The estimated cost of converting the oil-fired Anclote power plant to burning natural gas has jumped by about $15m, to a current $94.3m, due to some issues related to fan systems.
In other newly-filed testimony, a Duke Energy (NYSE:DUK) subsidiary has decided to retire, not retrofit, two coal units at the Crystal River power station in Florida.
George Hixon, employed by Progress Energy Florida (PEF) as Manager of Major Projects in the Project Management and Construction group, outlined the status of the Anclote project in April 1 environmental case testimony filed at the Florida Public Service Commission. PEF since mid-2012 has been a unit of Duke.
The Anclote conversion is needed to comply with the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS). The company originally estimated and the Florida commission approved $79.3m in total project costs.
“The $15 million increase in total project costs is due to changes in the forced draft (FD) fan systems, Hixon noted. “[T]he $79.3 million estimate was subject to change based on the results of an ongoing engineering evaluation to determine whether changes to the Anclote units FD fan systems were needed. Specifically, the changes would allow PEF to meet MATS compliance requirements while maintaining current maximum output. PEF has completed the engineering analysis and determined that the existing draft fans are not sufficient to maintain maximum output. Therefore, some changes to the FD fan systems are required. A decision on the appropriate option was made in late 2012 to enable the FD fans to be installed in 2014. The changes consist of new fans, motors, variable speed drives and two auxiliary transformers.”
Switching from #6 fuel oil to natural gas slightly decreases boiler thermal efficiency requiring additional boiler heat input to achieve the same electrical output, Hixon explained. The additional heat input is achieved by increasing fuel flow and combustion air supplied by FD fans. After testing the existing FD fans and considering options for increasing combustion air, PEF decided the existing fans were not capable of providing sufficient air.
PEF continues to expect that both Unit 1 and Unit 2 will be fully converted to natural gas in late 2013. But, installation of the FD fans will be not be completed until early in the second quarter of 2014 due to long lead time involved to purchase necessary equipment. PEF needed to conduct detailed engineering analysis to verify that FD fan system installation would be an effective and feasible solution, and the time needed to complete the analysis precluded ordering equipment to support a 2013 installation. Each unit will be placed into service as it is converted to natural gas, however, maximum output of each unit cannot be achieved until the new FD fans are installed.
The Florida commission in August 2012 approved the conversion of Anclote to 100% natural gas. Anclote Units 1-2 currently have a maximum summer rating of 500 MW and 510 MW, respectively. The current natural gas firing capability for each unit is limited to 40% of the total heat input. Because the balance of the heat input is from heavy fuel oil, the units would be subject to MATS limits for oil-fired electric generating units. However, PEF has determined that the most cost-effective compliance option is to convert the units to fire 100% natural gas and thereby remove the units from MATS regulation.
PEF to shut Crystal 1-2 coal units, though a brief extension possible on new coal
Also, in companion April 1 testimony, Benjamin Borsch, employed by the Integrated Resource Planning and Analytics Department of PEF as Director of Integrated Resource Planning and Analytics for Florida, said the company has decided to retire, not retrofit, the coal-fired Units 1-2 at the Crystal River power plant. The coal-fired Units 4-5 at Crystal River are newer, bigger and have gotten emissions retrofits in recent years that will keep them running for the long term. The nuclear Unit 3 is shut and about to be permanently retired.
“PEF cannot continue to operate the Crystal River Units 1 and 2 without implementation of additional measures to bring the units into compliance with MATS,” Borsch noted. “Accordingly, the two main options that PEF considered were: (1) installing new emission control systems to reduce NOx, SO2 and mercury emissions; and (2) retiring the units and replacing the generation.”
To determine the most cost-effective compliance option for CR 1 and 2, PEF conducted a lifecycle cost analysis of all costs associated with both options. PEF focused on the comparative economics of a scenario in which Crystal River Units 1 and 2 continue to operate through 2041, equipped with significant life extension upgrades, state of the art emission control systems and a long term supply of low cost coal, versus a scenario where the units are retired in 2016.
PEF has decided that installing emission controls at Crystal River Units 1 and 2 is not the most cost-effective option to achieve MATS compliance. PEF is evaluating alternative fuel options that would allow Crystal River Units 1 and 2 to continue operating in compliance with MATS for a limited period of time. PEF plans to schedule and obtain permits for operational tests in 2013 to determine how the units perform with unnamed, alternative coals. If these tests are successful, it may be possible for PEF to extend Crystal River Units 1 and 2 operations to the 2018-2020 timeframe while still being in compliance with MATS.
MATS first takes effect in April 2015, with two one-year extensions of that deadline possible under certain circumstances.
Said an April 1 environmental plan update filed with the commission along with this testimony: “If the Company elects to shut down Crystal River Units 1 and 2, there are a variety of power resource options under consideration to address the timing and scope of replacement power needs, including both purchased power and self build options. Shutting down Crystal River Units 1 and 2 eliminates roughly 900 MW of coal-fired baseload generation which will ultimately need to be replaced to meet reliability and economic needs on the system. Specific recommendations for replacement power are actively being developed and pursued by the Company’s planning and development teams. For the purposes of the long term comparative economic evaluation of alternatives, the replacement capacity and energy is assumed to be a blend of natural gas combined cycle and peaking energy which is reasonable for planning purposes and representative of the options PEF is pursuing.”
Here are net generating capacity, plus projected capacity factors and coal burn figures for each Crystal River coal unit in 2013, as previously filed by the company with the commission.
- Unit 1, 376 MW, 11.4% capacity factor, 165,226 tons of coal burn;
- Unit 2, 497 MW, 24% capacity factor, 459,548 tons of coal burn;
- Unit 4, 727 MW, 67% capacity factor, 1.87 million tons of coal burn; and
- Unit 5, 706 MW, 70.2% capacity factor, 1.93 million tons of coal burn.