Kentucky Utilities approved by state PSC for new coal-related environmental projects

The Kentucky Public Service Commission on Aug. 8 approved several new environmental control projects for Kentucky Utilities, which was the same day that it approved three new environmental projects for Louisville Gas and Electric, which like Kentucky Utilities is a subsidiary of PPL Corp. (NYSE: PPL).

On Jan. 29, Kentucky Utilities (KU) sought four Certificates of Public Convenience and Necessity (CPCN), approval of an amended environmental compliance plan, and a declaratory ruling that CPCNs are not needed to close three surface impoundments at generating stations previously closed. One CPCN is for Project 36, the construction of Phase II of the landfill at the coal-fired E.W. Brown Generating Station; one CPCN each is for Projects 40, 41 and 42, consisting of surface-impoundment-related construction and new process-water systems at the coal-fired Ghent Generating Station, the Trimble County Generating Station and at Brown, respectively.

According to KU, the surface-impoundment-related construction, consisting of closing five surface impoundments at Ghent, two at Trimble County and one at Brown, is necessary to comply with the U.S. Environmental Protection Agency’s Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), while the new process-water systems are required to continue operating those generating stations without the surface impoundments.

KU also requested a declaratory ruling that CPCNs are not required for the proposed closure of surface impoundments, or coal ash ponds, at the Green River Generating Station, Pineville Generating Station and Tyrone Generating Station. In the alternative, KU requested a CPCN for the closures at Green River, Pineville and Tyrone if the commission finds that those ash pond closures require a CPCN.

KU’s request for approval of its amended environmental compliance plan (2016 Plan) was for the purpose of recovering the costs of the proposed new and amended projects through the environmental surcharge mechanism.

KU’s application was initially deemed to be deficient, but the filing deficiency was cured, and the application was accepted for filing on Feb. 9.

The total capital cost of the eight proposed projects in the 2016 plan is estimated to be approximately $677.7 million. 

  • Project 36 involves constructing Phase II of the landfill at Brown, which is currently necessary to remain in compliance with the Special Waste Landfill Permit issued by the Kentucky Division of Waste Management (KDWM). The Special Waste Landfill Permit set forth a ten-foot height limit for each successive phase of lateral expansion such that the volume of CCR disposed in each phase is no more than ten feet higher than adjoining phase(s). Accordingly, Phase I of the Brown Landfill is designed to be ten feet high, with a CCR capacity of approximately 540,000 cubic yards. KU anticipates that, based on historical production at the Brown Landfill, Phase I will be at capacity as early as the second quarter of 2018, or at the latest in 2019. Phase II construction would entail regrading of the clay subgrade to prepare the site for installation of the liner and leachate collection system necessary for ongoing CCR disposal. KU states construction will commence in 2017 and is expected to be completed within one year. The estimated total capital cost to construct Phase II of the Brown Landfill is $11 .9 million. In its economic analysis of the Brown Landfill Phase II, KU evaluated the proposal against two other alternatives: transporting the Brown CCR to beneficial-use markets and transporting the CCR to the nearest municipal landfill. KU ruled out transporting the CCR to beneficial-use markets because Brown’s fly ash, bottom ash, and gypsum are currently not marketable due to unacceptable product specification and the high transportation costs stemming from lack of access to barge transportation at Brown. Regarding the alternative of transporting the CCR to the nearest landfill, KU’s economic analysis indicated that the proposed Phase II construction is the lower-cost alternative by $4.2-$4.5 million, on a present-value revenue requirement (PVRR) basis.
  • Project 37 consists of improvements to the wet flue gas desulfurization (WFGD) systems at Ghent Unit 2 to further reduce SO2 emissions in order to comply with the federal Mercury and Air Toxics Standards (MATS). The current WFGD system on Ghent Unit 2 removes slightly over 90% of SO2 emissions from the flue gas. The MATS Rule requires a 97% emissions removal rate. KU proposed improvements to the WFGD system on Ghent Unit 2 that cumulatively will improve the sulfur dioxide removal efficiency by increasing the effective liquid-to-gas contact. KU plans to install new technology spray nozzles that will increase the liquid-to-gas contact surface area through a finer and more concentrated spray droplet, as well as install “wall rings” which are attachments to the WFGD’s module walls near the spray nozzle and spray cone areas. The wall rings reduce “leakage” of flue gas up the module walls caused by the pressure drop of the nozzle sprays by forcing the flue gas flow through the nozzle spray cone areas. The total estimated capital cost for Project 37 is approximately $7 million. In its economic analysis of Project 37, KU evaluated the proposal against three other alternatives: status quo (comply using dispatch modifications only); use reagent to improve SO2 removal rate; and burn lower-sulfur coal. The dispatch modification approach includes the costs of modifying Ghent Unit 2’s dispatch so that it does not produce more than 20% of the station’s total generation, which would effectively reduce Ghent Unit 2’s capacity by approximately 110 MW when the other three Ghent units are operating at full load. The reagent alternative involves the injection of a reagent into Ghent Unit 2’s scrubber liquor. The estimated capital cost of this alternative is approximately $1.4 million. The estimated annual cost of the reagent is approximately $1.3 million and is assumed to escalate at an annual rate of 2%. The use of lower-sulfur coal alternative would increase Ghent Unit 2’s annual expense by approximately $11 million. KU noted that the additional capital costs associated with the WFGD modification project were more than offset by the higher O&M or fuel costs associated with the other two alternatives. One analysis indicated that Project 37 is the lower cost alternative between $37 million and $68 million, on a PVRR basis, across all three gas price scenarios (low, mid, and high).
  • Project 38 consists of supplemental injection systems on all four Ghent units to further reduce mercury emissions from the station in order to comply with the National Ambient Air Quality Standards for 2.5 micron particulate matter and the MATS Rule for mercury emissions. Project 38 involves a supplemental alternative to using PAC injection for capturing mercury in the baghouse of each of the four Ghent units. Mercury re-emission can occur from the PAC injection process that could result in excessive mercury emissions. To reduce the occurrence of mercury re-emission, KU plans to install equipment to apply coal and flue gas desulfurization (FGD) additives to capture mercury in the station’s gypsum. Project 38 would require a $10 million investment in equipment to store and inject the additives, but this cost would be lower than the cost of PAC. KU also asserted that the addition of a mercury-control injection system would make the Ghent CCR more marketable as beneficial-use products because it would enable KU to have greater control over where the mercury is captured.
  • Project 39 involves the closure of ash ponds at the retired Green River, Pineville, and Tyrone stations. In particular, three ash ponds will be closed at Green River, one at Pineville, and one at Tyrone. Although these ash ponds are not subject to the CCR Rule because the coal-fired units at Green River, Pineville, and Tyrone were retired as of the effective date of the CCR Rule, KU asserts that closing these ash ponds at this time is a prudent decision. KU stated that by closing these ash ponds at the same time as the ash ponds at Ghent, Trimble County, and Brown (Projects 40, 41, and 42), it could take advantage of economies of scale that could result in potential cost savings. The projected total capital cost for the closure of the Green River ash ponds is approximately $56.8 million. The projected total capital cost for the closure of the Pineville ash pond is approximately $8 million. The projected total capital cost for the closure of the Tyrone ash pond is approximately $13.1 million.
  • Projects 40, 41 and 42 involve the closure of ash ponds and the construction of process-water systems at Ghent, Trimble County and Brown, respectively. KU contended that these projects are necessary for compliance with the CCR Rule while supporting continued operation of the generating units at those stations. Specifically, KU proposed to close five ash ponds at Ghent, two ash ponds at Trimble County, and one ash pond at Brown, all by 2023. The estimated total capital cost of Project 40 is $364.2 million. In its economic analysis of Project 40, KU evaluated the costs of continuing to operate the Ghent units through 2021 against the cost of retiring the Ghent units in 2019 and purchasing replacement capacity. KU’s economic analysis indicated that the PVRR associated with operating the Ghent units with the proposed capital projects contained in Project 40 through 2021 is $278 million to $574 million lower than compared to the retire/replace alternative. The estimated total capital cost of Project 41 is $105.3 million. In its economic analysis, KU evaluated the proposed Project 41 against the following two alternatives: retire the Trimble County units in 2019 and purchase replacement capacity; and convert the Trimble County units to operate on natural gas. KU’s economic analysis indicated that the PVRR of Project 41 is $495 million to $2.9 billion favorable as compared to retiring the Trimble County units and replacing the capacity and is $478 million to $4 billion favorable as compared to the conversion alternative. The estimated total capital cost of Project 42 is $101.3 million. In its economic analysis, KU evaluated the following two alternatives to Project 42: retire the Brown coal units in 2019 and purchase replacement capacity either through a purchase power agreement for two 201-MW simple-cycle combustion turbine units (called the “402-MW SCCT”) or a purchase power agreement for one 368-MW natural gas combined cycle unit and one 201-MW simple cycle combustion turbine unit (“569-MW NGCC/SCCT”); and convert the Brown coal units to operate on natural gas. KU’s economic analysis indicated that compared to the retire/replace and conversion alternatives, Project 42 was $153 million favorable to $5 million unfavorable on a PVRR basis.
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.