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W&RRC Cogenration Facilities Project_Public Hearing
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: December 28, 2012 Dubuque kital All- America City II 111! 2012 Water & Resource Recovery Center Manager Jonathan Brown recommends City Council approval of the plans, specifications, form of contract and estimated cost of $2,113,157 for two turbines or $2,313,157 for three turbines for the Water & Resource Recovery Center Cogeneration Project. 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 the U.S. Environmental Protection Agency and Jeld -Wen Corporation, the City was recently awarded the opportunity to have Jeld -Wen partially fund the project in the amount of $386, 843. 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. 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 no 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 high strength waste digestion at the Water & Resource Recovery Center, and would also produce revenue from the collection of tipping fees for acceptance of such wastes. The financial analyses include both a 400 -kW system and a 600 -kW system, with the major differences between these two scenarios outlined below: • The 600 -kW system is anticipated to cost approximately $200,000 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 per 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 2.5% and 9.7 %, respectively. 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 (GHG) impacts, the estimated GHG reduction resulting from the conversion from incineration to anaerobic digestion at the Water & Resource Recovery Center is about 830 tons per 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 per 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. The costs for financing the Co -Gen project were included in the rate structure analysis performed during the Fiscal Year 2013 budget process and should not impact rates depending upon the outcome of arbitration with Miron Construction. Water & Resource Recovery Center Manager Jonathan Brown recommends that the most viable approach is to proceed with the three turbine option, however, it is in the City's best interest to bid the cogeneration facilities project as a 400 -kW system (two 2 200 -kW microturbines), with the third 200 kW microturbine (600 kW system) as a bid alternative. This will provide some flexibility should the project bid costs be higher than anticipated. 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 Manager Jennifer Larson, Budget Director 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: December 28, 2012 INTRODUCTION Dubuque All-America City 1111 1 2007 The purpose of this memo is to request City Council approval of the plans and specifications, form of contract and estimated cost 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 Co -Gen 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. 5. Future capacity increases with the microturbines will be less expensive than a capacity 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. 1 450.000 400.000 T 350,000 300.000 +i 250.000 200.000 150.000 [ 100.000 • • 2010 ogas Production With High Strength Was 5 Microturbines (1,000 kW Total) 4 Microturbines (800 kW Total) Base Biogas Production 2015 2020 Year Figure 1 Projected Biogas Production and Microturbine Capacity. From draft Renewable Natural Gas for Vehicle Fuel Study (Strand Associates) 2 Microturbines (400 kW Total) 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 delayed 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. 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. 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 no 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. 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 $200,000 more than the 400 -kW system on an initial capital basis. • The 600 -kW system will have marginally higher maintenance costs, estimated at approximately $1 4,000/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 2.5% and 9.7 %, respectively. 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 (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: February 18, 2013: April 1, 2013: April 25, 2014: May 8, 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 is as follows: Two Turbines: Three Turbines: $2.5 million - $386,843 = $2.113 million $2.7 million - $386,843 = $2.313 million The costs for financing the Co -Gen project were included in the rate structure analysis performed during the fy13 budget process and should not impact rates depending upon the outcome of arbitration with Miron Construction. ACTION REQUESTED Based on review of the financial study findings, I concur with Strand's findings. I also believe that the most viable approach is to proceed with the three turbine option, however I also concur that it is in the City's best interest to bid the cogeneration facilities project as a 400 -kW system (two 200 -kW microturbines), with the third 200 kW microturbine (600 kW system) as a bid alternative. This will provide some flexibility should the project bid costs be higher than anticipated. I respectfully request that the City Council approve the plans and specifications, form of contract and estimated cost for the W &RRC Cogeneration Project. 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 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 City of Dubuque W &RRC Cogeneration Project Financial Analysis 11/9/2012 Capacity: Electricity Costs ($/kWH): Generation Uptime: Discount Rate: 2 microturbines =400 kW $ 0.07 92% L 5.0 %I Capital Cost: $ 4500,000 (no grants included) Grants: $ (386,000) Does not include potential AlRant Energy rebate (up to $200,000) or potential green project loan forgiveness through SRF. Anticipated Loan: $ 2,114,000 Loan Interest Rate: 2.0% based on current guidance Annual Debt (P &I): $129,285 400-kW Project - Financial Analysis Annual Annual Net Annual Annual Electricity Electricity Electricity O &M Cost or Maintenance Generated Generated* Cost Savirgs ( Savirgs) Present Worth Year Contract Mr) (kW) (kWH /yr) ($ /yr) ($ /yr( of Sayings 0 1 $ 87,000 2 $ 87,000 3 $ 87,000 4 $ 87,000 5 $ 87,000 6 $ 87,000 7 $ 87,000 8 $ 87,000 9 $ 87,000 10 $ 87,000 11 $ 87,000 12 $ 87,000 13 $ 87,000 14 $ 87,000 15 $ 87,000 16 $ 87,000 17 $ 87,000 18 $ 87,000 19 $ 87,000 20 $ 87,000 350.0 360.0 370.0 380.0 390.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 400.0 J $ 2,114,00C $ 2,114,000 2,907,936 $ (203,556) $ (116,556) $ (111,005) 2,988,712 $ (209,210) $ (122,210) $ (110,848) 3,069,488 $ (214,864) $ (127,864) $ (110,454) 3,150,264 $ (220,518) $ (133,518) $ (109,846) 3,231,04C $ (226,173) $ (139,173) $ (109,046) 3,231,04C $ (226,173) $ (139,173) $ (103,853) 3,231,04C $ (226,173) $ (139,173) $ (98,908) 3,231,04C $ (226,173) $ (139,173) $ (94,198) 3,231,04C $ (226,173) $ (139,173) $ (89,712) 3,231,04C $ (226,173) $ (139,173) $ (85,440) 3,231,04C $ (226,173) $ (139,173) $ (81,371) 3,231,04C $ (226,173) $ (139,173) $ (77,497) 3,231,04C $ (226,173) $ (139,173) $ (73,806) 3,231,04C $ (226,173) $ (139,173) $ (70,292) 3,231,04C $ (226,173) $ (139,173) $ (66,944) 3,231,04C $ (226,173) $ (139,173) $ (63,757) 3,231,04C $ (226,173) $ (139,173) $ (60,721) 3,231,04C $ (226,173) $ (139,173) $ (57,829) 3,231,04C $ (226,173) $ (139,173) $ (55,075) 3,231,04C $ (226,173) $ (139,173) $ (52,453) 20 -yr Present of Annual Costs or Savings: $ (1,683,054) 1 Annual Net Cash Flow with Debt Payment (Debt- Net Sayings) $ 12,730 $ 7,075 $ 1,421 $ (4,233) $ (9,887) S (9,887) S (9,887) S (9,887) $ (9,887) $ (9,887) $ (9,887) S (9,887) S (9,887) S (9,887) $ (9,887) $ (9,887) $ (9,887) S (9,887) S (9,887) S (9,887) No Project - Financial Analysis** Present Worth of Annual Electricity Annual ($ /yrj Electricity $ 203,556 $ 193,862 $ 209,210 $ 189,759 $ 214,864 $ 185,608 $ 220,518 $ 181,421 $ 226,173 $ 177,212 $ 226,173 $ 168,774 $ 226,173 $ 160,737 $ 226,173 $ 153,083 $ 226,173 $ 145,793 $ 226,173 $ 138,850 $ 226,173 $ 132,239 $ 226,173 $ 125,941 $ 226,173 $ 119,944 $ 226,173 $ 114,233 $ 226,173 $ 108,793 $ 226,173 $ 103,612 $ 226,173 $ 98,678 $ 226,173 $ 93,979 $ 226,173 $ 89,504 $ 226,173 $ 85,242 $ 2,682,024 "Tota120 -Yr Pres: -, - - $ 2,682,024 ** * Assumes that electrical production increases linearly every year from 350 kW at time zero to 400 kW after 5years ** Does not include the capitsl (^$250,000) and debt( -$$13, 000 /yr) costs associated with instslling a second boiler, which would likely be required 3 cogen is not implementec City of Dubuque W &RRC Cogeneration Project Financial Analysis 11/9/2012 Capacity: Electricity Costs ($ /kWH): Generation Uptime: Discount Rate: Capital Cost: Grants: Anticipated Loan: Loan Interest Rate: Annual Debt (P &I): 3 microturbines = 600 kW $ 0.07 92' 1 M. 5.0 %I $ 2,700,000 (no grants included) $ ( 386, 000) Does not include potential Ailiant Energy rebate (up to $ 200, 000) orpotentiai green project loan forgiveness through SRF. $ 2,314,000 2.0% based on current guidance $141,517 600 -kW Project- Financial Analysis No Project- Finandal Analysis ** Annual Annual Net Annual Annual Electricity Electricity Electricity Annual O &M Cost or Maintenance Generated Generated* Cost Savings Tipping (Savings) Present Worth Year Contract ($/yr) (kW) (kWH /yr) ($ /yr) Fees#($ /yr) ($ /yr) of Savings 350.0 1 $ 101,000 375.0 3,029,100 $ 2 $ 101,000 400.0 3,231,040 $ 3 $ 101,000 425.0 3,432,980 $ 4 $ 101,000 450.0 3,634,920 $ 5 $ 101,000 475.0 3,836,860 $ 6 $ 101,000 500.0 4,038,800 $ 7 $ 101,000 525.0 4,240,740 $ 8 $ 101,000 550.0 4,442,680 $ 9 $ 101,000 575.0 4,644,620 $ 10 $ 101,000 600.0 4,846,560 $ 11 $ 101,000 600.0 4,846,560 $ 12 $ 101,000 600.0 4,846,560 $ 13 $ 101,000 600.0 4,846,560 $ 14 $ 101,000 600.0 4,846,560 $ 15 $ 101,000 600.0 4,846,560 $ 16 $ 101,000 600.0 4,846,560 $ 17 $ 101,000 600.0 4,846,560 $ 18 $ 101,000 600.0 4,846,560 $ 19 $ 101,000 600.0 4,846,560 $ 20 $ 101,000 600.0 4,846,560 $ (212,037) (226,173) (240,309) (254,444) (268,580) (282,716) (296,852) (310,988) (325,123) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (339,259) (55,000) (60,000) (65,000) (70,000) (75,000) (80,000) (85,000) (90,000) (95,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) 20 -yr Present of Annual Costs or Savings: $ 2,314,000 $ 2,314,000 $ (166,037) $ (158,130) $ (185,173) $ (167,957) $ (204,309) $ (176,489) $ (223,444) $ (183,828) $ (242,580) $ (190,068) $ (261,716) $ (195,297) $ (280,852) $ (199,596) $ (299,988) $ (203,043) $ (319,123) $ (205,710) $ (338,259) $ (207,662) $ (338,259) $ (197,773) $ (338,259) $ (188,355) $ (338,259) $ (179,386) $ (338,259) $ (170,844) $ (338,259) $ (162,708) $ (338,259) $ (154,960) $ (338,259) $ (147,581) $ (338,259) $ (140,554) $ (338,259) $ (133,861) $ (338,259) $ (127,486) $ (3,491,290) Annual Net Cash Flo4 with Debt Payment ## (Debt -Net Savings) $ (24,520) $ (43,656) $ (62,792) $ (81,928) $ (101,064) $ (120,199) $ (139,335) $ (158,471) $ (177,607) $ (196,743) $ (196,743) (196,743) (196,743) $ (196,743) $ (196,743) $ (196,743) $ (196,743) $ (196,743) (196,743) $ (196,743) Present Worth of Annual Electridty Annual ($ /yr) Electricity $ 212,037 $ 201,940 $ 226,173 $ 205,145 $ 240,309 $ 207,588 $ 254,444 $ 209,332 $ 268,580 $ 210,440 $ 282,716 $ 210,967 $ 296,852 $ 210,967 $ 310,988 $ 210,489 $ 325,123 $ 209,577 $ 339,259 $ 208,276 $ 339,259 $ 198,358 $ 339,259 $ 188,912 $ 339,259 $ 179,916 $ 339,259 $ 171,349 $ 339,259 $ 163,189 $ 339,259 $ 155,419 $ 339,259 $ 148,018 $ 339,259 $ 140,969 $ 339,259 $ 134,256 $ 339,259 $ 127,863 $ 3,565,107 Total 20 - ent Wort Return on Investment (20 year) * Assumes that electrical production increases linearly every year from 350 kW at time zero to 600 kW after 10 years. •• Does not indude 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 indude additional revenue from hauled waste acceptance in this option. RESOLUTION NO. 8 -13 APPROVING THE PLANS, SPECIFICATIONS, FORM OF CONTRACT, AND ESTIMATED COST FOR THE WATER & RESOURCE RECOVERY CENTER COGENERATION PROJECT NOW THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF DUBUQUE, IOWA: That the proposed plans, specifications, form of contract and estimated cost for the Water & Resource Recovery Center Cogeneration Project, in the estimated amount of $2,500,000 are hereby approved. Passed, adopted and approved this 7th day of January, 2013. \\ff \-DY� Kevin J. Lys. , Mayor Pro Tem Attest: Kev'n . Firnstall, CMC, ity Clerk NOTICE OF PUBLIC HARING ON PLANS, SPECIFICATIONS, F! RM OF CONTRACT, AND ESTIMATED COST FOR THE CITY OF DUBUQUE WATER & RESOURCE RECOVERY CENTER COGENERATION FACILITIES NOTICE IS HEREBY GIVEN: The City Council of the City of Dubuque, Iowa will hold a public hearing on the proposed plans, specifications, from of contract, and esti- mated cost for the Water & Resource Recovery Center Co- generation Facilities, in accordance with the provisions of Chapter 26, Code of Iowa, at 6:30 p.m., on the 7th day of January, 2013, in the Historic Federal Building Council Cham- bers (second floor), 350 West 6th Street, Dubuque, Iowa. Said proposed plans, speci- fications, form of contract and estimated cost are now on file in the office of the City Clerk. At said hearing any interested person may appear and file objections thereto. The scope of the Project is as follows: The work includes the installation of Micro - turbines, Compression Skid, Heat recovery units and associated mechanical, - electrical, and site work to utilize anaerobic digester gas in a combined heat and power facility. Any visual or hearing- impaired persons need- ing special assistance or persons with special accessibility needs contact the City Clerk's office at (563) 589 -4120 or TDD at (563) 690 -6678 at least 48 hours prior to the meeting. Published by the order of the City Council given on the 17th day of December, 2012. Kevin S. Firnstahl, CMC, City Clerk It 12/21 NOTICE TO BIDDERS CITY OF DUBUQUE PUBLIC IMPROVE- MENT PROJECT WA- TER AND RESOURCE RECOVERY CENTER COGENERATION FA- CILITIES CONTRACT 1 2012 Time and Place for Filing Sealed Propo- s. Sealed bids for the work comprising improvement as stated below must be filed before 2:00 PM on February 5, 2013, in the Office of the City Clerk, City Hall First Floor, 50 West 13th Street, Dubuque, Iowa. Time arad Placed Sealed Proposals Will be Opened and Considered. Sealed proposals will be publicly opened, read aloud, and bids tabulated at 2:00 PM on February 5, 2013, at City Hall Conference Room A, 50 West 13th Street, Dubuque, Iowa, for consideration by the City Council (Council) at its meeting on February 18, 2013. The City of Dubuque, Iowa, reserves the right to reject any and all bids. Time for Commence - ment and Comple- tion of Work. Work shall be commenced after Notice to Proceed has been issued and shall be fully com- pleted in accordance with the requirements listed in the Agree- ment. Bid Security. Each bidder shall accom- pany its bid with a bid security as security that the successful bidder will enter into a contract for the work bid upon and - will furnish after the award of contract a corporate surety bond, accept - able to the govern - mental entity, for the faithful performance of the contract, in an amount equal to one hundred percent of the amount of the contract. The bid security shall be in the amount of five percent (5%) of the amount of the contract and shall be in the form of a cashier's check or certified check drawn on a state chartered or federally chartered bank, or a certified share draft drawn on a state chartered or federally chartered credit union, or the governmental entity may provide for a bidder's bond with corporate surety satis- factory to the govern- mental entity. The bid bond shall contain no conditions excepted as provided in this section. Contract Docu- ments. Bids are to be addressed to the City of Dubuque, Iowa, 50 West 13th Street, Dubuque, IA 52001, and shall be marked "Sealed Bid Water and Resource Recovery Center Cogeneration Facilities Contract 1 2012." Complete digital project bidding docu- ments are available at www.strand,com or at www.cluestcdn. corn. Download the digital plan documents for $30 by inputting the Quest project number 2378035 on the website's Project Search page. Please. contact Quest - CDN.com at (952) 233 1632 or info quest - cdn,com for assist- ance in free member- ship registration, down- loading, and working with this digital project information. Bidding Documents may be reviewed and paper copies may be obtained from the Issuing Office which is Strand Associates, Inc., 910 West Wingra Drive, Madison, Wisconsin 53715. A nonrefundable fee of $150 will be required (shipping and handling fees in- cluded).Overnightmail - ing of Bidding Docu- ments will not be provided. All Bidders submitting' a sealed Bid shall obtain the '. Bidding Documents from QuestCDN.com or from Strand Associates, Inc. Bidders who submit a must - be s -Plan Holder of record at the Issuing Office. Bids from Bidders who are not on the Plan Holders List may be returned as not being responsive. Plan Holders are requested to provide an e -mail address if they wish to receive addenda and other information electron- ically. Plan 'Holders are requested to designate whether they are a prime contractor, sub- contractor, or supplier if they want this information posted on the project Plan Holders List. No Bid will be received unless accom- panied by a cashier's, certified or bank check or a Bid Bond equal to at least 5 percent of the maximum Bid, payable to the OWNER as a guarantee that atter a Bid is accepted, Bidder will execute and file the Agreement and 100% Performance and Payment Bonds within 15 days after the Notice of Award. A Federal Davis Bacon wage rate determin- ation is a requirement of this project. Bidders shall comply with the President's executive Order No. 11246, Equal Employ- ment Opportunity as amended. The City of Dubuque reserves the right to reject any or all Bids, to waive any technicality, and to accept any Bid which it deems advantageous. All Bids shall remain subject to acceptance for 95 days after the time set for receiving Bids. Contract award shall be made based on the lowest responsive and responsible Bidder. Any Contract or Contracts to be awarded are expected to be funded entirely or in part by a loan from Iowa Clean Water State Revolving Fund. This procurement will be subject to regulations contained in appropriate State Statutes and 40 CFR Parts 31, 33, and 35 of the Federal Statutes. Award of Contract 1 2012 may be dependent on loan securement. Women and Minority owned businesses are encouraged to submit Bids for this Project. Bidders must demon - strate positive efforts to utilize women's and minority owned busi- nesses. This procure- ment will be subject to regulations contained in 40 CFR 35.3145(d), and P.L. 102 389 and 1 100 590. In addition, Bidder shall comply with Executive Orders 11625, 12138, and 12432. Project information may be obtained either by calling (608) 251 3480 or by accessing www.strand.com /PI an Distribution/ Contact_plan.htrnl. Preference for Iowa Products and Labor. By virtue of statutory authority, preference will be given to products and provi- sions grown and coal produced within the State of Iowa, and to Iowa domestic labor, to the extent - lawfully 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: December 21, 2012, and for which the charge is $111.79. Subscribed to before me, a Notary Public in and for Dubuque County, Iowa, ,20.x.,. this cg day of required under Iowa statutes. Sales Tax. The bidder should not include sales tax in its bid. A sales tax exemption certificate will be available for all material purchased for incorporation in the project. General Nature of Public improvement. Water & Resource Recovery Center Co- generation Facilities The work includes installation of co- generation facilities to convert digester gas to electricity and heat, and associated me- chanical, electrical, and site work. Pre Bid Construc- tion Conference. Each prospective bid- der is encouraged to attend the Pre Bid Construction Confer- ence to be held at 9:00 AM on January 16, 2013 in the Majestic Room, Five Flags Center 4th and Main Streets, Dubuque, Iowa. Atten- dance by all ° pro - spective bidders is not mandatory but highly recommended. CONTRACTOR must sign the Consent Decree certification agreement bound in this document as a condition of the Contract and prior to commencing any work for this Contract. Published in the Telegraph Herald, December 21, 2012. It 12/21 Notary Public in and for Dubuque County, Iowa. Payback Calculations: All data from Strand Financial Report Method 1. is simply Principle divided by average savings over 20 years PB =Prin /Savings Method 2. incorporates interest costs averged for the 20 year period P B= Prin /(Savings - Interest) Costs from second boiler $15,289 per year 400KW Option Principle Average Savings Average Interest Savings Minus Interest Second Boiler $2,114,000 $136,346 $23,585 $112,761 $15,289 Method 1 Payback = 15.5 years Method 2 Payback = 18.7 years Method 2 including 2nd Boiler Costs Payback = 16.5 years 600KW Option The 600KW Option includes Methods 1 & 2 plus Method 3 which includes revenue from Tipping Fees (These fees are only avaialable in the 600KW Option) Principle Average Savings Average Interest Savings Minus Interest Average Tipping Fees Second Boiler $2,314,000 $295,203 $25,817 $269,386 $88,750 $15,289 Method 1 Payback = 7.8 years Method 2 Payback = 8.6 years Method 3 (includes tipping fees) Payback = 6.5 years Method 3 including 2nd Boiler Costs Payback = 6.2 years City of Dubuque W &RRC Cogeneration Project Capacity: Financial Analysis 11/9/2012 Electricity Costs ($ /kWH): Generation Uptime: Discount Rate: Capital Cost: Grants: Anticipated Loan: Loan Interest Rate: Annual Debt (P &I): 2 microturbines = 400 kW $ 0.07 92% 5.0% Total Costs Total Interest Costs Average Interest (20 yrs) $2,585,706.04 $471,706.04 $23,585.30 Costs if 2nd Boiler Added $250,000.00 2.0% $ 2,500,000 (no grants included) Debt Payment on 2nd Boiler $15,289 $ (386,000) Does not include potential Alliant Energy rebate (up to $200,000) or potential green project loan forgiveness through SRF. $ 2,114,000 2.0% based on current guidance $129,285 Total Interest $471,700 Average Interest $23,585 400 -kW Project - Financial Analysis No Project - Financial Analysis ** Annual Annual Net Annual Annual Electricity Electricity O &M Cost or Maintenance Electricity Generated* Cost Savings (Savings) Present Worth Year Contract ($ /yr) Generated (kW) (kWH /yr) ($ /yr) ($ /yr) of Savings 0 350.0 $ 2,114,000 $ 2,114,000 1 $ 87,000 360.0 2,907,936 $ (203,556) $ (116,556) $ (111,005) 2 $ 87,000 370.0 2,988,712 $ (209,210) $ (122,210) $ (110,848) 3 $ 87,000 380.0 3,069,488 $ (214,864) $ (127,864) $ (110,454) 4 $ 87,000 390.0 3,150,264 $ (220,518) $ (133,518) $ (109,846) 5 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (109,046) 6 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (103,853) 7 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (98,908) 8 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (94,198) 9 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (89,712) 10 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (85,440) 11 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (81,371) 12 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (77,497) 13 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (73,806) 14 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (70,292) 15 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (66,944) 16 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (63,757) 17 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (60,721) 18 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (57,829) 19 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (55,075) 20 $ 87,000 400.0 3,231,040 $ (226,173) $ (139,173) $ (52,453) average saving $ (136,346) 20 -yr Present of Annual Costs or Savings: $ (1,683,054) nnual Net Cash low with Debt Payment ebt - Net Savings 2,731 7,075' $ 1,421 $ (4,233) $ (9,887) $ (9,887) $ (9,887) $ (9,887) $ (9,887) $ (9,88 $ (9,88 $ (9,8 $ (9,887) $ (9,887) $ (9,887) $ (9,88 $ (9,881 $ (9,887) $ (9,887) $ (9,887) $ (141,207) $ (7,060.34) Present Worth Annual Electricity of Annual ($ /yr) Electricity $ 203,556 $ 193,862 $ 209,210 $ 189,759 $ 214,864 $ 185,608 $ 220,518 $ 181,421 $ 226,173 $ 177,212 $ 226,173 $ 168,774 $ 226,173 $ 160,737 $ 226,173 $ 153,083 $ 226,173 $ 145,793 $ 226,173 $ 138,850 $ 226,173 $ 132,239 $ 226,173 $ 125,941 $ 226,173 $ 119,944 $ 226,173 $ 114,233 $ 226,173 $ 108,793 $ 226,173 $ 103,612 $ 226,173 $ 98,678 $ 226,173 $ 93,979 $ 226,173 $ 89,504 $ 226,173 $ 85,242 $ 2,682,024 Total 20 -Yr Present�Gorth (annual + capital): $ 430,946 $ 2,682,024 ** •* Assumes that electrical production increases linearly every year from 350 kW at time zero to 400 kW after 5 years. ** Does not include the capital ($250,000) and debt ($13,000 /yr) costs associated with installing a second boiler, which would likely be required if cogen is not implemented. City of Dubuque W &RRC Cogeneration Project Capacity: Financial Analysis 11/9/2012 Electricity Costs ($ /kWH): Generation Uptime: Discount Rate: 3 microturbines = 600 kW $ 0.07 92% 5.0 %I Total Payments Total lnterest Average Interest $2,830,340.00 $516,340.00 $25,817.00 Capital Cost: $ 2,700,000 (no grants included) Grants: $ (386,000) Does not include potential Alliant Energy rebate (up to $200,000) or potential green project loan forgiveness through SRF. Anticipated Loan: $ 2,314,000 Loan Interest Rate: 2.0% based on current guidance Costs if 2nd Boiler Added $250,000.00 Annual Debt (P &I): $141,517 2.0% Debt Payment on 2nd Boiler $15,289 600 -kW Project - Financial Analysis No Project - Financial Analysis ** Annual Annual Net Annual Annual Electricity Electricity 0 &M Cost or Maintenance Electricity Generated* Cost Savings Annual Tipping (Savings) Present Worth Year Contract ($ /yr) Generated (kW) (kWH /yr) ($ /yr) Fees# ($ /yr) ($ /yr) of Savings 0 1 $ 101,000 2 $ 101,000 3 $ 101,000 4 $ 101,000 5 $ 101,000 6 $ 1.01,000 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 $ (240,309) 3,634,920 $ (254,444) 3,836,860 $ (268,580) 4,038,800 $ (282,716) 4,240,740 $ (296,852) 4,442,680 $ (310,988) 4,644,620 $ (325,123) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) 4,846,560 $ (339,259) (55,000) (60,000) (65,000) (70,000) (75,000) (80,000) (85,000) (90,000) (95,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) (100,000) $ (1,775,000) 20 -yr Present of Annual Costs or Savings: $ 2,314,000 $ 2,314,000 $ (166,037) $ (158,130) $ (185,173) $ (167,957) $ (204,309) $ (176,489) $ (223,444) $ (183,828) $ (242,580) $ (190,068) $ (261,716) $ (195,297) $ (280,852) $ (199,596) $ (299,988) $ (203,043) $ (319,123) $ (205,710) $ (338,259) $ (207,662) $ (338,259) $ (197,773) $ (338,259) $ (188,355) $ (338,259) $ (179,386) $ (338,259) $ (170,844) $ (338,259) $ (162,708) $ (338,259) $ (154,960) $ (338,259) $ (147,581) $ (338,259) $ (140,554) $ (338,259) $ (133,861) $ (338,259) $ (127,486) $ (5,904,073) - 295203,65 $ (3,491,290) Annual Net Cash Flow with Debt Payment## (Debt - Net Savings) $ (24,520) $ (43,656) $ (62,792) $ (81,928) $ (101,064) $ (120,199) $ (139,335) $ (158,471) $ (177,607) 5 (196,743) $ (196,743) $ (196,743) 5 (196,743) $ (196,743) (196,743) $ (196,743) �p$ (196,743) (196,743) $ (196,743) $ (196,743)1 $ (3,073,740) - 153687.0043 Present Worth Annual Electricity of Annual ($ /yr) Electricity 212,037 $ 201,940 226,173 $ 205,145 240,309 $ 207,588 254,444 $ 209,332 268,580 $ 210,440 282,716 $ 210,967 296,852 $ 210,967 310,988 $ 210,489 325,123 $ 209,577 339,259 $ 208,276 339,259 $ 198,358 339,259 $ 188,912 339,259 $ 179,916 339,259 $ 171,349 339,259 $ 163,189 339,259 $ 155,419 339,259 $ 148,018 339,259 $ 140,969 339,259 $ 134,256 339,259 $ 127,863 $ 3,565,107 $ 3,565,107 ** * Assumes that electrical production increases linearly every year from 350 kW at time zero to 600 kW after 10 years. ** 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. Average Tipping Fee (20 yrs) $88,750,00