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HomeMy WebLinkAboutNCS000546_Allen NPDES Application Update_20160831DUKE ENERGY August 31, 2016 Mr. Jeffrey Poupart Water Permitting Section Chief Division of Water Resources Department of Environmental Quality State of North Carolina 1617 Mail Service Center Raleigh, NC 27699-1617 Re: NPDES Wastewater Permit Application Update Duke Energy Carolinas, LLC. Allen Steam Station Permit #: NC0004979 Gaston County Dear Mr. Poupart, Harry K. Sidens Senior Vice President Environmental, Health & Safety 526 S. Church Street Mail Code: EC3XP Charlotte, NC 28202 (704) 382-4303 Duke Energy Carolinas, LLC (Duke) is submitting herewith supplemental information in support of the NPDES renewal application submitted in October 2014 for the subject facility. This update is in addition to the previous update submitted in March 2016. Please include this supplemental information and the information in the previous submittal in your review to renew the NPDES permit for Allen Steam Station (Allen). This submittal is intended to provide an update of modifications that will be necessary to comply with recently enacted laws and regulations including the Federal Steam Electric Effluent Guidelines (ELG), Federal Coal Combustion Residual (CCR) rule, the North Carolina Coal ash Management Act of 2014 and HB 630 of 2016. Specific permit requests from Duke Energy are identified in bold throughout this submittal. With numerous federal and state requirements to coordinate and implement in a short time for the site, planning and sequencing of work are paramount and yet dynamic. As such, final scope and sequence for all work is not complete at this time. Where scope is still not finalized, Duke has provided a range of options that are being evaluated and has also provided various alternate scenarios in an attempt to limit the number of subsequent submittals. Duke believes that the information provided in this submittal is of sufficient detail to allow for review and issuance of the renewed NPDES permit for Allen. This is consistent with the guidance received from DEQ staff in a meeting on November 20, 2015 and follow up correspondence dated January 11, 2016 and January 28, 2016. Allen Steam Station NPDES application update NC0004979 Gaston County Page 2 of 35 1. Duke Energy requests a new outfall associated with the planned retention basin system (RBS). North Carolina's Coal Ash Management Act and the Federal CCR rule will prohibit continued wastewater flows to the existing ash basin at Allen. A project is underway to convert ash handling of to a100% dry handling and disposal system. All other wastewater inputs to the active ash basin (AAB) must be redirected and handled in another manner. By April 2018, Duke intends to construct a RBS to handle all flows currently directed to the active ash basin. The RBS will accommodate flows from the yard drainage sump, the coal yard sump, the flue gas desulfurization (FGD) stormwater basin and the FGD wastewater treatment system (WWTS) effluent discharge. The requested new RBS outfall and the active ash basing outfall 002 may need to both be operational for a period of time. Details of the inputs to the RBS are given in Attachment 1. A drawing showing the approximate location of the RBS is provided as Attachment 2 The requested outfall from the newly constructed retention basin will discharge into the Catawba River. An aerial photo with an approximate location of the outfall (35.198434, - 81.010253) for the new retention basin can be found as Attachment 3. 2. Landfill leachate is currently sent to the AAB. Landfill leachate flows will be directed to the RBS via the coal yard sump as described in item # 1 upon completion of that system. Duke requests that the landfill leachate be considered as a new input to the coal yard sump overflow(Outfall 002A). 3. Duke requests a new internal outfall for the planned retention basin system. FGD purge water is routed to a WWTS consisting of a physical -chemical process designed to precipitate heavy metals and remove suspended solids. The clarified product water is routed to a series of bioreactors designed for selenium and nitrate removal. The bioreactor product water will be routed through a polishing filtration system (ultrafiltration with the addition of coagulant, flocculent, or antiscalant to ensure performance) then discharged to the retention basin via the relocated internal outfall. The new internal outfall for FGD wastewater and the existing internal outfall 005 may need to both be operational for a period of time. 4. Duke requests that the emergency spillway of the retired ash basin be included as a wastewater outfall. If 4(a) and 4(c) above are granted for 5-10, the emergency spillway would need to follow suit in becoming a permitted wastewater outfall. The emergency spillway is located in the northeastern corner of the stormwater retention basin that spans the southern portion of the landfill (please see Attachment 5). The approximate coordinates of the spillway are (35.181850,-81.006706). The emergency spillway was Allen Steam Station NPDES application update NC0004979 Gaston County Page 3 of 35 designed for a flood greater than a 100-year event. Duke requests that sampling of this spillway be waived due to the small likelihood of an overflow and more importantly due to unsafe conditions associated with sampling during an overflow event. 5. Duke requests specific authorization within the reissued permit that, upon ceasing or reducing flows to the active ash basin, decanting and dewatering of the basin through existing wastewater outfall 002 can occur. Specific authorization for decanting and dewatering is a condition currently in the NPDES permits at Sutton and Marshall. Duke requests specific authorization that the ash basin may be decanted and dewatered and that permit limits associated with these activities be included in the permit. A temporary WWTS may be needed to meet future permit limits. Additional treatment for the dewatering process may be completed via chemical and/or physical processes prior to discharge to outfall 002. This treatment system may require the addition of a coagulant and/or flocculent to enhance solids removal. A characterization of the ash basin interstitial water was previously provided in an addendum to Allen's NPDES wastewater permit application dated 18 May 2015. 6. Modifications associated with coal pile runoff. A holding basin will be constructed to receive coal yard runoff and backwash water from preheater washes. The holding basin will have a chemical feed system for adjusting pH and polymer addition to enhance settling. Once treatment is sufficient, the holding basin contents will be transferred to the RBS. See attachment 2 for approximate location of coal pile basin. 7. Area of wetness (AOW) disposition. Duke has previously identified a number of AOWs within the property, all of which have been included in Allen's renewal application or a subsequent update. Duke requests that S-9 be removed from the permit application due to its pipe being grouted, allowing no more seepage to exit the pipe. Duke also requests that S-1 be removed from the permit due to it being a natural stream feature and being free from wastewater pollutants. Duke requests that the remainder of the disclosed AOWs be permitted in the following fashion: a) As determined during the DEQ site visit on August 16, 2016, designate the conveyances associated with S-2, S-3, S-4, S-8, S-813, and S-10 as effluent channels with outfalls to the Catawba River and appropriate limits for outfalls to those points; Allen Steam Station NPDES application update NC0004979 Gaston County Page 4 of 35 b) Due to accessibility and sampling challenges and because the seepage is from the same source (active ash basin), S-4 should be considered representative of S- 5, S-6, and S-7. Therefore, Duke is requesting that there be no sampling requirements for S-5, S-6, and S-7. c) The seepage from 5-10 enters a stormwater retention basin south of the landfill (please see Attachment 5) and then eventually enters the Catawba River through stormwater outfall SW015 (an outfall in permit NCS000546). Duke requests that stormwater outfall SW015 be removed from NCS000546 and be permitted as a wastewater outfall that includes inputs from 5-10 and stormwater from the drainage area of SW015. 8. Steam Electric Effluent Guidelines Alternate Schedule Justification. Duke requests an alternate applicability date for the Steam Electric Effluent Guidelines in accordance with the request found in Attachment 4. Treated bottom ash transport water and FGD wastewater are currently discharged from Allen. Under normal plant operations, fly ash is collected dry and either disposed in a permitted on -site landfill or transported offsite for beneficial reuse. The new Effluent Guidelines Rule (ELG Rule) (80 Fed. Reg. 67,838 (Nov. 3, 2015)) sets a range of possible applicability dates for compliance with the new best available technology (BAT) limits for bottom ash transport water (zero discharge) and FGD wastewater (numeric limits for selenium, arsenic, mercury, and nitrate/nitrite), as well for fly ash transport water (zero discharge). The regulation provides that all permits issued after the effective date of the rule (January 4, 2016) should contain applicability dates for compliance with the BAT limits, and that those dates should be "as soon as possible" but not sooner than November 1, 2018 and not later than December 31, 2023. Per the New Source Review (NSR) Consent Decree dated Oct. 20, 2015, Units 1, 2 and 3 at Allen are required to retire on or before December 31, 2024. Due to the retirement dates for these units, Duke is evaluating early retirement options to avoid stranded costs. Duke, therefore, requests the following implementation process to establish the ELG applicability date for Allen. — On or before December 31, 2017, Duke will make a determination on early retirement. Based on this decision, Duke requests the following ELG applicability dates: o If the decision is to retire the units on or before December 31, 2023, Duke requests an ELG applicability date of December 31, 2023 for both FGD wastewater and bottom ash transport water to avoid stranded costs. Allen Steam Station NPDES application update NC0004979 Gaston County Page 5 of 35 o If the decision is not to retire the units on or before December 31, 2023, Duke requests an ELG applicability date of February 28, 2021 for both bottom ash transport water and FGD wastewater. Duke is not requesting an applicability date for the zero discharge of fly ash transport water beyond November 1, 2018. 9. CWA Section 316(b) alternate schedule. In the renewal application Duke submitted an alternate schedule for compliance with Section 316(b) of the Clean Water Act. The alternated schedule is submitted again here for convenience and can be found in Attachment 6. We appreciate your attention to these requests and look forward to finalizing the NPDES permit for Allen Steam Station in the near future. Should you have any questions regarding this letter or require additional information, please contact Mr. Ross Hartfield at 980-373-6583 or at ross.hartfield@duke-energy.com. "I certify, under penalty of law, that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fines and imprisonment for knowing violations. " Sincerely, Harry Sideris SVP - Environmental, Health & Safety Enclosures NCDEQ cc: Mike Randall Duke Energy cc: Brent Duett, Ross Hartfield, Scott Harris, Randy Gantt, Mary Parlemon, Jeremy Pruett, Richard Baker, Shannon Langley, Brandon Dellis Attachment 1 Narrative description of inputs to retention basin system and 2018 flow schematic August 31, 2016 NPDES application update Allen Steam Station NC0004979 Inputs to the New Retention Basin System The RBS will accommodate flows from the yard drainage sump, the coal yard sump, the FGD tormwater basin and the FGD WWTS effluent discharge. Additional treatment of the wastewater in the RBS may be completed via chemical and/or physical processes prior to discharge to the new requested outfall. This treatment system may require the addition of a coagulant or flocculent to enhance solids removal or may require pH adjustment.The following gives preliminary details of the current and planned design and operation of wastewater treatment related to the planned RBS. Variation in treatment and operation are expected. a) Stormwater Run-off - Stormwater run-off will enter the RBS from drainage flows collected at the yard drainage sump, the coal yard sump, and the FGD stormwater basin. The powerhouse sump and the limestone storm water sump discharges its stormwater run-off into the yard drainage sump. The landfill leachate sump will discharge its stormwater run-off into the coal yard sump. b) Sanitary Wastes - Sanitary waste at Allen is treated in a septic tank, and the effluent from the septic tank is sent to the the coal yard sump. Approximately 115 people are responsible for the load on this system. An average flow of 4850 GPD is treated by the system. c) Ash Sluicing - Allen employs a dry fly ash handling system. Ash collected in the electrostatic precipitators is transported by compressed air to two silos where ash is transferred to trucks for ultimate disposal in the on -site landfill. Wet sluicing of fly ash is still utilized during times of dry system upset. Bottom ash from the boilers will be sluiced to the submerged flight conveyors, dewatered, and the resulting ash solids will be disposed of in the on -site landfill. The ash sluicing water will be recirculated in a closed loop system with make-up provided from service water for evaporation and water loss from moisture in the dewatered bottom ash. Draining of the system will be necessary on occasion; the water from this draining process will be sent to the FGD WWTS. Allen presently has additional air pollution control systems installed on three units. Use of these systems entails the use of low concentrations of sulfur compounds. These systems aid in the collection of the ash in the electrostatic precipitators. d) Recirculating Water System (RCW) - Allen has 2 RCW systems: a chiller system and a pump cooling water system. Both systems use the biocide Nalco H-550 or similar products. In addition, the corrosion inhibitor Nalco CS-4710 or similar products are used. Generally, these systems are closed loop in nature but may need to be drained occasionally. All such water would enter the floor drains and then be discharged to the RBS. e) Heat Exchanger Cleaning - Periodically, it may be necessary to clean the small heat exchangers with polyacrylamide, polyacrylate, sodium laurylsulfate, tri-sodium phosphate, or similar compounds. All wastewater would be routed to the RBS. f) Condensate Polishers - Allen utilizes condensate polishers which divert a portion of the normal condensate (closed system) flow through one of two cells per unit. The polishers provide filtration as well as ion exchange functions to remove or substantially reduce dissolved solids and suspended matter present in the condensate stream. The polishers require precoating with a combination of anion and cation resin. To facilitate precoating, 125-150 ml of a solution of polyacrylic acid (25%) is added to the precoat slurry. Upon resin exhaustion, the precoat is removed from the filters by water/air blasting and would be flushed to the RBS via sumps. Condensate water is used to remove the exhausted precoat at the rate of 1558 gal/precoat for units 1 & 2 and 2090 gal/precoat for units 3, 4, & 5. A total average waste flow of approximately 980 GPD to the RBS is expected. g) Condenser Leakage Testing - Approximately I lb. of a disodium fluorescing dye is added to 280,000 gals of demineralized water to test the condensers for leakage. All wastewater from the testing would be routed to the RBS. Periodically, sulfur hexafluoride is injected into the condenser tubes to locate condenser tube leaks. Sulfur hexafluoride is a chemically inert, nonflammable, nontoxic gas with an extremely low water solubility. It is estimated that 150 grams of sulfur hexafluoride would be used during the leak detection process. Most of the sulfur hexafluoride would be volatilized during the process. h) FGD Stormwater Sump - Stormwater collected at the FGD site including the dry ash handling facility, gypsum pile, WWTS area (not process water), stack, absorbers, switchgear building, dewatering building, reagent prep building, and the control room area is routed to a large stormwater collection basin and would then be pumped to the RBS. i) Landfill Leachate Collection Discharge - Industrial Solid Waste landfill (Permit No. 36-12) is permitted to accept coal combustion byproducts (fly ash, bottom ash, gypsum, WWTS filter press sludge cake) consists of a double liner with leachate collection system. Collected leachate will be pumped to the coal yard sump prior to being pumped to the RBS. j) Boiler Room Sumps (Units 1-4) - The water which flows to the boiler room sumps originates from such sources as floor wash water, boiler blowdown, water treatment waste, condensates, equipment cooling water, sealing water, and miscellaneous leakage. The effluent from the units 1 through 4 boiler room sumps is flushed to the yard drain sump. k) Turbine Room Sumps - The turbine room sumps accommodate flows from floor washing, leakage, and occasional condenser water box drainage. Effluent from Units I through 5 turbine room sumps is flushed to the yard drain sump. 1) Limestone Unloading/Storage Area Sump - The limestone sump collects stormwater from the limestone unloading and storage area and sends it to the yard drain sump via powerhouse sump discharge line. m) Powerhouse Sump (Unit 5) - The wastes that enter the floor drains at Allen accumulate in the boiler room sumps and turbine room sumps. The water that flows to the boiler room sumps originates from such sources as floor wash water, boiler blowdown, water treatment waste, condensates, equipment cooling water, sealing water, and miscellaneous leakage. Effluent from the unit 5 boiler room sump is sent to the yard drain sump via the powerhouse sump. The powerhouse sump also receives stormwater from various drains located on the northern end of the powerhouse. n) Water Treatment System Waste- The water treatment system waste consists of sedimentation, filter backwash, reverse osmosis concentrate, demineralizer regeneration wastes, and boiler blowdown. The make- up water treatment system consists of a clarifier, two pressure filters, two activated carbon filters, pre -reverse osmosis filters, a reverse osmosis unit, and one set of demineralizers. Make-up water is used in the boilers and closed cooling systems. Details of the water treatment system are given below. i) Clarifier: The clarifier has an average production of 0.252 MGD. Caustic or ferric sulfate/ferric chloride are used to effect precipitation and thus remove suspended solids from the raw river water. Desludging of the clarifier takes place approximately 8% of the unit run-time with an average volume of 2300 GPD expected to flow to the RBS. ii) Pressure Filters: There are two pressure filters which follow the clarifier in the water treatment process. These filters are backwashed once per week with a waste flow of 11,000 gallons per backwash. Each pressure vessel will contain 84 ft3 of anthracite, 50 ft3 of quartz, 25 ft3 of garnet, and 41 ft3 of garnet/quartz support media. Each vessel will use product water to backwash at a rate of 750 gpm. On average, both vessels are backwashed once per week. The contents of the pressure filters will be c hanged out as internal maintenance requires, and the used filter medium will be sluiced to the RBS. iii) Activated Carbon Filters: In addition to the pressure filters, there are two activated carbon filters. These filters are backwashed twice per month. Approximately 30,000 gallons of water are required to backwash each of these filters. The activated carbon filters consist of approximately 250 ft3 of granular activated carbon (coal). The spent filter medium is changed out yearly and will be sluiced to the RBS. iv) Reverse Osmosis Unit: A reverse osmosis unit is used to decrease the conductivity in the filtered water, thereby increasing the efficiency of the demineralizers and reducing the amount of chemical needed for demineralizer regeneration. During operation the unit has a continual blowdown of 60 gal/min, which is currently discharged to the ash basin. The reverse osmosis unit is cleaned on a quarterly basis with the waste going to the yard drains. During a cleaning, approximately 30 lbs of a sulfamic acid cleaner along with 5 gallons of biocide, 2 liters of sodium hydroxide, and 0.5 gallons of sodium lauryl sulfate is used. v) Demineralizer: The demineralizer consists of two mixed -bed cells. Only one of these cells is operated at any one time. The cell which is in operation is regenerated approximately once every 7-14 days of operation. A regeneration requires 42 gallons of sulfuric acid (78-80%) and 150 gallons of 50% sodium hydroxide. An average dilute waste chemical and rinse flow of 20,000 gal is realized. The dilute acid and caustic are discharged to the floor drains simultaneously through the same header for neutralization purposes. All regeneration wastes are currently flushed to the ash basin. The demineralizer resin is changed out approximately once every 10 years, and the spent resin is currently sluiced to the ash basin. Approximately 1 milliliter of the surfactant Triton CF-54 or similar product is added to the new resin to improve separation. vi) Boiler Blowdown: Each of the five boilers at Allen blowdown at an average rate of about 500 lbs. of steam per hour. The blowdown is allowed to flash in a blowdown tank. Most of the blowdown is vented to the atmosphere with a minimal amount of condensate discharged to the boiler room sump. The average condensate flow to this sump is 0.004 MGD. Hydrazine is maintained at a concentration of 25 ppb in the condensate system for deoxygenation. A minute amount of hydrazine (<10 ppb) may be present in the condensate flow to the boiler room sump. o) Preheater Washes - Preheaters are backwashed with raw water on an as needed basis to remove ash and corrosion products. There are 12 preheaters at Allen that would require approximately 100,000 gallons of backwash water each. The backwash water would be routed to the holding basin through the yard drain sump. p) Laboratory Wastes - The plant chemistry and the FGD chemistry laboratories on -site perform a variety of water analyses and routine sample collections. Therefore several chemicals are used in the lab in small quantities for sample preservation, bottle rinsing, equipment calibration, conductivity analyses, etc. The wastes are flushed down the sink and discharged into the yard drain sump. Some of the laboratory chemicals are as follows: ammonia molybdate, acetic acid, ferric sulfate, hydrochloric acid, monoethylamine, nitric acid and potassium hydroxide. q) Selective Non -Catalytic Reduction (SNCR) - As part of the compliance with the North Carolina Clean Air Initiative, Allen has installed urea -based "trim" SNCR systems on all five units. The trim SNCR systems are expected to reduce NOx emissions by approximately 30%. SNCR systems operate by injecting urea into the upper section of the boiler where a chemical reaction occurs to reduce the NOx to water and nitrogen. Some residual ammonia will be collected on the fly ash in the electrostatic precipitators, and a small amount is expected be carried to the RBS. However, the operation of the SNCR system is not expected to require additional treatment capabilities to ensure compliance with NPDES permit limits. r) Flue Gas Desulfurization - A wet FGD system has been installed at Allen for the reduction of SO2 from the stack gas. The following provides a description of the FGD system at Allen. In a wet scrubber system, the SO2 component of the flue gas produced from the coal combustion process is removed by reaction with limestone -water slurry. The particular system used at Allen collects the flue gas after it passes through the electrostatic precipitator and routes the gas into the absorber tank. As the gas rises through the tank to the outlet at the top, the gas passes through a spray header. A slurry of water and limestone droplets is continually sprayed through this header into the stream of flue gas. The SO2 in the flue gas reacts with the calcium in the limestone and produces S03. The SO3 slurry falls to the bottom of the tank where a stream of air is injected to oxidize the slurry to form gypsum (CaSO4 * 2H2O). The gypsum slurry is drawn off the absorber tank and subsequently pumped to a vacuum belt filter. Part of the process water from the FGD system is blown down in order to maintain the FGD water chemistry within the FGD system specifications. This water is treated in a WWTS that will discharge to the retention basin via the displaced internal outfall 005. The FGD system has a material handling system that supplies limestone to the scrubber and a gypsum storage area for the gypsum removed from the process. The limestone comes onto the site by rail and is then transferred to the FGD site via a covered conveyor. Runoff from the storage area is routed to the FGD storm water basin. The gypsum is routed from the FGD tank to a dewatering belt and then to a covered conveyor belt that will carry it to a storage pile. The runoff from this area is also routed to the FGD storm water basin. t) Hazardous and Toxic Substances - At Allen, the potential for toxic and hazardous substances being discharged is very low. The hazardous substances that may be in the discharge are acetaldehyde, asbestos, butyl acetate, cyclohexane, diuron, epichlorohydrin, formaldehyde, monoethyl amine, propylene oxide, pyrethrins, vinyl acetate, and xylene. During the course of the year products such as commercial cleaners and laboratory reagents may be purchased which contain low levels of a substance found in Table 2c-3 . It is not anticipated that these products will impact the retention basin's capacity to comply with existing toxicity limits, since their concentrations are extremely low. Catawba River t-onaenser Cooling Water Plant Allen 2018 Water Schematic Outfall 001 649 MGD South Fork River Sanitary Waste Bottom Ash -------------I S stem I I Water Treatment Atm Boiler Boiler Room Sumps FG D Outfall 002A _ Intermittent Catawba River Landfill Coal Yard 4 Coal Handling Leachate Sump Sumps Stormwater Holding basin Internal Outfall005 I-------- — — — J ---4 FGD WWTS .5 M D I I Stormwater I I I Ash Silo �_(t:FG water I Ash BasinOUtfall 002 Sump m I 1.0 MGD Catawba River I I Stormwater I Seeps Turbine Room I Sumps I Yard Drainage New Sump Retention Basin �—� 00X c b R Misc Equip Cooling & Seals ataw a aver 3.3 MGD Outfall 003 4.5 MGD South Fork River Powerhouse Outfall 002B _______ Sump——————————--———————-———————————————————————— —----— / (Intermittent) Catawba River Limestone Stormwater Sum Intake Screen Outfall 004 Backwash 6.5 MGD Catawba River Debris Filter Backwash *Flows are estimates. Catawba River Attachment 2 Drawing of approximate location of the planned retention basin system, holding basin, and submerged flight conveyor August 31, 2016 NPDES application update Allen Steam Station NC0004979 T 2 T 3 T 4 T 5 T 6 T 7 T 9 mm� - �_C �—D �—E 50UTHPOINT RE) A �07/06/16� MCC DWK ISSUED FOR REVIEW no. I date I by I ckd I description Z:\Clients\ENR\DukeEnr\WtrRedirProg\88679_Allen\Design\Civil\Dwgs\Site Preparation\Water Redirection\ALN00-CV-C-SI.PL-101.dgn souTHPoINT PD no. date by I ckd 4 description LIME REACTION TANK HYDRATED LIME SILO ` � \ 0 G BASIN HB CHEMICAL FEED BUILDING ` VACUUM TRUCK PAD \ PRELIMINARY - NOT FOR CONSTRUCTION BURNS N&MMONNELL 9400 WARD PARKWAY KANSAS CITY, MO 64114 816-333-9400 FIRM LICENSE NO. C-1435 0 200' 400' SCALE IN FEET TITLE WATER REDIRECTION PROGRAM OVERALL GENERAL ARRANGEMENT PLAN FOR ALLEN STEAM STATION UNITS 1-5 DUKE ENERGY® GASTON COUNTY, NC DWG TYPE CVL D TR: MCC JOB NO: 88679 CHKD: DWK DATE: 07/06/2016 ENGR: DWK FILENAME: ALN00-CV-C-SI.PL-101.dgn APPD: DWG SIZE DRAWING NO. REVISION ARCH Ell ALN00-CV-C-SLPL-101 A Tim - C__� D--� F--� 5 i 6 1 7 1 9 1 10 7/8/2016 mccochran 2:59:02 PM I Attachment 3 Aerial imagery of approximate location of new outfall for planned retention basin system August 31, 2016 NPDES application update Allen Steam Station NC0004979 L Goo steart,_ 2016 Google • f M1 A AAporpximate Location of New RBS Outfall � N � z000 ft � Attachment 4 Steam Electric Effluent Guidelines Alternate Schedule Justification August 31, 2016 NPDES application update Allen Steam Station NC0004979 Allen Steam Station: Effluent Guidelines Rule Justification for Applicability Dates A. Introduction Duke Energy (Duke) is working diligently to develop and refine an optimized schedule for the installation and upgrades to wastewater treatment systems to comply with the Steam Electric Power Generating Effluent Limitation Guidelines (ELG) at seven coal-fired stations in North Carolina. Duke submits the following information as a justification for appropriate applicability dates for compliance with the new Effluent Guidelines Rule (ELG Rule) (80 Fed. Reg. 67,838 (Nov. 3, 2015)) at Allen Steam Station (Allen), located in Belmont, North Carolina. Allen consists of five coal fired generating units with a total generating capacity of 1,127 MW. Treated bottom ash transport water (BATW), and FGD wastewater is currently discharged from the station. Under normal plant operations, fly ash is collected dry and either disposed in a permitted on - site landfill or transported offsite for beneficial reuse. If the dry fly ash collection system is not operating, the fly ash is sluiced to the ash basin in which the transport water is treated in the ash basin and subsequently discharged through outfall 002. Bottom ash from the boilers is sluiced with transport water to the ash pond. The transport water is treated by the ash pond system and is discharged through outfall 002. The FGD blowdown flows to a physical / chemical treatment system followed by a biological treatment system and discharges through internal outfall 005 to the ash basin. The ELG Rule sets a range of possible applicability dates for compliance with the new best available technology (BAT) limits for bottom ash transport water (zero discharge) and FGD wastewater (numeric limits for selenium, arsenic, mercury, and nitrate/nitrite), as well for fly ash transport water (zero discharge). The regulation provides that all permits issued after the effective date of the rule (January 4, 2016) should contain applicability dates for compliance with the BAT limits, and that those dates should be "as soon as possible" but not sooner than November 1, 2018 and not later than December 31, 2023. For Allen, since the plant's final NPDES permit will be issued after January 4, 2016, but before November 1, 2018, EPA specifically instructs permit writers to "apply limitations based on the previously promulgated BPT limitations or the plant's other applicable permit limitations until at least November 1, 2018." 80 Fed. Reg. at 67,883, col. 1 (emphasis added). As the rule makes clear, however, BAT limits may apply — depending on the individual circumstances of the facilities subject to the rule — any time within the window of November 1, 2018 to December 31, 2023. In selecting an appropriate applicability date for each waste stream subject to the new BAT limits, the permitting authority is called upon to determine an "as soon as possible" date. The ELG Rule provides a very specific definition for "as soon as possible." The permit writer - when supplied with appropriate information by the permittee - must consider a range of factors that affect the timing of compliance. Those factors are as follows: (1) Time to expeditiously plan (including to raise capital), design, procure, and install equipment to comply with the requirements of this part. (2) Changes being made or planned at the plant in response to: (i) New source performance standards for greenhouse gases from new fossil fuel - fired electric generating units, under sections 111, 301, 302, and 307(d)(1)(C) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C); (ii) Emission guidelines for greenhouse gases from existing fossil fuel -fired electric generating units, under sections 111, 301, 302, and 307(d) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d); or (iii) Regulations that address the disposal of coal combustion residuals as solid waste, under sections 1006(b), 1008(a), 2002(a), 3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as amended by the Resource Conservation and Recovery Act of 1976, as amended by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. 6906(b), 6907(a), 6912(a), 6944, and 6945(a). (3) For FGD wastewater requirements only, an initial commissioning period for the treatment system to optimize the installed equipment. (4) Other factors as appropriate. 40 C.F.R. § 423.11(t). Per the New Source Review (NSR) Consent Decree dated Oct. 20, 2015, Units 1, 2 and 3 at Allen are required to retire on or before December 31, 2024. Due to the retirement dates for these units, Duke Energy is evaluating early retirement options to avoid stranded costs. We, therefore, would like to request the following implementation process to establish the ELG applicability date for Allen. - On or before December 31, 2017, Duke will make a determination on early retirement. Based on this decision, Duke would like to request the following ELG applicability dates:: o If the decision is to retire the units on or before December 31, 2023, Duke would like to request an ELG applicability date of December 31, 2023 for both FGD wastewater and bottom ash transport water to avoid stranded costs. o If the decision is not to retire the units on or before December 31, 2023, Duke would like to request an ELG applicability date of February 28, 2021 for both BATW and FGD wastewater. — Duke is not requesting an applicability date for the zero discharge of fly ash transport water beyond November 1, 2018. Duke developed the proposed process and its applicability date with grid reliability in mind. The dispatch of the units at Allen varies throughout the year with a unit(s) typically operating in the summer and winter months. Duke needs additional time to evaluate the early retirement option to ensure an early retirement will not disrupt grid reliability and electricity availability. EPA explicitly notes that the permitting authority should consider grid reliability in setting applicability dates: "EPA's decision is also designed to allow, more broadly, for the coordination of generating unit outages in order to maintain grid reliability and prevent any potential impacts on electricity availability, something that public commenters urged EPA to consider." 80 Fed. Reg. at 67,854, col. 2. See also Response to Comments, p. 8-138. This statement clearly applies to scheduling tie-ins with generating unit outages, but also implies the ELG applicability date should consider grid reliability associated with unit retirements. The following provides necessary information justifying the requested applicability dates provided above. B. Stranded Cost Avoidance due to Early Retirement Decision The steam electric industry is in the midst of major transitions driven by new environmental regulatory requirements in the air, waste, and water arenas. In the ELG Rule, EPA explicitly acknowledged the complications of planning and executing ELG retrofits while developing and executing compliance strategies under other rules. EPA made it clear that the range of applicability dates provided in the ELG Rule are supposed to be implemented in a manner that avoids stranded costs and promotes orderly decision making. For instance, EPA states: "From an environmental protection/coordination standpoint, with the increased use of flue gas desulfurization scrubbers and flue gas mercury controls in response to air pollution -related requirements, this rule makes sense from a holistic environmental protection perspective and from the perspective of coordinating across rules affecting the same sector. This final ELG controls the discharges associated with these particular waste streams." Response to Comments, p. 8-388. The ELG Rule clearly allows consideration of stranded cost avoidance in setting the ELG applicability date based on the need to account for any applicable obligations under the CPP. However, in statements in the Response to Comments, EPA indicates stranded costs apply to any rule, not just the CPP. EPA explains in the Response to Comments that it provided flexibility in applicability dates so that facilities could consider all new regulatory requirements and then have an adequate time to plan and implement accordingly, and thus avoid stranded costs: "EPA is sensitive to the need to provide sufficient time for steam electric power plants to understand, plan for, and implement any changes to their operation to meet their environmental responsibilities, and agrees with the commenter that transparency of requirements is important for minimizing "stranded investments." ...Furthermore, as described in the preamble, the final rule provides time for plant owners or operators to implement changes to plant operations in order to meet the final limitations and standards, as well as flexibility to permitting authorities in implementing the final rule. The Agency specifically considered the timing of requirements of other environmental regulations in establishing implementation requirements for the ELGs, in order to provide steam electric power plants time to consider and implement their strategy for compliance." Response to Comments, p. 8-388. Furthermore, EPA also states that the permitting authority may "account for time the facility needs to coordinate all the requirements of this rule, along with other regulatory requirements, to make the correct planning and financing decisions, and to implement the new requirements in an orderly and feasible way." Response to Comments, p. 8-129 (emphasis added). At Allen, we need to coordinate our ELG implementation strategy with the NSR Consent Decree, CPP, Coal Combustion Residual (CCR) and NC-CAMA rules. For both the CCR and CAMA rules, we are evaluating the current CCR ash pond to determine whether the ponds meet the locational restrictions of 40 C.F.R. § 257.60 - .64. The future of the ash pond under both of these rules will determine whether it is available or not to receive legacy wastewaters (i.e., those wastewaters generated before the applicability date for bottom ash transport water retrofits) and continue to receive non-BATW. In addition, as discussed below, the final determination of the extent of the ash pond, as well as the closure method could have significant ramifications for the siting of the RMDS, as well as the retirement date decision. For the CPP, the affected units at Allen will not know their individual obligations under the CPP until well after November 1, 2018. As promulgated by EPA, the CPP's emission guidelines do not apply directly to units. Instead, states are responsible for developing state plans setting forth requirements applicable to individual units that implement those emission guidelines. These state plans are subject to review and approval by EPA. If EPA determines that the state has not submitted an approvable plan, then EPA will promulgate a federal plan in its place. The timeline the CPP provides for developing and reviewing these state plans involves numerous steps. The initial deadline for state plan submittal was September 6, 2016. 40 C.F.R. § 60.5760(a). The vast majority of states were expected to seek and obtain a two-year extension for final state plan submittal until September 6, 2018. See id. § 60.5760(b). However, the Supreme Court issued a stay of the CPP on February 8, 2016. Thus, the timing of the requirements of the CPP is uncertain at this time, as we wait further decisions by the Supreme Court. C. ELG Applicability Justification under a Decision Not to Retire Early Bottom Ash Transport Water If the decision is not to retire units, significant portions of the bottom ash transport system at Allen will need to be replaced to comply with the no discharge limit of bottom ash transport water (BATW). The rule identified dry handling or closed -loop systems as the BAT technology basis for control of pollutants in bottom ash transport water. Specifically, a mechanical drag system (MDS) was identified as the technology basis for a dry handling system, where as a RMDS was identified as the technology basis for a closed -loop system. Duke is planning on installing a RMDS at Allen to handle bottom ash dry. The system will be designed to operate in a closed -loop mode to meet the zero discharge limits for BATW. Duke anticipates 52 months from the effective date of the permit will be needed to design, install and commission the RMDS as a zero discharge system based on the following preliminary timeline. It is important to note Duke will be installing RMDS at four stations in N. Carolina; therefore, additional time is needed compared to a single installation to account for managing multiple projects simultaneously. Remote Mechanical Drag System (RMDS) Activity Duration (Months) Design' 8 • Siting 3 • Engineering 5 Procurement 12 Potential Permitting Delays 6 Construction/Tie-in 13 Optimization & Operational Experience2 13 • Commissioning 2 • Start -Up 6 Total: 52 1) The design tasks has been initiated and Duke estimates an additional 6 months from the permit effective (assuming Nov. 1, 2016) will be needed to complete the design. 2) Even though is it estimated that commissioning and start-up can occur in 8 months, Duke anticipates needing a 13 month window to obtain the necessary operating time at full load and account for commissioning / optimizing occurring at multiple facilities simultaneously. Assuming a permit effective date of November 1, 2016, Duke estimates the system can be installed and operated to comply with the zero discharge limit of BATW on or before February 28, 2021. To design, procure, construct and optimize the RMDS at Allen to operate as a closed -loop system, the following steps must be taken: Design in�g Duke has initiated the design phase, but, due to the simultaneous implementation of programs, such as the CCR Rule and NC-CAMA across applicable sites in North Carolina, engineering and technology resources are limited. Duke, therefore, estimates the design and engineering process will take an additional 8 months from the permit effective date. Some of the activities within the water balance and siting task will occur concurrently; however the design cannot be completed until the siting task is completed. The permitting process, if necessary, will be initiated in the design and engineering phase, but it is assumed permit receipt / approval will be conducted concurrently with the design and procurement phase and will be completed prior to the construction phase. The following tasks will need to be completed. Water Balance The first step in the design process of the RMDS is to develop a detailed water balance of the current BATW. To operate the system as a zero discharge system, there is a balance between the inputs of water into the system and the outputs of water through evaporation and bottom ash removal. This is necessary to determine if any additional treatment of the BATW is needed to avoid increase in fines and concentration of other constituents that could affect equipment operability. In addition, several non-BATW waste streams are currently commingled and treated along with BATW. The flow of these waste streams will be rerouted from the BATW system to a new wastewater treatment system. This will require the streams to be characterized for both volumetric flow and constituent make-up in order to size and design an appropriate treatment system. It is important to note that not all waste streams discharge continuously or simultaneously. Some waste streams discharge intermittently based on activity occurrence, such air preheater and precipitator washes, while others may only discharge under certain rainfall events. In addition, many waste streams do not discharge if the unit is not running. With most coal-fired units operating in an infrequent mode, the opportunities to collect samples are limited and the operation schedule could affect the schedule of this task. Upon completion of the water balance, detailed engineering of the RMDS system and piping reroutes of non-BATW can commence. Siting The RMDS will need to be sited appropriately to avoid any historical or current CCP disposal sites and avoid construction areas that will be used to complete closure of the ash basins at Allen. In addition, Duke will attempt to site the system to avoid waters of the U.S. (WOTUS). However, based on the final siting of the system, WOTUS may not be avoided, and permits from the U.S. Army Corps of Engineers may be required. Permitting If WOTUS cannot be avoided, then permitting from the U.S. Army Corps of Engineers (USACE) will be needed. At this time, it is unknown whether a USACE permit will be required or the type of permit that may be required (nationwide permit (NPW) or individual permit). Duke, therefore, has included 12 months in the schedule to prepare and obtain any necessary USACE permits. Once the RMDS is commissioned, the permitted discharge flows will change drastically. The amount of water discharged could be reduced by as much as 85%. In addition, these flows typically were treated along with the BATW in the ash basin. Duke, therefore, will need to design, and construct a new treatment system for these low volume wastes. The size and technology of the treatment system will be determined based on the water characterization study discussed above. Additionally, based on the final siting of the low volume wastewater treatment system, a new outfall may be needed for the discharge of the effluent from this new wastewater treatment system. With significant changes to the characteristics of the permitted discharge, Duke anticipates a NPDES permit modification will be required to revise the permit to account for the changes in flow and constituent make-up. Even though the permitting task will be initiated during the design and engineering phase, it is expected to continue through the procurement phase and up to the construction phase. In addition, the extent and complexity of the permits required are unknown at this time. The required permits will be evaluated during the engineering and design phase. Since the time needed to prepare the permit applications and the time needed to receive the permits is uncertain, Duke allocated 6 months to account for potential permitting delays. Procurement After the design is complete, Duke will initiate the process to procure the necessary outside resources to construct and install the new wastewater treatment systems. This process will involve the following steps: Evaluate potential vendors for proposal solicitation; Develop and submit request for proposal (RFP) to selected vendors; Conduct a review and vendor selection based on the received bids; Develop required contract documents; Acquire materials (potentially from overseas), which involves: o Shipment, and o Equipment Fabrication — Fabrication and inspection of equipment. RMDS have a fabrication queue that is dependent on total industry -wide demand. Duke, therefore, has allocated 12 months to acquire the necessary materials. Construction Once all the necessary materials are procured, Duke estimates construction of the RMDS will take approximately 13 months. In addition, the tie-in of the RMDS to each individual generating unit will need to occur during outages, which are anticipated to occur between March to May and October to November depending on generation demand. Optimization and Operational Experience As stated above, Duke is planning to have the equipment installed by December 31, 2019 at the latest to meet the obligations under LAMA, in addition, to any CCR requirements. Again, these rules regulate the bottom ash material, not the transport water. Given the system will continue to utilize water to transport bottom ash, time will be needed to gain operational experience and optimize the system to meet the zero discharge limit. Duke estimates a 13 month window will be required to gain the necessary operational experience and fine-tune the system. The 13 month window is estimated based on the potential that the station may only be operating at full load during the winter and summer months and account for commissioning / optimizing occurring at multiple facilities simultaneously. In addition, with NCDEQ approving the implementation date of January 31, 2021 for Marshall Steam Station, Duke would like to stagger the commissioning / optimization activities for Allen by one month. New Wastewater Treatment Svstem As discussed above, with the removal of several non-BATW waste streams from the bottom ash transport system, a new wastewater treatment system will need to be designed and constructed for co - treatment of low volume waste and other regulated process streams per the CCR rule, ELGs, and NDPES permitting requirements. The activities associated with the new wastewater treatment system will be conducted concurrently with the other design activities at the site. These waste streams are not subject to the applicability date in the ELG rule, therefore, Duke is not requesting a compliance date, but this task will need to be completed prior to the effective date of the zero discharge of BATW. Duke anticipates 30 months will be needed to design, install and commission the new wastewater treatment system, based on the following preliminary timeline. New Wastewater Treatment System Activity Duration Months Siting 3 Engineering 6 Procurement 3 Construction/Tie-in 9 Commissioning 3 Start -Up 6 Total: 30 FGD Wastewater The FGD wastewater treatment system at Allen contains the model technology EPA used as the basis for the BAT limits for FGD wastewater, physical / chemical treatment followed by biological treatment. However, the BAT limits were based on data from Allen and Belews Creek Steam Station (BCSS) while the station was primarily using coal from the Central Appalachian region. Based on Duke's experience with the treatment of FGD wastewater, variability in the coal can affect the performance of the biological treatment system. This was evident based on data collected from the FGD wastewater treatment systems at Allen and BCSS in 2014 and 2015 when the stations were using coal from regions other than Central Appalachian. In a memorandum from EPA, Variability in Flue Gas Desulfurization Wastewater: Monitoring and Response dated Sept. 30, 2015, EPA acknowledges data from Allen and BCSS show the selenium concentration can sometimes become elevated. In addition, EPA stated "The coal characteristics could alter the characteristics of the FGD purge stream...". EPA further stated plants have between three to eight years to conduct the necessary studies to properly design the treatment system and plants should investigate the variability of the FGD purge stream to inform the design process. EPA went on to state plants should acquire information on the variability of the system over a "long enough time that will included variability in plant operations such as shutdowns, fuel switches (preferably for all fuel types burned at the plant), variability in electricity generating loads, periods with high ORP, etc." EPA further recognizes that designing, procuring, installing, and optimizing an FGD wastewater treatment system is a complicated and time-consuming undertaking, involving much study and careful planning. For example, EPA states: "For plants that are planning to include fuel flexing in their operations, in the years prior to the installation and operation of the FGD wastewater treatment system, the plant should consider sampling the untreated FGD wastewater to evaluate the wastewater characteristics that are present based on the differing fuel blends. Based on those characteristics, the plant will be better able to design a system that can properly treat its FGD wastewater given variability that might occur at the plant, and it will be better prepared to adjust chemical dosages in the chemical precipitation system to mitigate the variability in the wastewater that enters the biological treatment system." Response to Comments, p. 5-387. EPA also states: "While EPA has based the effluent limitations and standards for selenium and nitrate/nitrite (as N) for FGD wastewater based on the performance of the Allen and Belews Creek biological treatment systems, EPA does not contend that every plant in the industry can simply take the design parameters from those two plants, install the biological treatment system, and meet the effluent limitations. Each plant will need to work with engineering and design firms to assess the wastewater characteristics present at their plant to determine the most appropriate technologies and design the system accordingly meet the effluent limitations. Therefore, some plants may need to design the bioreactors to provide additional bed contact time (as provided by the hydraulic residence time and volume of biomass and carbon substrate), while other plants may find they need less." Response to Comments, p. 5-389 Duke is requesting 52 months from the effective date of the permit to study the variability of the system, evaluate additional treatment needs and design, install and commission additional treatment components to meet the BAT limits based on the following preliminary timeline. FGD WWT Upgrade Activity Duration Months Design & Engineering 25 • Evaluate Variability in the System 12 • Technology Evaluation 7 • Engineering' 6 Procurement 8 Construction/Tie-in 7 Start-up & Optimization 2 12 • Start -Up 2 • Commissioning 6 Total: 52 1) Duke is conducting a similar process for BCSS and has requested an applicability date of Nov. 30 2020. Duke would like an additional three months for Allen to incorporate lessons learned from the system being installed at BCSS. 2) Duke is allocating a 12 month window to complete the commissioning and start-up under all expected operating conditions from full load to partial load to periods of no load and under varying fuel types. Assuming a permit effective date of November 1, 2016, Duke estimates the system can be installed and commissioned to meet the BAT limits on or before February 28, 2021. To design, procure, construct and commission the FGD WWT system at Allen, the following steps must be taken: Design Engineering As with the RMDS, engineering and technology resources are limited due to regulatory requirements for concurrent implementation of programs, such as the CCR Rule and NC-CAMA across applicable sites in North Carolina. In addition, a similar process is being followed for BCSS and Duke would like to incorporate any engineer lessons learned for the system evaluated at BCSS for Allen. Duke is, therefore, estimating 25 months to complete the design and engineering phase of the project. Evaluate Variability in the System As stated by EPA and with Duke's agreement, plants need to conduct studies of the variability of the system over a long enough period of time that will include variability in plant operations such as shutdowns, fuel switches (preferably for all fuel types burned at the plant), variability in electricity generating loads, periods with high ORP, etc. to design an effective treatment system. With the need to evaluate different fuel types to maintain economic viability of the station, Duke estimates at least an additional 12 months after the permit effective date will be required to investigate variability in the system. Technology Evaluation Duke has significant experience in the design, construction and operation of biological treatment systems for selenium reduction. Based on Duke's experience, biological treatment alone may not be a fool proof technology based on the characteristics of the coal. Duke, therefore, is obligate to evaluate cost effective technology that ensures the FGD limits can be met under all conditions, including fuel type, electricity load, etc. At a minimum, Duke will be evaluating the addition of ultrafiltration to the backend of the treatment system. Duke will be working closely with utility organizations, such as the EPRI, to identify other suitable technologies for the removal of selenium from FGD wastewater and additional filtration steps that may be required to meet the limits. Duke estimates an additional 7 months after the completion of the investigation of variability in the system will be required to complete the technology evaluation. Engineering Upon completion of the investigation of variability in the system and technology evaluation, engineering and design of the system can be conducted and Duke has estimated two months for this effort. Procurement After the design is complete, Duke will initiate the process to procure the necessary outside resources to construct and install the new wastewater treatment systems. This process will involve the following steps: Evaluate potential vendors for proposal solicitation; Develop and submit a request for proposal (RFP) to selected vendors; Conduct a review and vendor selection based on the received bids; Develop required contract documents; Acquire materials (potentially from overseas), which involves: o Shipment, and o Equipment Fabrication Fabrication and inspection of equipment. Duke has allocated 8 months to acquire the necessary materials. Construction / Tie In Once all the necessary materials are procured, Duke estimates construction of the FGD WWT will take approximately 7 months to complete. In addition, the tie-in of the additional components to the existing FGD WWT will need to occur during outages, which are anticipated to occur between March to May and October to November depending on generation demand. Commissioning & Start-up Duke estimates that commissioning and start-up of the FGD WWT will take 8 months to complete, 2 months for startup and 6 months for commissioning. Duke, however, is allocating a 12 month window to complete the commissioning and start-up under all expected operating conditions from full load to partial load to periods of no load and under varying fuel and other operating conditions. This will allow the identification of necessary actions that need to be completed and necessary communications protocol in order to maintain and operate the system to comply with the limits. Attachment 5 Aerial of stormwater retention pond and spillways to the south of the landfill August 31, 2016 NPDES application update Allen Steam Station NC0004979 iiVV } a r �i •Y■ � _,�1 � - r _{_' #' �ly�''�'��'_ � ����`..� ~_ Tom_ • ik --EErnerg n y Spillway i IternateF4111way VW01 5 v Attachment 6 Clean Water Act 316(b) alternate schedule request August 31, 2016 NPDES application update Allen Steam Station NC0004979 Alternate Schedule Request §316(b) of the Clean Water Act Allen Steam Station Final regulations to establish requirements for cooling water intake structures at existing facilities were published in the Federal Register on August 15, 2014 (i.e. regulations implementing §316(b) of the Clean Water Act) with an effective date of October 14, 2014. Allen Steam Station is subject to the regulations. The design intake flow of the station is greater than 2 million gallons per day (MGD) and the historical actual intake flows are greater than 125 MGD; therefore, the following submittals are expected to be required: — §122.21(r)(2) Source Water Physical Data §122.21(r)(3) Cooling Water Intake Structure Data — §122.21(r)(4) Source Water Baseline Biological Characterization Data — §122.21(r)(5) Cooling Water System Data — §122.21(r)(6) Chosen Method(s) of Compliance with the Impingement Mortality Standard §122.21(r)(7) Entrainment Performance Studies — §122.21(r)(8) Operational Status §122.21(r)(9) Entrainment Characterization Study — §122.21(r)(10) Comprehensive Technical Feasibility and Cost Evaluation Study §122.21(r)(11) Benefits Valuation Study — §122.21(r)(12) Non -water Quality and Other Environmental Impacts Study As allowed under §125.95(a)(2), Duke Energy would like to request an alternate schedule for the submittals listed above. Allen Steam Station was not subject to the remanded Phase II Rule due to the intake velocity; therefore, none of the above submittals were prepared. Duke Energy will need at least 60 months to prepare the necessary submittals. This timeframe includes complying with the peer review requirement for submittals §122.21(r)(10), §122.21(r)(11), and §122.21(r) (12). The rule requires the necessary submittals to be included with the permit renewal application for permits with an effective date after July 14, 2018. Duke Energy, therefore, would like to request the 316(b) submittals, with the exception of §122.21(r)(6) Chosen Method(s) of Compliance with Impingement Mortality Standard, for Allen Steam Station to be required with the subsequent permit renewal application after July 14, 2018. Since Allen Steam Station is subject to the entrainment best technology available (BTA) determination, a compliance schedule to complete §122.21(r)(6) Chosen Method(s) of Compliance with Impingement Mortality Standard will be requested to be included in the permit upon issuance of the entrainment BTA determination.