The Kentucky Public Service Commission wants to know a lot more about the environmental compliance planning of Big Rivers Electric, including more details about a planned conversion of the coal-fired Reid unit 1 to natural gas and a replacement SO2 scrubber for the coal-fired Wilson plant.
In a May 21 order, the commission asked Big Rivers Electric a series of follow-up questions on the cooperative’s 2012 environmental compliance plan. The answers need to be turned over to the commission by June 1.
- One question had to do with how Big Rivers will replace the demand and energy normally be provided by Wilson unit 1 during the three-year period from 2013 through 2016 when a new flue gas desulfurization, or scrubber, system is being fabricated and constructed.
- Another proposed project is the completion of the Reid 1 conversion to natural gas. A Big Rivers witness said that four of the boiler’s eight coal burners were converted to natural gas in 2004 but that the burners were never permitted, tested or put into service. The commission wants various information about this conversion, including whether there is an adequate supply of gas to serve a converted Reid 1 and how the conversion would exempt Reid Unit 1 from the Mercury and Air Toxics Standards (MATS) requirements from the U.S. Environmental Protection Agency.
- Big Rivers stated that the portion of the 2012 compliance plan related to the coal-fired Station Two is currently under review by plant owner Henderson Municipal Power and Light (HMP&L). The commission wants an update on the status and timetable of that review.
- The commission noted that consultant Sargent & Lundy did a study for Big Rivers that used a natural gas forecast of $4.50/MMBtu. “Recognizing that the current cost of natural gas is $2.00/MMBtu, what is the impact of a continued low natural gas price forecast on the proposed environmental compliance decisions?” the commission wrote.
- At one point in its filing, Big Rivers said that returning a scrubber at the coal-fired Coleman plant back to as-designed operation conditions produces a further emissions cut. “Explain how and why the Coleman scrubber is not currently operating as designed,” the commission wrote. “Include in your response the cost to return the scrubber back to as-designed operations.”
- A Big Rivers Electric witness discussed a proposal to add a dry sorbent injection system at the Coleman, Wilson, and Green units for acid gas removal. It said this would help reduce SO2 emissions for Cross-State Air Pollution Rule (CSAPR) requirements and that those reductions would be a “surrogate” that would help with MATS compliance. “Is there uncertainty as to whether this proposal will make Big Rivers compliant with the MATS rule?” the commission asked. “If yes, explain.”
Reduction needs exceed capability of some emissions controls
Robert Berry, Vice President of Production at Big Rivers, said in April 2 testimony to open this case that Big Rivers’ 2012 plan includes: installing a new scrubber at Wilson to increase SO2 removal efficiency from 91% to 99%; installing selective catalytic reduction (SCR) on Green Unit 2 to increase NOx removal efficiency from 50% to 85%; modifying the scrubbers on HMP&L Station Two Units 1 and 2 to improve SO2 removal from 93.5% to 97%; and converting Reid Unit 1 to burn natural gas instead of coal, as necessary, to comply with CSAPR.
To comply with the new MATS regulation, Big Rivers must install activated carbon injection equipment for mercury (Hg) removal, dry sorbent injection equipment for acid gas removal, and continuous emission compliance monitors on all three Coleman units, the two Green units and the Wilson unit. And even though testing has proven the two HMP&L units are low mercury emitters, continuous emission monitors must be installed to demonstrate constant compliance. As for Reid Unit 1 and the Reid Combustion Turbine, natural gas-fired units are not subject to the MATS regulation.
With the exception of one, all of the coal units owned and operated by Big Rivers are already fitted with SO2, NOx and particulate control equipment. If operating at its projected capacity (above 80% net capacity factor), the Big Rivers fleet will not be capable of meeting CSAPR and MATS without significant capital investment in additional emissions equipment, Berry noted. Unless emission removal efficiencies are improved, generation will need to be curtailed by 27% from historic levels in Phase 2 of CSAPR. An investment in pollution control equipment will be more cost effective than reducing generation. “In order to meet the proposed CSAPR and MATS regulations it is imperative that Big Rivers invest in the pollution control technologies contained in the 2012 Plan,” Berry wrote.
Wilson – Although the Wilson unit currently has a scrubber, its SO2 removal efficiency is only 91%. SO2 removal efficiency on the Wilson unit must be improved to 99%. There are no known modifications or engineering solutions to adequately improve the existing scrubber’s removal efficiency; thus, a new advanced scrubber must be built, Berry said. The new scrubber system will reduce the Wilson unit’s projected 2016 SO2 emissions from 8,740 tons to 1,845 tons.
Preliminary engineering and design for this Wilson scrubber project will begin in 2012 with final drawings completed and approved in 2013. Fabrication and construction will begin in 2013 with completion and acceptance scheduled for Jan. 1, 2016. The estimated capital cost for this project is $139m.
Green – Green Unit 2 is currently equipped with a proprietary coal re-burn technology for NOx control with reduction capability of 50%. However, NOx reduction at this unit must be improved to 85% to meet CSAPR. There are no known modifications or engineering solutions to adequately improve reduction capability for the current re-burn system, so a new SCR must be built. The new SCR equipment will reduce projected 2016 NOx emissions from Green Unit 2 from 2,413 tons per year to 336 tons per year.
Preliminary engineering and design for the Green SCR project will begin in 2012 with final drawings completed and approved in mid-2013. Fabrication and construction will begin in 2013 with completion and acceptance scheduled for July 1, 2015. The estimated capital cost for this project is $81m.
Reid – Reid Unit 1 is the smallest and oldest plant in Big Rivers’ fleet and is currently not equipped with SO2 or NOx control equipment. In 2004, four of the boiler’s eight coal burners were converted to natural gas to meet the Clean Air Interstate Rule NOx State Implementation Plan call regulation; however, the gas burners were never permitted, tested, or put into service due to high natural gas pricing in the mid 2000s. A Sargent & Lundy study determined that the best way to bring this facility into compliance was to complete the existing conversion project and fire the boiler solely with natural gas.
Engineering and design for this Reid Unit 1 project will begin in 2012 with final drawings completed and approved in 2013. Maintenance and testing will begin in 2013 with completion and acceptance scheduled for Jan. 1, 2014. The estimated capital cost is $1.2m. Anticipated increases in fuel cost will most likely cause this unit to continue to be used for peaking service in the future, Berry noted.
Station Two – Although HMP&L Units 1 and 2 are currently equipped with scrubbers, their SO2 removal efficiency is only 93.5%. SO2 removal efficiency on the HMP&L units must be improved to 97%. The S&L study determined that by installing additional slurry recycle pumps and modifying the booster fans to offset the additional pressure drop across the scrubber towers, SO2 emissions could be reduced sufficiently to comply with CSAPR. This project will reduce the projected 2015 SO2 emissions from the HMP&L units from 5,637 tons to 2,054 tons per year.
Preliminary engineering and design for the HMP&L scrubber upgrade project will begin in 2012 with final drawings completed and approved by mid-2013. Fabrication and construction will begin in 2013 with completion and acceptance set for Jan. 1, 2015. The estimated capital cost is $6.3m. Big Rivers has submitted the Station Two portion of the 2012 plan to HMP&L for review.
Coleman, Wilson, and Green – These plants will need to reduce mercury emissions to comply with MATS. Activated carbon can be injected into the exhaust gas to react with the mercury, and the combined elements can be collected with particulate removal equipment. The presence of acid gases, specifically sulfur trioxide (SO3), inhibits the reaction between mercury and activated carbon, but industry testing has revealed that injecting a dry sorbent such as hydrated lime or trona to capture SO3 ahead of the activated carbon would restore the reaction between the carbon and mercury, Berry wrote.
Preliminary engineering and design for the activated carbon and dry sorbent injection projects at the three plants will begin in 2013 with final drawings completed and approved by mid-2014. Fabrication and construction will begin in 2014 with completion and acceptance scheduled for Jan. 1, 2016. The estimated capital costs for these three projects are $58.2m.
Powder River Basin coal rejected as compliance option
The Big Rivers filing shows that Coleman Units 1 and 2 each have 160 MW (gross) of capacity, while Unit 3 has 165 MW (gross). Wilson Unit 1 has 440 MW (gross) of capacity. Green Unit 1 has 252 MW (gross) of capacity, while Green Unit 2 has 244 MW (gross). Station Two’s Unit 1 has 172 MW (gross) and Unit 2 has 165 MW (gross). Reid Unit 1 currently has 72 MW (gross). The primary fuel for all of these units of Illinois Basin bituminous coal.
As part of Sargent & Lundy’s study, fuel switching to fire Powder River Basin (PRB) fuel at these units was initially considered as a viable approach to achieving SO2 and NOx compliance with CSAPR. However, it was quickly eliminated due to the extremely high net present value (NPV).
Generally speaking, there are two main cost components to convert bituminous units to PRB units. One cost component is to address the fire and explosion issues that are associated with handling this dusty coal. The second cost component is to address performance issues due to this low-Btu coal, sub-bituminous coal.
Based on the large variation in equipment upgrades and modifications that may be required, capital costs for switching to PRB can vary significantly. Reviewing costs from past PRB conversions, it was estimated that a PRB conversion at HMP&L, Wilson, and Green would cost between $70/kW and $100/kW, depending on the extent of work that is needed.
To estimate the operation and maintenance (O&M) impact of fuel switching, Sargent & Lundy was given $2.00/MMBtu as the cost of Big Rivers’ bituminous fuels. PRB fuels are likely to cost closer to $3.00/MMBtu because of the higher transportation costs associated with shipping coal from Wyoming. For HMP&L, Wilson, and Green Unit 2, fuel switching results in a NPV that is about $700m higher than the total NPV for the compliance plan. Therefore, fuel switching as a means for complying with CSAPR was not recommended.