Duke opts for temporary air controls, like DSI, at two Crystal River units

Duke Energy Florida applied Dec. 31 at the Florida Public Service Commission for approval of costs for temporary emissions control equipment to comply with air emissions mandates at its coal-fired Crystal River Units 1 and 2.

The larger, newer Units 4 and 5 at the Crystal River plant, also fired by coal, don’t have any major need right now for new emissions controls. Unit 3 is a shut nuclear facility that is in the process of being retired. Duke Energy Florida, formerly known as Progress Energy Florida, is a unit of Duke Energy (NYSE: DUK).

The Crystal River coal units and their net capacities are:

  • Unit 1 – 376 MW;
  • Unit 2 – 497 MW;
  • Unit 4 – 727 MW; and
  • Unit 5 – 706 MW.

In addition to Mercury and Air Toxics Standards (MATS) requirements, Crysal River Units 1 and 3 (CR 1 and 2) are subject to Best Available Retrofit Technology (BART) and Reasonable Further Progress (known as “Beyond BART”) requirements under Clean Air Visibility Rule (CAVR). In accordance with BART requirements, The Florida Department of Environmental Protection has established new particulate and opacity permit limits for CR 1 and 2 which have been incorporated into a revised Regional Haze State Implementation Plan (SIP).

In order to address Beyond BART requirements which are scheduled to take effect in 2018, the revised SIP further requires Duke Energy Florida to install flue gas desulfurization (FGD) and selective catalytic reduction (SCR) on CR 1 and 2 by 2018 or cease burning coal in the units on or before the end of 2020. EPA approved the revised SIP in August 2013.

Although third parties recently petitioned for review of EPA’s approval in the U.S. Eleventh Circuit Court of Appeals, that rule has not been stayed by the court in the meantime.

The utility noted that it has decided not to install the FGD and SCR, at a cost of over $1bn, on these older coal units, opting instead to shut them around 2020. The two options looked at were:

  • Retire CR 1 and 2 in April 2016 before the MATS compliance deadline (assuming the utility gets a one-year extension on the initial April 2015 MATS deadline) and meet system requirements with purchased power and/or new resources in a manner that the grid would support.
  • Configure the units to operate in compliance through mid-2018, and establish a resource plan to provide for replacement combined-cycle generation in that timeframe. This alternative includes a competitive solicitation for combined-cycle energy and capacity starting in 2018, identification of additional resources needed in 2016 and beyond, and a transmission plan that supports the required resources.

The results of the quantitative economic analysis indicate that the lifecycle projected system cost (CPVRR) for the option of limited continued operation of CR 1 and 2 through mid-2018 (Alternative 2) was $307m lower overall than the system CPVRR for the option retiring the units in mid-2016 (Alternative 1).

Furthermore, the qualitative planning assessment concluded that the limited continued operations alternative has a significant positive impact on system reliability if operations of CR 1 and 2 are continued until replacement generation can be added near the Crystal River plant site, or until transmission projects can be completed to address grid concerns.

Temporary emissions controls came out as the cheapest option

“Based on the results of those evaluations and tests of alternate coals at CR 1 and 2, DEF has determined that use of alternate coals with installation of less expensive pollution controls, at a total project cost of approximately $28 million, would provide a cost-effective means for DEF to continue operating CR 1 and 2 in compliance with MATS (and CAVR) requirements for a limited time until replacement generation can be constructed,” said the Dec. 31 filing. “The new pollution controls include dry sorbent injection (‘DSI’) for control of acid gas emissions, activated carbon injection (‘ACI’) for control of mercury emissions, and changes to the electrostatic precipitators (‘ESPs’) for control of particulate emissions. The planned DSI and ACI systems will be relatively small to meet the emission reduction levels envisioned, and will be set up to operate intermittently or continuously, depending on the needs of the facility. In addition to the above project costs, DEF expects to incur annual O&M costs of approximately $2 million while the new pollution controls remain in operation.”

In order to ensure that the costs incurred for these activities are prudent and reasonable, Duke Energy Florida said it will identify qualified contractors and, when appropriate, will use competitive bidding.

In the Dec. 31 petition, Duke Energy Florida is asking the commission for approval of the passthrough of costs of these projects from this point forward though an environmental cost rate recovery mechanism.

Units 4 and 5 at Crystal River are equipped with new-ish emissions controls, like FGDs, and are not in danger of shutting. Under the terms of a revised air permit, Crystal River Units 1 and 2 are required to cease coal-fired operation by the end of 2020 unless scrubbers are installed prior to the end of 2018.

Crystal River Units 1 and 2 have traditionally been fired with Central Appalachia coal. U.S. Energy Information Administration data shows that the plant got its coal in 2013 from various suppliers, including B&W ResourcesArch Coal SalesJames River Coal and Alpha Natural Resources. Test blends of coal in 2013 at these units, designed to find ways to get emissions reductions beyond the planned DSI/ACI installations, were of western bituminous and Powder River Basin coals. Units 4 and 5, which have SO2 scrubbers, burn high-sulfur coals from the Illinois Basin from suppliers like American Coal and Knight Hawk Coal LLC.

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.