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W&RRC Cogeneration Facilities Project Award
Masterpiece on the Mississippi TO: The Honorable Mayor and City Council Members FROM: Michael C. Van Milligen, City Manager SUBJECT: Water & Resource Recovery Center Cogeneration Facilities DATE: March 13, 2013 Dubuque kital All- America City II 111! 2012 Sealed bids were received for the Water & Resource Recovery Center Cogeneration Facilities Project. Water & Resource Recovery Center Manager Jonathan Brown recommends award of the contract to the only bidder, Total Mechanical Systems Incorporated, for the base bid installation of two microturbines, along with Alternative #1 for a total installation of three turbines with a combined capacity of 600 kW, for a total bid price of $3,155,000. This amount is $505,000 over the engineer's estimate for the base bid and Alternate #1. On November 1, 2010, the City Council approved the engineering services agreement between the City of Dubuque and Strand Associates to provide planning, design, and construction phase engineering services for the cogeneration project. On April 22, 2011, Strand provided to Water & Resource Recovery Center staff a facility planning report that was then submitted to and approved by the Iowa Department of Natural Resources (IDNR) for low interest funding through the Iowa Finance Authority (IFA). The original project schedule included design completion by May 2011, and construction completion by early 2012. Because of funding unknowns, the project has been delayed by approximately 18 months. Through an agreement with US EPA and the Jeld -Wen Corporation, the City was recently awarded the opportunity to have Jeld -Wen partially fund the project in the amount of $386,843. In addition to the Jeld -Wen grant, the City has received information from Alliant Energy that the project will be approved for a rebate of up to $200,000. This rebate is only available in calendar year 2013, meaning that the project has begun and equipment ordered. The design of the project is complete and the Iowa Department of Natural Resources has approved the project for construction. Financing of the project has been approved by IFA and IDNR. The project includes the installation of electrical generation equipment (microturbines) that will use biogas from the anaerobic digestion facilities to produce electricity. Heat recovery equipment will provide heat to the digesters and the Water & Resource Recovery Center Bio- Process buildings, which will improve the overall alternative energy recovery efficiency from the biogas. Several factors were considered when deciding to move forward with the project rather than rebidding. The grant from Jeld -Wen for $386,843 and the Alliant Energy Rebate of $200,000 would be in jeopardy if the City would be unable to proceed with the project in a timely manner. In discussions with the successful bidder and with several contractors, who took out plan sets but did not bid, it became apparent that the likelihood of significant reductions in the bid amounts would be unlikely, especially in light of the risk of losing $586,843 in grant and rebate money. A financial analysis was conducted for the project to estimate approximate cash flow impacts and overall cost - effectiveness of the project. Two scenarios were evaluated: 1. Construction of a two microturbine system with 400 -kW of electrical generation capacity. This system would use the biogas generated from the Water & Resource Recovery Center sludge only, and limited high- strength wastes would be brought to the plant for digestion and biogas production. 2. Construction of a three microturbine system with 600 -kW of electrical generation capacity. This would provide electrical generation capacity related to the additional biogas that could be produced from high- strength wastes digestion at the Water & Resource Recovery Center, and would also produce revenue from the collection of tipping fees for acceptance of such wastes. An important consideration is that this financial analysis does not include the capital ($165,000) and debt ($12,000 /yr) associated with the installation of a second boiler. Using the combined heat and power (CHP) capabilities of the cogeneration system, the boiler becomes a backup system rather than a primary source of heat for the digester complex. If the boiler becomes the primary heat source, a backup boiler would be required to assure heat for the digesters. The financial analyses include both a 400 -kW system and a 600 -kW system. The major differences between these two scenarios are outlined below: • The 600 -kW system is anticipated to cost approximately $355,000 more than the 400 -kW system on an initial capital basis. • The 600 -kW system will have marginally higher maintenance costs, estimated at approximately $14,000 /year. • The 600 -kW system will allow the City to accept high- strength wastes at the plant, which will generate additional revenue from increased electrical production as well as tipping fees. • The 600 -kW system is estimated to have a positive cash flow (including new debt service) within the first year or two of operation, whereas the 400 -kW system is projected to have essentially no impact (perhaps slightly positive) on cash flow. • The estimated 20 -year return -on- investment for the 400 -kW and 600 -kW systems is approximately 7.8% and 12 %, respectively. • The 400 -kW system has a payback of 11 years and the 600 -kW system 9 years. 2 A more aggressive implementation of the introduction of high strength waste under the 600 -kW scenario would improve the cost benefit analysis. Related to green house gas impacts, the estimated green house gas reduction resulting from the conversion from incineration to anaerobic digestion at the Water & Resource Recovery Center is about 830 tons /year of CO2 equivalent. The additional green house gas reduction resulting from cogeneration, which typically is calculated as electrical energy cost avoidance, is about 2,200 tons /year of CO2 equivalent. This is based on 400 kW of electrical generation, operating 92% of the time, as well as a conversion of 1.37 Ibs CO2 equivalent per kWH. As electrical generation increases, the green house gas reductions would also increase. The costs for financing the Co -Gen project were included in the rate structure analysis performed during the Fiscal Year 2013 budget process and would not impact rates significantly for the 400kW system and an approximate 1% rate increase for Fiscal Year 2015 for the 600 -kW system depending upon the outcome of arbitration with Miron Construction. I concur with the recommendation and respectfully request Mayor and City Council approval. Michael C. Van Milligen MCVM:jh Attachment cc: Barry Lindahl, City Attorney Cindy Steinhauser, Assistant City Manager Teri Goodmann, Assistant City Manager Jonathan R. Brown, Water & Resource Recovery Center Manager 3 THE CITY OF Masterpiece on the Mississippi TO: Michael C. Van Milligen, City Manager FROM: Jonathan R. Brown, W &RRC Manager SUBJECT: W &RRC Cogeneration Facilities DATE: March 12, 2013 Dubuque All-America City 1111 1 2007 INTRODUCTION The purpose of this memo is to request that the City Council authorize the City Manager to enter into negotiations and execute a contract with the low bidder for the W &RRC Cogeneration Project. BACKGROUND On November 1, 2010, the City Council approved the engineering services agreement between the City of Dubuque and Strand Associates to provide planning, design, and construction phase engineering services for the cogeneration project. On April 22, 2011 Strand provided to W &RRC staff a facility planning report that was then submitted to and approved by the Iowa Department of Natural Resources (IDNR) for low interest funding through the Iowa Finance Authority (IFA). A copy of this report is attached for reference. In summary the report determined that the most cost effective and sustainable approach was the use of Microturbines rather than Engine- Generators for the Cogeneration project. This decision has recently been reviewed and is still considered to be the most viable option. The following factors were used to reach this conclusion. 1. Costs and energy recovery for the two technologies were similar. 2. Microturbines and heat recovery modules will better fit in the Cogeneration Room. The Cogeneration Room is a very limited space for the engine generators and removal of /access to the equipment would be difficult. 3. The engine generators require a remote mounted after - cooler radiator and engine -water radiator located outside, which is difficult to site at the WRRC. 4. Microturbine modular capacity expansion provides flexibility to add units as gas production increases, shown in Figure 1. One 450 kW engine generator, conversely, could be installed now with a potential build out to two units, 900 kW total. Projected Gas Production (ft' /day) 5 Future capacity increases with the microturbines will be less expensive than a capacit.; increase for the engine generators (plug- and -play concept for future modules). 6. Unison Solutions is located in Dubuque and offers a maintenance contract for microturbines. 7. The design is complete and has been approved by IDNR for funding through the IFA State Revolving Fund. A change to engine generators would require design changes and approval of IDNR. This would add additional costs and delays to the project. 450.000 400.000 t I 350.000 300.000 250.000 200.000 150.000 100,000 5 Microturbines (1,000 kW Total) 4 Microturbines 800 kW Total) ogas Production With High Strength Was Base Bioges Production 2010 2015 2020 Year Figure 1 Projected Biogas Production and Microturbine Capacity. From draft Renewable Natural Gas for Vehicle Fuel Study (Strand Associates) 2025 2030 The original project schedule included design completion by May 2011 and construction completion by early 2012. Because of funding unknowns, the project has been decayed by approximately 18 months. Through an agreement with USEPA and the Jeld -Wen Corporation, the City was recently awarded the opportunity to have Jeld -Wen partially fund the project in the amount of $386,843. In addition to the Jeld -Wen grant we have received information from Alliant Energy that the project will be approved for a rebate of to $200,000. This rebate is only available in calendar year 2013, meaning that the project has begun and equipment ordered. This amount is included in a financial update that also includes an inflation factor in calculating the long term costs and savings. The design of the project is complete and the Iowa Department of Natural Resources has approved the project for construction. Financing of the project has been approved by the Iowa Finance Authority (IFA) and IDNR. The project includes the installation of electrical generation equipment (microturbines) that will use biogas from the anaerobic digestion facilities to produce electricity. Heat recovery equipment will provide heat to the digesters and the W &RRC Bio- Process buildings, which will improve the overall alternative energy recovery efficiency from the biogas. On January 7, 2013 the City Council approved the plans and specifications for the W &RRC Cogeneration Project with a bid opening date of February 5, 2013. On bid day Total Mechanical Systems of St. Paul MN, was the only bidder. A comparison of the engineer's estimates and the bid amounts is as follows: Bid Amounts: Total Mechanical Systems Base Bid: $2,800,000 Alternate #1 (additional turbine) $355,000 Alternate #2 (small backup boiler) $165,000 Engineers Estimate: Base Bid: $2,400,000 Alternate #1 $250,000 Alternate #2 $200,000 Several factors were considered when deciding to move forward with the project rather than rebidding. The grant from Jeld -Wen for $386,843 and the Alliant Energy Rebate of $200,000 would be in jeopardy if we would be unable to proceed with the project in a timely manner. In discussions with the successful bidder and with several contractors, who took out plan sets but did not bid, it became apparent that the likelihood of significant reductions in the bid amounts would be unlikely especially in light of the risk of losing $586,843 in grant and rebate money. DISCUSSION A financial analysis was conducted for the project to estimate approximate cash flow impacts and overall cost - effectiveness of the project. Two scenarios were evaluated: 1. Construction of a two microturbine system with 400 -kW of electrical generation capacity. This system would use the biogas generated from the W &RRC sludge only, and limited high- strength wastes (HSW) would be brought to the plant for digestion and biogas production. 2. Construction of a three microturbine system with 600 -kW of electrical generation capacity. This would provide electrical generation capacity related to the additional biogas that could be produced from HSW digestion at the W &RRC, and would also produce revenue from the collection of tipping fees for acceptance of such wastes. An important consideration is that this financial analysis does not include the capital ($165,000) and debt ($12,000 /yr) associated with the installation of a second boiler. Using the combined heat and power (CHP) capabilities of the cogeneration system the boiler becomes a backup system rather than a primary source of heat for the digester complex. If the boiler becomes the primary heat source a backup boiler would be required to assure heat for the digesters. The financial analyses are attached to this memorandum and include both a 400 -kW system and a 600 -kW system. The major differences between these two scenarios are outlined below: • The 600 -kW system is anticipated to cost approximately $355,000 more than the 400 -kW system on an initial capital basis. • The 600 -kW system will have marginally higher maintenance costs, estimated at approximately $14,000/year. • The 600 -kW system will allow the City to accept high- strength wastes at the plant, which will generate additional revenue from increased electrical production as well as tipping fees. • The 600 -kW system is estimated to have a positive cash flow (including new debt service) within the first year or two of operation, whereas the 400 -kW system is projected to have essentially no impact (perhaps slightly positive) on cash flow. • The estimated 20 -year return -on- investment for the 400 -kW and 600 -kW systems is approximately 7.8% and 12 %, respectively. • The 400 -kW system has a payback of 11 years and the 600 -kW system 9 years. A more aggressive implementation of the introduction of High Strength Waste under the 600 -kw scenario would improve the cost benefit analysis. The following table gives an indication of the potential for receiving high strength wastes into the anaerobic digesters and the subsequent generation of electrical energy. Summary Provided by Strand Engineering Number of Trucks /Day GPD Based on 5,000 gal./ Truck Tipping Fee ($ /gal_) Average Travel Distance (Hrs. of Travel) Maximum Travel Distance (Hrs. of Travel) Sheboygan, WI 5 to 13 25,000 to 65,000 $0.030 1 4+ Milwaukee MSD1 10 - 50,000 $0.030 1 to 2 Davenport, IA` 3 to 4 15,000 to 20,000 $0.080 0.25 Des Moines, IA 50 250,000 $0.025 2 to 4 8 1 The HS'.V receiving station is completing construction this spring. Information is based on planned NSW receiving. 2 All HSWis received from one local industry, five days perweek. Related to green house gas (GHG) impacts, the estimated GHG reduction resulting from the conversion from incineration to anaerobic digestion at the W &RRC is about 830 tons /year of CO2 equivalent. The additional GHG reduction resulting from cogeneration, which typically is calculated as electrical energy cost avoidance, is about 2,200 tons /year of CO2 equivalent. This is based on 400 kW of electrical generation, operating 92% of the time, as well as a conversion of 1.37 Ibs CO2 equivalent per kWH. As electrical generation increases, the GHG reductions would also increase. Proposed Project Schedule: December 17, 2012: December21, 2012: January 7, 2013: February 5, 2013: March 18, 2013: April 29, 2013: May 23, 2014: June 5, 2014: Set Hearing Notice to Bidders Public Hearing Bid Opening Award Bid and IFA -IDNR Loan Closing Notice to Proceed Substantial Completion Final Completion BUDGET IMPACT The total estimated cost for the Co -Gen project including Jeld -Wen funding of $386,843 and a rebate of $200,000 from Alliant Energy is from the attached spreadsheet and is as follows: Two Turbines: Three Turbines: $2,690,005 $3,032,750 The costs for financing the Co -Gen project were included in the rate structure analysis performed during the fy13 budget process and would not impact rates significantly for the 400kW system and an approximate 1% rate increase for fy15 for the 600 -kW system depending upon the outcome of arbitration with Miron Construction. ACTION REQUESTED I respectfully request that the City Council authorize the City Manager to negotiate and execute a contract with Total Mechanical Systems Incorporated of St. Paul, MN for the Base Bid installation of two microturbines along with Alternative #1 for a total installation of three turbines with a combined capacity of 600 kW fora total bid price of $3,155,000. Attachments: cc: Steve Brown, Project Manager Jenny Larson, Budget Director Ken TeKippe, Finance Director ASSOCIATES, E N G I N E E R S 910 West Wingra Drive Madison, WI 53715 Phone: 608 - 251 -4843 Fax: 608- 251 -8655 Office Locations Madison, WI Joliet, IL Louisville, KY Lexington, KY Mobile, AL Columbus, IN Columbus, OH Indianapolis, IN Milwaukee, WI Cincinnati, OH Phoenix, AZ www,strand,com April 22, 2011 Mr. Steve Sampson Brown, P,E, City of Dubuque 50 West 13th Street Dubuque, IA 52001 Re: Water Pollution Control Plant Cogeneration Facilities Dear Steve, Enclosed are five copies of the final Water Pollution Control Plant (WPCP) Cogeneration Facilities report, which is being submitted to the Iowa Department of Natural Resources to qualify this project for Cow interest loan funding, Based on the recommendations of this report and the City's concurrence with the direction of the project, we are proceeding with detailed design of the microturbine cogeneration system at the Dubuque WPCP, Please call with any questions, Sincerely, STRAND ASSOCIATES, INC,6 Randall A, Wirtz, Ph,iD,l, P.E. Enclosure: Repor R :\MAD \Dooumenls\Roports \Archivo \201 I \D,buquo, IA \WPCPCogen.Fas,l 154,033.raw.jno\Report \Cogeneration Reporl,rev,4.2I- 11,docx\4 /22/2011 Report for Cityof uque, Iowa Water Pollution Control Plant Cogeneration Facilities ,1,�,`,19,111 �,,�,!/ �titi\ ©� f •••. �.� pi,� �,�'¢Q°°'� ' °•�`�°'.e ,. e n�C,1 / „'1 I �t►�;'f 'lam° 16137 °4: I hereby certify that this engineering document was prepared by me or under my direct personal supervision and that I am a duly licensed Professional Engineer under the laws of the State of Iowa, FOR STRA D ASSOCIATE • , INC,® ((' d.-1,---AA” ( ,,;'/V.:-. 2-4,61( °� > /// On f r ```�`\\\ � Randall Number 6E ,7 Date My license renewal date-is- ecember 31, 2011 Pages or sheets covered by this seal: Entire Study Prepared by: STRAND ASSOCIATES, INC.° 910 West Wingra Drive Madison, WI 53715 www,strand,com April 2011 STRAND ASSOCIATES, INC.` ENGINEER fl TABLE OF CONTENTS Page No. or Following WATER POLLUTION CONTROL PLANT COGENERATION FACILITIES Introduction 1 Projected B|ogaoP[oduction---------------...--------.---1 Electrical Generatior Alternatives 1 Generation Device Evaluation 2 Opinions of Cost 3 Recommendations 5 TABLES Table 1 Biogas Production Estimates 1 Table 2 Microturbine Nonmonetary Considerations 2 Table 3 Engine Generator NoDnooOetary Considerations ... ......... ................. 2 Table Energy Balance for Microturbines and Engine Generators 3 Table 5 Total Present Worth Summary (20 Year) 5 FIGURE APPENDIX APPENDIXTOTAL PRESENT WORTH ) City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities INTRODUCTION The City of Dubuque Water Pollution Control Plant (WPCP) incinerators will be decommissioned, and new anaerobic digestion facilities will be constructed as part of the current 2010 WPCP Modifications Project. The anaerobic digestion process at the WPCP will produce significant quantities of biogas that can be used as a renewable fuel. Three common end uses for digester gas are in a microturbine combined heat and power (CHP) system, an engine generator CHP system, and in a boiler system, The 2010 WPCP project included a boiler to utilize the biogas, This report further evaluates the microturbine and engine generator alternatives. The majority of municipal wastewater treatment plants (WWTPs) that employ anaerobic digestion use biogas to replace or supplement natural gas for the heating needs of the digestion process as well as for space heating in buildings. However, this typically only uses a portion of the total biogas produced in the digestion process, CHP systems utilize all, or nearly all, of the biogas on a year -round basis to generate electricity. During cold months, waste heat from the generators is captured and used to heat the digesters and other buildings. During warm months, some of the waste heat would not be utilized. PROJECTED BIOGAS PRODUCTION The microturbines and engine generator alternatives were sized based on current average and future design (year 2030) biogas production estimates of 165,000 cubic feet per day (f3 /day) and 303,000 f3 /day, respectively. The estimated biogas production rates for the current average, future design, and future design with food residuals are shown in Table 1. Table 1 Biogas Production Estimates ELECTRICAL GENERATION ALTERNATIVES A. Microturbines Microturbines are gas turbines that burn methane mixed with compressed air. The hot pressurized gases that result from combustion are forced out of the combustion chamber and through the turbine wheel, causing it to spin and turn the generator. Microturbines provide relatively clean combustion and low exhaust emissions, particularly of nitrogen oxide (NOx) components. Microturbines require a fuel with a lower heating value (LHV) >450 British Thermal Units /standard cubic feet (BTU /scf) and at pressures between 75 and 80 pounds per square inch (psi). B. Engine Generators Reciprocating gas engine generators for anaerobic digester gas are essentially natural gas engines that have been modified to handle larger volumes of fuel because of the greater percentage of carbon dioxide (002) in digester gas, and to accept higher levels of contaminants. A reciprocating, or internal combustion (IC), engine converts the energy contained in a fuel to mechanical power. This mechanical power is used to turn a shaft in the engine. A generator is attached to the IC engine to convert the mechanical motion into power, Prepared by Strand Associates, Inc," 1 R;\ MAD \Documents \Reports\Archlve\2011 \Dubuque, IA \WPCP Cogen,Fac.1154,033.raw,Jan \Report\Cogeneration Report , rev.4- 21.11,docx \4/22/2011 Future Design With Current Average Future Design Food Residuals Gas Production (f3 /day) 165,000 303,000 379,000 Table 1 Biogas Production Estimates ELECTRICAL GENERATION ALTERNATIVES A. Microturbines Microturbines are gas turbines that burn methane mixed with compressed air. The hot pressurized gases that result from combustion are forced out of the combustion chamber and through the turbine wheel, causing it to spin and turn the generator. Microturbines provide relatively clean combustion and low exhaust emissions, particularly of nitrogen oxide (NOx) components. Microturbines require a fuel with a lower heating value (LHV) >450 British Thermal Units /standard cubic feet (BTU /scf) and at pressures between 75 and 80 pounds per square inch (psi). B. Engine Generators Reciprocating gas engine generators for anaerobic digester gas are essentially natural gas engines that have been modified to handle larger volumes of fuel because of the greater percentage of carbon dioxide (002) in digester gas, and to accept higher levels of contaminants. A reciprocating, or internal combustion (IC), engine converts the energy contained in a fuel to mechanical power. This mechanical power is used to turn a shaft in the engine. A generator is attached to the IC engine to convert the mechanical motion into power, Prepared by Strand Associates, Inc," 1 R;\ MAD \Documents \Reports\Archlve\2011 \Dubuque, IA \WPCP Cogen,Fac.1154,033.raw,Jan \Report\Cogeneration Report , rev.4- 21.11,docx \4/22/2011 City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities GENERATION DEVICE EVALUATION A. Microturbines The microturbine analysis includes two initial 200 - kilowatt (kW) Capstone microturbines with a potential build -out to 1,000 kW (5 units at 200 kW each). The turbines and heat recovery units would be installed in the Structure 75 (Solids Processing Building) Cogeneration Room. The 2010 WPCP Modifications Project will provide a biogas cleaning and conditioning system, which includes moisture removal, hydrogen sulfide removal, and siloxane removal facilities installed at the Anaerobic Digestion (Structure 70) complex. For the microturbine alternative, a gas compression skid would be installed in Structure 70 (Digester Building) to meet fuel pressure requirements for the microturbines. A summary of the nonmonetary considerations related to microturbines is shown in Table 2. An energy balance of the 400 -kW microturbine system is shown in Table 4. Positives Negatives Modular capacity expansion (flexibility). Few manufacturers. Potential build -out to 1,000 kW within current space. Requires gas compression (electrical load). Unison is located in Dubuque and offers maintenance contract for microturbines. Microturbines and heat recovery modules will fit in Cogeneration Room. Table 2 Microturbine Nonmonetary Considerations B. Engine Generators Similar to the microturbines, engine generators would be installed in the Structure 75 Cogeneration Room. Engine generators do not require gas cleaning or conditioning in addition to that provided in the WPCP Modifications Project. Therefore, the gas compression skid is not required. Initially, one engine generator would be installed. The space available will accommodate two engine generators. The engine requires an after - cooler radiator and engine jacket water radiator located outside for cooling. Two gas engine generator options that operate at different speeds were evaluated. The Caterpillar G3508 gas engine is a low speed, 1,200 revolutions per minute (rpm), heavy -duty engine. The Caterpillar G3412 gas engine is a 1,800 rpm, normal -duty engine. The heavy -duty engine and normal -duty engine have an electrical output rating of 390 kW and 450 kW, respectively. The nonmonetary evaluation of these engine generators is summarized in Table 3. The engine generator energy balance is shown in Table 4. Positives Negatives Remote - mounted after - cooler radiator and engine -water radiator located outside; difficult to site at the WPCP. Requires two 500 - gallon oil storage tanks for fresh and waste oil in the basement. Space is very limited for generators and removal of equipment would be difficult. Competitive suppliers JCaterplar, Jenbacher, Waukesha, and others). Install one unit now at 390 or 450 kW with potential build -out to two units. Robust and proven technology, Greater overall efficiency than microturbines. Table 3 Engine Generator Nonmonetary Considerations Prepared by Strand Associates, Inc.® 2 R:\ MAD\ Documents \Reports\Archlve\2011 \Dubuque, IA \WPCP Cogen.Fac.1154.033,raw.jan \Report \Cogeneralion Reportrev.4.21- 11,docx \4/22/2011 City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities Table 4 Energy Balance for Microturbines and Engine Generators C. Performance Evaluation Table 4 compares the energy balances for the microturbines and engine generators at the current average gas production. The energy input available to each device, based on the estimated current average gas production rate and a 600 BTU /scf lower heating value, is 4,120 thousand British thermal units per hour (MBH). The engine generators have greater heat recovery than the microturbines because of heat recovery from the engine jacket water and exhaust, while the microturbines can only provide heat recovery from the exhaust. The heating demand of 1,320 MBH includes biosolids heating for the anaerobic digestion process as well as the heating load for Structures 70 and 75 during the winter, If heat recovery were not employed, the heating demand would need to be provided through burning of natural gas. During winter operations, the monthly value of natural gas would be approximately $10,000 per month at a value of $1.00 per therm. The annual natural gas cost would be approximately $90,000 without heat recovery on the cogeneration system. Since all of the cogeneration devices provide adequate heat recovery for the anticipated heating loads, the anticipated natural gas usage is zero under nearly all conditions. The electrical output is greater for the normal duty engine because of the higher electrical efficiency and higher rated output, OPINIONS OF COST A. Microturbines The installed opinion of capital cost for a 400 kW microturbine system is approximately $823,000. Additionally, the gas compression skid system has an opinion of capital cost of approximately $265,000 installed. The opinion of annual operation and maintenance (O &M) cost is approximately $87,000 and includes routine maintenance (9 -year factory protection plan), overhauls, and the compression skid electrical use. The gas cleaning costs for sulfur, siloxanes, and moisture removal were not included in this annual O &M cost because the cost will be equal for the three generator alternatives. Annual O &M costs for the microturbine system assume that a long -term maintenance contract is entered into with an authorized Capstone service provider. Preliminary proposals for a maintenance contract were obtained and included in the annual O &M costs. The maintenance contract includes routine maintenance as well as major equipment overhauls approximately every 5 years or Prepared by Strand Associates, Inc.® 3 R:\ MAD \Documents \Reports\Archive\2011 \Dubuque, IA \WPCP Cogen.Fac.1154.033.raw,jan \Report \Cogeneration Report .rev,4.21- 11.docx1412 2/2 0 1 1 Heavy -Duty Engine Generator (390 kW) Normal -Duty Engine Generator (450 kW) Microturbines (Two 200 kW) Electrical Generation Potential (kW) 390 422 398 Gas Production Energy Available (MBH) 4,120 4,120 4,120 Heat Recovery (MBH) 1,770 1,980 1,650 Average Heating Demand (MBH) 1,320 1,320 1,320 Adequate Heat Recovery Yes Yes Yes Electrical Efficiency 33% 35% 33% Thermal Efficiency 44% 48% 40% Table 4 Energy Balance for Microturbines and Engine Generators C. Performance Evaluation Table 4 compares the energy balances for the microturbines and engine generators at the current average gas production. The energy input available to each device, based on the estimated current average gas production rate and a 600 BTU /scf lower heating value, is 4,120 thousand British thermal units per hour (MBH). The engine generators have greater heat recovery than the microturbines because of heat recovery from the engine jacket water and exhaust, while the microturbines can only provide heat recovery from the exhaust. The heating demand of 1,320 MBH includes biosolids heating for the anaerobic digestion process as well as the heating load for Structures 70 and 75 during the winter, If heat recovery were not employed, the heating demand would need to be provided through burning of natural gas. During winter operations, the monthly value of natural gas would be approximately $10,000 per month at a value of $1.00 per therm. The annual natural gas cost would be approximately $90,000 without heat recovery on the cogeneration system. Since all of the cogeneration devices provide adequate heat recovery for the anticipated heating loads, the anticipated natural gas usage is zero under nearly all conditions. The electrical output is greater for the normal duty engine because of the higher electrical efficiency and higher rated output, OPINIONS OF COST A. Microturbines The installed opinion of capital cost for a 400 kW microturbine system is approximately $823,000. Additionally, the gas compression skid system has an opinion of capital cost of approximately $265,000 installed. The opinion of annual operation and maintenance (O &M) cost is approximately $87,000 and includes routine maintenance (9 -year factory protection plan), overhauls, and the compression skid electrical use. The gas cleaning costs for sulfur, siloxanes, and moisture removal were not included in this annual O &M cost because the cost will be equal for the three generator alternatives. Annual O &M costs for the microturbine system assume that a long -term maintenance contract is entered into with an authorized Capstone service provider. Preliminary proposals for a maintenance contract were obtained and included in the annual O &M costs. The maintenance contract includes routine maintenance as well as major equipment overhauls approximately every 5 years or Prepared by Strand Associates, Inc.® 3 R:\ MAD \Documents \Reports\Archive\2011 \Dubuque, IA \WPCP Cogen.Fac.1154.033.raw,jan \Report \Cogeneration Report .rev,4.21- 11.docx1412 2/2 0 1 1 City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities 40,000 hours. The present worth costs for the microturbine alternative includes these future major overhauls over the 20 -year design life of the facilities. Microturbines have a nominal life expectancy of approximately 10 years, However, the maintenance contract approach essentially provides new equipment as the microturbines reach the end of their useful life. To sell electricity to the local power utility in the future, electrical paralleling switchgear will be required. The switchgear is not required to operate the microturbines for plant electrical use and, therefore, was not included in the project cost opinion. For future grid connection, space for this gear is available in the Cogeneration Room or below this room in the basement, B, Engine Generators The opinion of installed costs for the heavy -duty and normal -duty Caterpillar engines are $1,119,000 and $844,000, respectively. Annual O &M costs for the heavy -duty engine and normal -duty engine system alternatives are estimated to be $81,000 and $123,000, respectively, based on information provided by the manufacturer and local representative, The normal -duty engine has a greater O &M cost than the heavy -duty engine because it operates at higher speeds, which requires more frequent overhauls and routine maintenance. As with the microturbines, the gas cleaning and conditioning costs were not included in the O &M costs, The engine generators require a paralleling switchgear for plant electrical use, which adds approximately $204,000 to the opinion of capital cost. This switchgear for the engine generator could also allow for a future connection to the electrical grid, Annual O &M costs for the engine generator alternatives are based on "$ per kilowatt hour (kWh)" level costs provided by equipment suppliers. These O &M costs are $0.025 /kWh for the heavy -duty engine and $0,035 /kWh for the normal -duty engine. These annual costs include routine maintenance as well as engine overhauls approximately every 5 to 7 years and are included in the 20 -year present worth costs for these alternatives. With proper maintenance and overhauls, the engine generators have a life expectancy of 15 to 20 years or more, especially the heavy -duty generators. We have assumed the generators would not need to be replaced within the 20 -year design life for these facilities, C. Total Present Worth The 20 -year total present worth (TPW) analysis for the evaluated devices is included in the Appendix and summarized in Table 5. The engine generators have greater structural, mechanical, and electrical costs than the microturbines because of the remote- mounted heat exchangers, paralleling switchgear, switchgear control room, and engine cooling water piping. The heating, ventilating, and air conditioning (HVAC) costs are greater for the microturbines because these require supply fans and ductwork to provide the cooling and combustion air. The electrical savings for each device is based on $0.07 kWh and the estimated current average gas production rate, This is expected to be a conservative estimate of electrical savings since biogas production is expected to increase throughout the life of the facilities, In addition, the cost of electricity may increase at a faster rate than the overall inflation rate accounted for in the total present worth analysis, which employs an effective discount rate of 4.375 percent. If the cost of electricity increases at a rate faster than inflation, the electrical savings would be higher. Prepared by Strand Associates, Inc,® 4 R:\ MAD\ Documents \Reports\Archfve12011\Dubuque, IAIWPCP Cogen.Fac,1154,033.raw.Jan \Report \Cogeneration Report .rev.4- 21- 11.docx14/22/2011 City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities Each alternative is expected to operate 8,000 hours a year to account for maintenance downtime. Based on this analysis, the microturbine alternative has the lowest TPW and the normal -duty engine generator has the second lowest TPW, though these values are considered approximately equal at this stage of planning. Total Project Cost Annual O &M Annual Electrical Savings Total Present Worth (20 year) Heavy Duty Engine Generator (390 kW) Normal Duty Engine Generator (450 kW) Microturbines (400 kW) $2,387,000 $1,745,000 $1,921,000 $81,000 $123,000 $87,000 ($218,000) ($236,000) ($223, 000) $585,000 $259,000 $197,000 See attached TPW of each alternative (Appendix) for details Table 5 Total Present Worth Summary (20 Year)1 RECOMMENDATIONS A. Generation Device Based on the evaluations of the microturbines and engine generators, microturbines are recommended for digester gas utilization at the Dubuque WPCP. The microturbines and normal -duty gas engine have similar opinions of total present worth. However, space constraints and system layout within the Solids Processing Building favor microturbines over engine generators. In addition, service for the microturbines is anticipated to be provided from a local service firm, which should improve service response for future equipment issues and decrease downtime. B, Preliminary Design Figure 1 presents a preliminary layout for the microturbines in the Solids Processing Building (Structure 75) Cogeneration Room. The microturbine room is required by code to have a 2 -hour fire -rated wall to separate this space from the rest of the building. A stud wall inside the Cogeneration Room will separate the microturbine air intake on the south side of the room from the heat exchanger side. Combustion and cooling intake air will be ducted down from the existing louvers at the top of the structure to the intake space. On the heat exchanger side, an exhaust fan will control the room temperature. The microturbines will be accessible with a manufacturer- provided cart, which allows for removal of microturbines during servicing or overhauls. Additional 200 kW microturbines and heat exchangers can be added as gas production increases. At the estimated gas production rate for future design with food residuals, the microturbines could generate approximately 930 kW, which matches the build -out space of five 200 kW units. Prepared by Strand Associates, lnc,® 5 R:\ MAD \Documents \Reporis\Archive12011 \Dubuque, IA \WPCP Cogen,Fac.1154,033.raw.Jan \Report \Cogeneration Report .rev,4- 21- 11,docx \4/22/2011 City of Dubuque, Iowa Water Pollution Control Plant Cogeneration Facilities C. Recommended Alternative Considerations The following alternatives are provided for the City's consideration. With respect to the microturbine system, there is a relatively significant cost incentive to install 600 kW of generation capacity (three 200 kW units) rather than 400 kW of generation capacity (two 200 kW units). The total opinion of capital cost of the 400 kW system is approximately $1,921,000, or $4,800 /kW. In comparison, the total opinion of capital cost for the 600 kW system is approximately $2,149,000, or $3,600 /kW. The addition of the third 200 kW microturbine adds approximately $228,000 to the capital costs, or $1,140/kW of added capacity. The 600 kW system would not have significant additional structural, mechanical, electrical, or HVAC costs compared to the 400 kW because the Cogeneration Room and piping would largely be the same except for an additional hot water pump, piping, and electrical work for the third heat exchanger. In addition, having a third microturbine will reduce the overall maintenance downtime on the cogeneration system, since a standby unit can be brought online when another unit is down for maintenance. We recommend requesting a Bid Alternative in the Bidding Documents to include a third 200 kW microturbine, 2. Locating the microturbines and heat recovery modules outdoors would reduce structural and HVAC costs of the project. However, this alternative would provide a less ideal location for maintenance and servicing. 3. Rather than a 2 -hour fire -rated wall constructed at full height to the roof, a 2 -hour fire -rated structural ceiling over the Cogeneration Room could be considered. This option would provide additional usable space above the Cogeneration Room. To support the ceiling, structural columns may be required. These may have service clearance and layout conflicts, and this option would increase the cost of the project. 4. Even though it is not required by code, the City may elect to install a fire suppression system in the Cogeneration Room to protect the high -cost equipment, Prepared by Strand Associates, Inc,' 6 R:I MAD\ Documents1Reports \Archive12011\Dubuque, IA\WPCP Cogen,Fac,1154,033,raw.Jan \Report \Cogeneration Report .rev.4.21- 11.docx14/22/2011 APPENDIX TOTAL PRESENT WORTH City of Dubuque WPCP Heavy -Duty Caterpillar Engine Discount Rate 4.375% 20 year TPW ITEM Initial Capital Future Capital Service Replacement 20 yr Salvage Salvage Value Cost Cost Life Cost (P.W.) Value (P.W,) Heavy Duty Engine 1,119,000 1,119,000 20 011 Storage Tanks 14,000 14,000 20 Paralleling Switchgear 204,000 204,000 20 Subtotal $ 1,337,000 Structural 122,000 Mechanical 160,000 20 Electrical 200,000 20 HVAC 68,000 20 Subtotal $ 1,887,000 Contractors General Conditions @ 10% 189,000 Construction Costs 2,076,000 Contingencies @ 15% 311,000 Total Capital Costs $ 2,387,000 $ $ $ Present Worth $ 2,387,000 $ $ Operation Costs (Annual)* 81,000 Electrical Savings (Annual)* (218,000) Total $ (137,000) Present Worth of 0 &M $ (1,802,000) Summary of Present Worth Costs Capital Cost 2,387,000 Replacement O &M Cost (1,802,000) Salvage Value - TOTAL PRESENT WORTH $ 586,000 * Based on current annual average conditions S;\ MAD \1100 -- 1199 \1154 \033 \Spr \Total Present Worth Analysis- DBQ,xIsxA -1 ALT ENG1 390 kW City of Dubuque WPCP Normal -Duty Caterpillar Engine Discount Rate 4,375% 20 year TPW ITEM Initial Capital Future Capital Service Replacement 20 yr Salvage Salvage Value Cost Cost Life Cost (P.W.) Value (P.W.) Normal Duty Engine 611,000 611,000 20 Oil Storage Tanks 14,000 14,000 20 Paralleling Switch Gear 204,000 204,000 20 Subtotal $ 829,000 Structural 122,000 Mechanical 160,000 20 Electrical 200,000 20 HVAC 68,000 20 Subtotal $ 1,379,000 Contractors General Conditions @ 10% 138,000 Construction Costs 1,517,000 Contingencies @ 15% 228,000 Total Capital Costs $ 1,745,000 Present Worth $ 1,745,000 Operation Costs (Annual)" 123,000 Electrical Savings (Annual)" (236,000) Total $ (113,000) Present Worth of O &M $ (1,486,000) Summary of Present Worth Costs Capital Cost 1,745,000 Replacement O &M Cost (1,486,000) Salvage Value TOTAL PRESENT WORTH $ 259,000 Based on current annual average conditions S;\ MAD \1100 - -1199 \1154 \033 \Spr \Total Present Worth Analysis- DBQ.xlsxA -2 ALT ENG2 450 kW City of Dubuque WPCP Capstone Microturbines Discount Rate 4,375% 20 year TPW ITEM Initial Capital Future Capital Service Replacement 20 yr Salvage Salvage Value Cost Cost Life Cost (P.W.) Value (P.W.) Microturbines 823,000 823,000 20 Compression Skid 265,000 265,000 15 139,000 177,000 75,000 Subtotal $ 1,088,000 Structural 72,000 20 Mechanical 100,000 20 Electrical 160,000 20 HVAC 98,000 20 Subtotal $ 1,518,000 Contractors General Conditions @ 10% 152,000 Construction Costs 1,670,000 Contingencies @ 15% 251,000 Total Capital Costs $ 1,921,000 Present Worth $ 1,921,000 Operation Costs (Annual)" 87,000 Electrical Savings (Annual)* (223,000) Total $ (136,000) Present Worth of O &M $ (1,788,000) Summary of Present Worth Costs Capital Cost 1,921,000 Replacement 139,000 O &M Cost (1,788,000) Salvage Value (75,000) TOTAL PRESENT WORTH $ 197,000 " Based on current annual average conditions $ 139,000 $ 177,000 $ 75,000 $ 139,000 $ 75,000 S;\ MAD \1100 -- 1199 \1154 \033 \Spr \Total Present Worth Analysis- DBQ.xlsxA -3 ALT MT 400 kW J City of Dubuque WPCP Cogeneration Project Financial Analysis 10/11/2011 Revised: 03 -11 -2013 Capacity: Electricity Costs ($ /kWH): Generation Uptime: Discount Rate: 3 microturbines = 600 kW 0.07 92% 5.0% Capital Cost: $ 3,047,914 Loan Interest Rate: 2.0% Annual Debt (P &I): $186,400 Low Bid Add Alt. Engineering 5% Cont. Total Cost Less Grant Less Cont. Adj Less Rebate Loan Fee 0.5% $ 2,800,000 $ 355,000 $ 320,000 $ 3,475,000 $ 173,750.0 $ 3,648,750 $ 386,000 $ 30,000 $ 200,000 $ 15,164 600 -kW Project Analysis No Project Analysis ** Annual Annual Electricity Annual Maintenance Electricity Generated* Annual Electricity Tipping Fees# Year Contract ($ /yr) Generated (kW) (kWH /yr) Cost Savings ($ /yr) ($/yr) 0 1 $ 101,000 2 $ 101,000 3 $ 101,000 4 $ 101,000 5 $ 101,000 6 $ 101,000 7 $ 101,000 8 $ 101,000 9 $ 101,000 10 $ 101,000 11 $ 101,000 12 $ 101,000 13 $ 101,000 14 $ 101,000 15 $ 101,000 16 $ 101,000 17 $ 101,000 18 $ 101,000 19 $ 101,000 20 $ 101,000 350.0 375.0 400.0 425.0 450.0 475.0 500.0 525.0 550.0 575.0 600.0 600.0 600.0 600.0 600.0 600.0 600.0 600.0 600.0 600.0 600.0 3,029,100 $ (212,037) 3,231,040 $ (226,173) 3,432,980 $ (245,115) 3,634,920 $ (264,724) 3,836,860 $ (285,019) 4,038,800 $ (306,021) 4,240,740 $ (327,748) 4,442,680 $ (350,223) 4,644,620 $ (373,465) 4,846,560 $ (397,496) 4,846,560 $ (405,446) 4,846,560 $ (413,555) 4,846,560 $ (421,826) 4,846,560 $ (430,263) 4,846,560 $ (438,868) 4,846,560 $ (447,645) 4,846,560 $ (456,598) 4,846,560 $ (465,730) 4,846,560 $ (475,045) 4,846,560 $ (484,546) $ (156,000) $ (156,000) $ (156,000) $ (156,000) $ (156,000) $ (208,000) $ (208,000) $ (208,000) $ (208,000) $ (208,000) $ (208,000) $ (208,000) $ (208,000) $ (260,000) $ (260,000) $ (260,000) $ (260,000) $ (260,000) $ (260,000) $ (260,000) 20 -yr Present of Annual Costs or Savings: Total 20 -Yr Present Worival + capital): Return on Investment 20year) Net O &M Cost or Present Worth (Savings) ($ /yr) Cum. Net Savings of Savings $ 3,047,914 $ 3,047,914 $ 3,047,914 $ (267,037) $ 2,780,877 $ (254,321) $ (281,173) $ 2,499,704 $ (255,032) $ (300,115) $ 2,199,589 $ (259,250) $ (319,724) $ 1,879,865 $ (263,038) $ (340,019) $ 1,539,846 $ (266,414) $ (413,021) $ 1,126,825 $ (308,203) $ (434,748) $ 692,077 $ (308,968) $ (457,223) $ 234,854 $ (309,466) $ (480,465) $ (245,611) $ (309,712) $ (504,496) $ (309,717) $ (512,446) $ (299,617) $ (520,555) $ (289,865) $ (528,826) $ (280,448) $ (589,263) $ (297,618) $ (597,868) $ (287,585) $ (606,645) $ (277,911) $ (615,598) $ (268,583) $ (624,730) $ (259,588) $ (634,045) $ (250,913) $ (643,546) $ (242,546) 12.0% Annual Net Cash Flow with Debt Payment (Debt - Net Savings) $ (80,637) (94,772) (113,714) (133,324) (153,619) (226,620) (248,348) $ (270,822) $ (294,064) $ (318,096) $ (326,046) $ (334,155) (342,426) (402,862) (411,468) (420,245) (429,198) (438,330) (447,644) (457,145) Present Worth Annual Electricity of Annual ($ /yr) Electricity $ 212,037 $ 201,940 $ 226,173 $ 205,145 $ 245,115 $ 211,739 $ 264,724 $ 217,789 $ 285,019 $ 223,320 $ 306,021 $ 228,358 $ 327,748 $ 232,925 $ 350,223 $ 237,044 $ 373,465 $ 240,739 $ 397,496 $ 244,028 $ 405,446 $ 237,056 $ 413,555 $ 230,283 $ 421,826 $ 223,703 $ 430,263 $ 217,312 $ 438,868 $ 211,103 $ 447,645 $ 205,071 $ 456,598 $ 199,212 $ 465,730 $ 193,521 $ 475,045 $ 187,991 $ 484,546 $ 182,620 $ (5,598,793) $ 4,330,900 ** Does not include the capital (- $250,000) and debt (^'$13,000 /yr) costs associated with installing a second boiler, which would likely be required if cogen is not implemented. # This is likely underestimated. Tipping fees could be considerably higher. ## Does not include additional revenue from hauled waste acceptance in this option. IFTAL BORROW AMOUN City of Dubuque WPCP Cogeneration Project Financial Analysis 10/11/2011 City of Dubuque WPCP Cogeneration Project Financial Analysis 10/11/2011 Capacity: Electricity Costs ($ /kWH): Generation Uptime: Discount Rate: Capital Cost: Loan Interest Rate: Annual Debt (P &I): 2 micraturbines = 400 kW 0.07 92% 5.0% $ 2,703,450 2.0% $165,334 400 -kW Project Analysis Low Bid Add Alt. Engineering 5% Cont. Total Cost Less Grant Less Rebate Loan Fee 0.5% 2,800,000 320,000 3,120,000 156,000 3,276,000 386,000 200,000 13,450 Annual Annual Electricity Electricity Annual Maintenance Generated Generated* Annual Electricity Tipping Fees# Year Contract ($ /yr) (kW) (kWH /yr) Cost Savings ($ /yr) ($ /yr) 0 1 $ 87,000 360.0 2,907,936 $ (203,556) 2 $ 87,000 370.0 2,988,712 $ (209,210) 3 $ 87,000 380.0 3,069,488 $ (219,161) 4 $ 87,000 390.0 3,150,264 $ (229,427) 5 $ 87,000 400.0 3,231,040 $ (240,016) 6 $ 87,000 400.0 3,231,040 $ (244,817) 7 $ 87,000 400.0 3,231,040 $ (249,713) 8 $ 87,000 400.0 3,231,040 $ (254,707) 9 $ 87,000 400.0 3,231,040 $ (259,801) 10 $ 87,000 400.0 3,231,040 $ (264,997) 11 $ 87,000 400.0 3,231,040 $ (270,297) 12 $ 87,000 400.0 3,231,040 $ (275,703) 13 $ 87,000 400.0 3,231,040 $ (281,217) 14 $ 87,000 400.0 3,231,040 $ (286,842) 15 $ 87,000 400.0 3,231,040 $ (292,579) 16 $ 87,000 400.0 3,231,040 $ (298,430) 17 $ 87,000 400.0 3,231,040 $ (304,399) 18 $ 87,000 400.0 3,231,040 $ (310,487) 19 $ 87,000 400.0 3,231,040 $ (316,697) 20 $ 87,000 400.0 3,231,040 $ (323,030) 350.0 $ (84,324) $ (84,324) $ (84,324) $ (84,324) $ (84,324) $ (112,432) $ (112,432) $ (112,432) $ (112,432) $ (112,432) $ (112,432) $ (112,432) $ (112,432) $ (140,541) $ (140,541) $ (140,541) $ (140,541) $ (140,541) $ (140,541) $ (140,541) 20 -yr Present of Annual Costs or Savings: Total 20 -Yr Present Worth (annual + capital): Return on Investment (20 year) Net O &M Cost or Present Worth (Savings) ($ /yr) Cum. Net Savings of Savings $ 2,703,450 $ 2,703,450 $ $ (200,880) $ 2,502,570 $ $ (206,534) $ 2,296,036 $ $ (216,486) $ 2,079,550 $ $ (226,752) $ 1,852,798 $ $ (237,341) $ 1,615,458 $ $ (270,249) $ 1,345,209 $ $ (275,145) $ 1,070,063 $ $ (280,140) $ 789,923 $ $ (285,234) $ 504,690 $ $ (290,430) $ 214,260 $ $ (295,730) $ (81,470) $ $ (301,136) $ $ (306,650) $ $ (340,382) $ $ (346,119) $ $ (351,971) $ $ (357,939) $ $ (364,027) $ $ (370,237) $ $ (376,571) $ 2,703,450 (200,880) (187,333) (187,009) (186,549) (185,963) (201,664) (195,541) (189,610) (183,864) (178,299) (172,907) (167,684) (162,623) (171,916) (166,489) (161,242) (156,168) (151,261) (146,515) (141,926) $ (3,495,441) Annual Net Cash Flow with Debt Payment (Debt - Net Savings) $ (35,546) $ (41,200) $ (51,152) (61,418) $ (72,007) $ (104,915) $ (109,811) $ (114,806) $ (119,900) $ (125,096) $ (130,396) $ (135,802) $ (141,316) $ (175,048) $ (180,785) $ (186,637) $ (192,605) $ (198,693) $ (204,903) $ (211,237) No Project Analysis ** Annual Electricity ($ /yr) P resent Worth of Annual Electricity $ 203,556 $ 193,862 $ 209,210 $ 189,759 $ 219,161 $ 189,320 $ 229,427 $ 188,751 $ 240,016 $ 188,059 $ 244,817 $ 182,686 $ 249,713 $ 177,466 $ 254,707 $ 172,396 $ 259,801 $ 167,470 $ 264,997 $ 162,685 $ 270,297 $ 158,037 $ 275,703 $ 153,522 $ 281,217 $ 149,136 $ 286,842 $ 144,875 $ 292,579 $ 140,735 $ 298,430 $ 136,714 $ 304,399 $ 132,808 $ 310,487 $ 129,014 $ 316,697 $ 125,328 $ 323,030 $ 121,747 $ 3,204,371 $ (791,991) $ 3,204,371 ** 7.8% ** Does not include the capital (^'$250,000) and debt (^'$13,000 /yr) costs associated with installing a second boiler, which would likely be required if cogen is not implemented, Price per kWH YR Amt 1,2 0.07 Price Per Gallon = $ 0.04 *AII estimates assume 5,000 gal trucks five days per week 3 0.0714 4 0.072828 5 0.07428456 6 0.075770251 7 0.077285656 8 0.078831369 9 0.080407997 10 0.082016157 11 0.08365648 12 0.085329609 13 0.087036202 14 0.088776926 15 0.090552464 16 0.092363513 17 0.094210784 18 0.096094999 19 0.098016899 20 0.099977237 Input Estimated # of Trucks Per Weekday YR 1 YR2 YR3 YR 4 YR5 YR6 YR7 YR 8 YR9 YR 10 YR 11 YR 12 YR 13 YR 14 YR 15 YR 16 YR 17 YR 18 YR 19 YR20 3 3 3 3 3 4 4 4 4 4 4 4 4 5 5 5 5 5 5 5 600KW 400KW $ (156,000.00) $ (84,324.32) $ (156,000.00) $ (84,324.32) $ (156,000.00) $ (84,324.32) $ (156,000.00) $ (84,324.32) $ (156,000.00) $ (84,324.32) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (208,000.00) $ (112,432.43) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) $ (260,000.00) $ (140,540.54) * *400KW option has less incentive to dump high - strength waste, therefore tippin¢ will be less likely to produce the same $$ as 600 KW, as the extra methane produc City of Dubuque WPCP Cogeneration Project Financia I Analysis 10/11/2011 fees ed would not be used to fuel microturbines RESOLUTION NO. 99 -13 AWARDING THE PUBLIC IMPROVEMENT CONTRACT FOR THE WATER & RESOURCE RECOVERY CENTER COGENERATION PROJECT Whereas, sealed proposals have been submitted by contractors for the Water & Resource Recovery Center Cogeneration Project pursuant to Resolution No. 8 -13 and Notice to Bidders published in a newspaper published in the City of Dubuque, Iowa on the 21st day of December, 2012 Whereas, said sealed proposals were opened and read on the 5th day of February, 2013 and it has been determined that Total Mechanical Systems Inc. of St. Paul, MN with a bid in the amount of $2,800,000 and an Alternative #1 bid amount of $355,000 is the lowest responsive, responsible bidder for the Project. NOW THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF DUBUQUE, IOWA: That a Public Improvement Contract for the Project is hereby awarded to Total Mechanical Systems Inc. and the City Manager is hereby directed to execute a Public Improvement Contract on behalf of the City of Dubuque for the Project. Passed, approved and adopted this 18th day of March, 2013. Roy D. Buol, Mayor Attest: Kevi ' . Firnstahl, "City erk CITY OF DUBUQUE, IOWA OFFICIAL NOTICC NOTICE is hereby given that the Dubuque City Council will conduct public hear- ings at a meeting to commence at 6:30 p.m. on March 18,'.2013,. in the Historic Federal Building, 350 West 6th Street, on the following:' Text Amendments Request by the City of. I Dubuque to amend Articles 5 and 14 of the Unified _De ielop.ment Code regarding off- street parking require- ments to add "Parks, Public or Private, and similar Natural Recre- ation Areas" to the list I of land uses. Request by ttie City of Dubuque to amend Article 13- 3.6(A), of th'e UnifiBd Development Code regarding. Instal- lation of sidewalks. - • Copies of supportipg'' documents for the public hearings are on file in the City Clerk's Office and may be viewed 'during normal working hours. Written comments regarding the, above public hearings may be submitted to the City Clerk's Office on or before, said time of public hearing. At said time and place of public hearings all interested citizens and parties will be given an opportunity to be heard for or against said rezoning. Any Visual or hearing impaired persons need- ing special assistance or persons with special accessibility needs should contact the City Clerk's Office at (563) 589 -4120 or TTY (563) 690 -6678 at least 48 hours prior to the meeting. Kevin S. Firnstahl City Clerk 1t 3/9 STATE OF IOWA {SS: DUBUQUE COUNTY CERTIFICATION OF PUBLICATION I, Suzanne Pike, a Billing Clerk for Woodward Communications, Inc., an Iowa corporation, publisher of the Telegraph Herald,a newspaper of general circulation published in the City of Dubuque, County of Dubuque and State of Iowa; hereby certify that the attached notice was published in said newspaper on the following dates: March 9, 2013, and for which the charge is $14.20. ,S)v. Subscribed to before m a Notary Public in and for Dubuque County, Iowa, this /50 day of a'Lc% , 20 /3 . Notary Public in and for Dubuque County, Iowa. "- MARY K. WESTERMEYcr fi x v Commission Number 1548