood at $3.4 billion. According to recent testimony offered to the Indiana Utility Regulatory Commission (IURC), the project has since proved expensive to operate.
Duke Takes a $32M Hit
The settlement Duke Energy Indiana reached with groups, including the Indiana Office of Utility Consumer Counselor (OUCC), the Indiana Industrial Group representing Duke Energy’s Indiana customers, and Nucor Steel-Indiana, on September 20 pertains to operating and maintenance (O&M) costs for the Edwardsport plant in 2018 and 2019.
If approved, Duke Energy Indiana retail customers will receive a $30 million credit in future bills by reducing the balance of the regulatory asset.As well as providing $1.7 million in company funding for low-income energy assistance and renewable projects in Indiana, the agreement also seeks to cap the amount Duke can recover in Edwardsport O&M expenses for 2018 at $97.6 million, and for 2019, at $96 million.
“If costs fall below the caps, customers will pay the actual amounts. If costs rise above the caps, customers will pay the capped amounts and will not be responsible for any overruns,” Anthony Swinger, a spokesperson with the OUCC told POWER on September 25.
Duke’s O&M expenses—defined in the settlement to include O&M expenses, payroll taxes, property taxes, property insurance, and net of the credit for operating expenses of the retired Edwardsport units—that are incurred after January 2020 will be addressed in its next rate case. The settlement notes that Duke anticipates O&M expenses in 2020 will be greater than in 2019 owing to a scheduled major outage in 2020 of the entire station.
“This newly filed agreement will provide the consumer protections necessary to make sure Duke Energy’s customers are not being overcharged for the plant’s continued operations,” Swinger said, though he noted the IURC must still approve it. An evidentiary hearing on the agreement is scheduled in mid-December, but the date is subject to change. “An order will come in the weeks following the hearing. The IURC can approve, modify, or deny any settlement agreement,” he said.
Because of the agreement’s provisions, Duke expects to take a pretax charge of approximately $32 million in the third quarter of 2018. But for Duke, the agreement is important, because if approved it will remain in effect until new rates are established in the company’s next base rate case, which is expected to be filed in mid-2019 with rates effective in mid-2020. It also eliminates the need for future filings until the overall rate case.
“If approved, this agreement saves customers money and provides rate certainty between now and our next base rate review,” said Duke Energy Indiana President Melody Birmingham-Byrd in a statement on September 21.
Birmingham-Byrd emphasized that the IGCC plant’s performance has been strong of late, noting that it recently “set a record of 464 days of continuous net generation through April 2018.” The company also said that Edwardsport is a dual-fuel plant that can run on coal and natural gas, and in 2017, “it was available for service 99 percent of the time when factoring in both fuels.”
Operation and Maintenance Issues
But according to David Schlissel, director of resource planning analysis for the Institute for Energy Economics and Financial Analysis (IEEFA), the project—which he called an “experiment”—has “turned out to be a catastrophe for ratepayers.”
In testimony filed with the IURC this August, Schlissel said that the plant’s total O&M costs alone average $60/MWh since it opened. Its “core problem,” he said, “is that it is uneconomical unless both trains of its gasification plant operate as intended, in tandem, with both of its combustion turbines and its steam turbine producing electricity at a net capacity factor averaging 82% or more when operating on syngas. It is operating at barely half that factor.”
Schlissel also alleged that the plant continues to lose a significant portion of its potential generation due to gasifier equipment problems, “which explain its extremely poor 40% capacity factor on syngas during its first 55 months of operations, far below the 79% average capacity factor projected by Duke.” He also said that the plant continues to consume large amounts of parasitic power and suffers a high heat rate.
“The all-in cost of power from the plant, including financing costs and profits for Duke, averaged $145 per megawatt-hour (MWh) over the 55 months from its opening in June 2013 through December 2017,” he said.
Responding to questions about O&M costs, on September 28, Angeline Protogere, a Duke spokesperson, told POWER that plant operating expenses at Edwardsport are falling. “They decreased from 2016 to 2017, and we are forecasting a decrease in 2018 and again in 2019,” she said. “The exception will be in 2020 when we have a major planned outage. Our objective is a continued downward trend in expenses.”
Plant performance at the plant was also notable, Protogere said. “The plant had strong operations throughout 2017: 78% gasifier availability level; 99% availability when you factor in both coal and gas; and a net capacity factor—run time on both coal and natural gas—of 73%.”
A History of Cost Surges
While the project was conceived in 2006, Duke requested the IURC approval to recover the project’s then-estimated cost of $1.985 billion in 2007. It revised the cost estimate to $2.35 billion in 2008, which the IURC approved in January 2009. Construction began in 2008 at the site of a coal plant first developed in 1918, but whose three operating units had been constructed between 1944 and 1951. Those units were retired in 2011.
The company broke ground on the project in June 2008, anticipating that it would use 1.5 million tons of coal per year for the then-envisioned 630-MW plant expected to open in 2012. But in November 2009, Duke submitted a new revised cost estimate of $2.88 billion, prompting outrage from consumer groups, including the OUCC. In July 2010, the OUCC recommended a cap on project costs, expressing “serious concerns” about the project’s cost increases and “continuing inaccurate cost estimates.”
A 2012 settlement proposed to end five years of litigation involving the OUCC, the Duke Energy Industrial Group (which consists of six of the utility’s large industrial customers), Nucor Steel, and Duke put a $2.595 billion cap on project costs to be included in electric rates. The IURC in December 2012 ruled that Duke, not its customers, would bear all cost overruns.
Duke finally declared the project in service on June 7, 2013, touting it as one of the “world’s cleanest” coal plants—but it shut it down only six days later owing to technical issues. The plant reached 60% capacity in August, only to suffer mechanical failures again during that winter, which reduced output to a trickle.
Months after it officially opened, the OUCC and other parties sued the company concerning its “in service date,” filing separate litigation to address the recovery of testing and start-up costs, and in September 2015, the OUCC, industrial customers, and Duke reached an agreement providing an additional $85 million in ratepayer relief. In January 2016, that settlement was superseded by another agreement, raising relief to $87.5 million. It was approved by the IURC in August 2016.
The current settlement stems from a state law that allows Duke to approve adjustments to a billing component—known as the “IGCC rider.”
A Project with Merits
Despite Edwardsport’s exorbitant cost overruns, it was a POWER magazine Top Plant in 2013. The editors noted it was a controversial choice, but argued it merited the distinction because it commercialized state-of-the-art gasification technology. “At the time, Duke was a strong supporter of several ill-fated legislative carbon control proposals,” former POWER Editor-in-Chief Robert Peltier wrote. “Whatever your personal feelings about carbon controls, one must appreciate Duke’s single-mindedness in deploying ‘bleeding edge’ technologies, particularly in an industry customarily uninterested in serial No. 1 projects, particularly those with a nine- or 10-digit price tag.”
As POWER noted, Edwardsport 2 x 1 IGCC uses a coal gasification system to convert coal into a synthesis gas (syngas) that fuels the combustion turbines (CTs). Bechtel Corp. was responsible for project design and construction of the plant based on General Electric (GE) gasification technology. GE provided the process design and two separate trains of its radiant quench gasification equipment. “The process—capable of using high-sulfur, high-ash coals found in the Midwest—converts the coal into a slurry and feeds it into the gasifier along with oxygen, where it is turned into raw syngas consisting of H2 and CO. The raw syngas is next scrubbed of flyash, mercury, chlorides, and sulfur before it is burned in the CTs.”
The project remains only one of a handful of IGCC power plants in operation around the world. In the U.S., these include the 1999-commissioned Wabash River Power Station in West Terre Haute, Indiana; the 1996-commissioned Polk Power Station in Tampa, Florida.; and Piñon Pine in Reno, Nevada.
Around the world, ELCOGAS’ Puertollano IGCC plant in Spain was first fired with syngas in 1998. The Netherlands also has a 253-MW IGCC plant that began service in 1994 as a demonstration facility in Buggenum. China’s Huaneng Group demonstrated successful startup of its 265-MW GreenGen IGCC plant in Tianjin City in April 2012. That project on September 25 celebrated a new record, running 3,917 hours or around 163 days continuously.
Meanwhile, though it echoed Edwardsport’s turbulent and costly construction process, Southern Co. in June 2017 scrapped the 582-MW Kemper County energy facility days before it was expected to be in service, after the company proposed it would need post in-service improvements. Kemper was designed as an IGCC to convert locally mined lignite to synthesis gas, usingnovel TRIG technology to capture up to 65% of its carbon emissions. But owing to a number of technical hurdles, the project had been delayed nearly three years. It was originally projected to be placed into service in May 2014. Total costs, meanwhile, exceeded $7.5 billion, a figure that factored in mine, carbon dioxide pipeline, and other accounting costs.
This February, Southern Co. agreed to absorb the majority of outstanding costs resulting from the scuttled project. In a press release on August 8, Southern Co. noted additional pre-tax cancellation costs of up to $25 million for Mississippi Power Co.’s Kemper IGCC are expected to occur during the remainder of 2018 and 2019.
—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)
Updated (Sept. 28): Adds details from Duke about O&M costs and plant performance.