Senior Thesis Report Spring Appendix - A. HAP Calculations without Enthalpy Wheel Excel Graphs

Transcription

1 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix - A HAP Calculations without Enthalpy Wheel Excel Graphs

2 Cooling Plant Sizing Summary for Chiller Plant Monmouth CD New Schedule1 04/03/2005 psuae 02:07PM 1. Plant Information: Plant Name Plant Type Design Weather Chiller Plant Chiller Plant Trenton, New Jersey 2. Cooling Plant Sizing Data: Maximum Plant Load Tons Load occurs at Aug 1700 ft²/ton ft²/ton Floor area served by plant ft² 3. Coincident Air System Cooling Loads for Aug 1700 System Cooling Coil Load Air System Name Mult. ( Tons ) AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU System loads are for coils whose cooling source is ' Chilled Water '. Hourly Analysis Program v.4.2 Page 1 of 1

3 Monthly Simulation Results for Chiller Plant Monmouth CD New Schedule1 04/03/2005 psuae 02:12PM Plant Simulation Results (Table 1) : Cooling Coil Load Plant Load Chiller Output Chiller Input Primary Chilled Water Pump Condenser Water Pump Cooling Tower Fan Month (kbtu) (kbtu) (kbtu) (kwh) (kwh) (kwh) (kwh) January February March April May June July August September October November December Total Hourly Analysis Program v.4.2 Page 1 of 1

4 Heating Plant Sizing Summary for Hot Water Plant Monmouth CD New Schedule1 04/03/2005 psuae 02:07PM 1. Plant Information: Plant Name Plant Type Design Weather Hot Water Plant Hot Water Boiler Plant Trenton, New Jersey 2. Heating Plant Sizing Data: Maximum Plant Load MBH Load occurs at Winter Design BTU/(hr-ft²) 60.3 BTU/(hr-ft²) Floor area served by plant ft² 3. Coincident Air System Heating Loads for Winter Design System Heating Coil Load Air System Name Mult. ( MBH ) AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU System loads are for coils whose heating source is ' Hot Water '. Hourly Analysis Program v.4.2 Page 1 of 1

5 Monthly Simulation Results for Hot Water Plant Monmouth CD New Schedule1 04/03/2005 psuae 02:12PM Plant Simulation Results (Table 1) : Heating Coil Load Plant Load Boiler Output Boiler Input Boiler Misc. Electric Primary Hot Water Pump Month (kbtu) (kbtu) (kbtu) (kbtu) (kwh) (kwh) January February March April May June July August September October November December Total Hourly Analysis Program v.4.2 Page 1 of 1

6 Desing Day Electric Load Load (kw) Hour

7 Design Day Electric Load with No Chiller Load (kw) Hour

8 Yearly Cooling Load (Tons)

9 Yearly Cooling Thermal Storage (Tons) Tons Hours

10 Yearly Heating Load Heating Load (MBH) Hour

11 Yearly Electric Chiller Load (kw) Hour

12 Yearly Electric Load with No Chiller Load (kw) Hour

13 Yearly Heating and Cooling Thermal Load (MBH) Load (MBH) Hours

14 Yearly Heating and Cooling w/ Thermal Storage (MBH) Thermal Load (MBH) Hours

15 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix - B HAP Calculations with Enthalpy Wheel Excel Graphs

16 Cooling Plant Sizing Summary for Chiller Plant Monmouth CD New Schedule EW 04/03/2005 psuae 02:03PM 1. Plant Information: Plant Name Plant Type Design Weather Chiller Plant Chiller Plant Trenton, New Jersey 2. Cooling Plant Sizing Data: Maximum Plant Load Tons Load occurs at Aug 1700 ft²/ton ft²/ton Floor area served by plant ft² 3. Coincident Air System Cooling Loads for Aug 1700 System Cooling Coil Load Air System Name Mult. ( Tons ) AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU System loads are for coils whose cooling source is ' Chilled Water '. Hourly Analysis Program v.4.2 Page 1 of 1

17 Monthly Simulation Results for Chiller Plant Monmouth CD New Schedule EW 04/03/2005 psuae 01:46PM Plant Simulation Results (Table 1) : Cooling Coil Load Plant Load Chiller Output Chiller Input Primary Chilled Water Pump Condenser Water Pump Cooling Tower Fan Month (kbtu) (kbtu) (kbtu) (kwh) (kwh) (kwh) (kwh) January February March April May June July August September October November December Total Hourly Analysis Program v.4.2 Page 1 of 1

18 Heating Plant Sizing Summary for Hot Water Plant Monmouth CD New Schedule EW 04/03/2005 psuae 02:03PM 1. Plant Information: Plant Name Plant Type Design Weather Hot Water Plant Hot Water Boiler Plant Trenton, New Jersey 2. Heating Plant Sizing Data: Maximum Plant Load MBH Load occurs at Winter Design BTU/(hr-ft²) 26.8 BTU/(hr-ft²) Floor area served by plant ft² 3. Coincident Air System Heating Loads for Winter Design System Heating Coil Load Air System Name Mult. ( MBH ) AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU AHU System loads are for coils whose heating source is ' Hot Water '. Hourly Analysis Program v.4.2 Page 1 of 1

19 Monthly Simulation Results for Hot Water Plant Monmouth CD New Schedule EW 04/03/2005 psuae 01:46PM Plant Simulation Results (Table 1) : Heating Coil Load Plant Load Boiler Output Boiler Input Boiler Misc. Electric Primary Hot Water Pump Month (kbtu) (kbtu) (kbtu) (kbtu) (kwh) (kwh) January February March April May June July August September October November December Total Hourly Analysis Program v.4.2 Page 1 of 1

20 Design Day Electric Load Load (kw) Hour

21 Design Day Electric without Chiller Load (kw) Hour

22 Yearly Cooling Load (Tons)

23 Yearly Cooling with Thermal Storage (Tons) Tons Hours

24 Yearly Heating Load Heating Load (MBH) Hour

25 Yearly Electric Load with Chiller Load (kw) Hour

26 Yearly Electric without a Chiller Load (kw) Hour

27 Yearly Heating and Cooling Thermal Load (MBH) Load (MBH) Hours

28 Yearly Heating and Cooling w/ Thermal Storage (MBH)

29 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix C Hess Micro-generator Specifications

30 Empowering Your World Technical Specifications H E S S M I C R O G E N Packaged Cogeneration System SPECIFICATION HESS 375 SYSTEM (a) Frequency 60 Hz 50 Hz Continuous Electric Output at unity power factor (kw) (b) Mechanical Power (bhp) Rotating Speed (rpm) 1,800 1,500 Heat Rate (BTU per kwh) (c) 10,220 10,220 Combined Efficiency 85.9% 83.6% Electrical Efficiency 34.5% 33.4% Thermal Efficiency 50.6% 50.2% Fuel Consumption (SCFM) (d) Fuel Consumption (Therms per Hour) (d) Total Thermal Energy Output (BTU per Hour) 1,937,658 1,618,305 Heat from Water Jacket (BTU per Hour) 1,187, ,863 Heat from Exhaust (BTU per Hour) 750, ,441 Cooling Tons (e) (tons of absorption chilling) TBD TBD Steam Output 15 psi (lbs per hour) (f) Steam Output 125 psi (lbs per hour) (f) Exhaust Temperature ( F) (Engine Out) 1,022 1,009 Exhaust Temperature ( F) (Module Out) Exhaust Flow (lbs/hr) 3,189 2,681 Minimum Water Flow Rate (gpm) Maximum Water Temperature ( F) (Module Out) Cogen Return Temperature ( F) (Nominal) Generator Electrical Output Voltage (g) 120/208, 120/240, or 277/480, 3-phase 219/380, 3 phase Type Single bearing, Direct Coupled, Continuous Power Factor Synchronous: Variable from 0.8 lagging to 0.8 leading Options Synchronous Operating Modes Environmental (a) NOx CO Noise Fuel Type (i) Standard Minimum Gas Pressure Maximum Gas Pressure Package Size Dimensions (L x W x H) Weight (l) Compliance Standards (j) (k) 7 (j) (k) 21 Grid Independent, Standby, or In Parallel with Utility Grid < 0.15 g/bhp hr (< 9 ppm) < 0.60 g/bhp hr (< 84 ppm) < 71 dba at 3 meters (h) Natural Gas 905 BTU/SCF LHV inches H 2 O / 0.25 PSI inches H 2 O / 0.75 PSI 11' 8" x 4' x 5' 10" (3.6m x 1.2m x 1.8m) 11,600 lbs (5,260 kg) UL 2200 Listed (generating system) UL 1741 Type Tested (control system) UL 508 Listed (industrial control equipment) CA Rule 21 compliant SCAQMD compliant IEEE 1547 compliant Notes (f) Assuming 78% boiler efficiency (a) All specifications are based on rich burn configuration using optional SCAQMD (g) 600 V available upon request compliant technology (h) Sound level as fitted with optional sound hood. Option increases length (b) Power output can be derated to 350 kva upon customer request at time of of cabinet by 31 inches. Standard sound option is 80 dba order. Heat rate at 350 kva increases by approximately 2% (i) Other fuel options available including propane, biogas (methane), and diesel (c) Heat rate assumes maximum exhaust back pressure of 31.5 inches H 2 O (j) Gas pressure as measured at full load operating flow rate (d) Using 905 BTU/SCF LHV natural gas (k) Gas pressure variation must be within ± 2% (e) Depending on local conditions (l) Weight includes catalytic converter and sound attenuated cabinet

31 Technical Specifications H E S S M I C R O G E N Packaged Cogeneration System Empowering Your World SPECIFICATION HESS 375 SYSTEM Engine Generator Electrical System Fuel System Heat Recovery System System Controls and Monitoring Enclosure Warranty Daewoo manufactured V-Type 12 cylinder, 21.9L displacement 10.5:1 compression ratio 8.7 lbs/kw (3.8 kgs/kw) power-to-weight ratio 12 lead reconnectable synchronous generator PMG brushless excitation for synchronous generator NEMA 105 C temperature rise, continuous duty operation Voltage regulation ± 0.5% Digital inductive ignition system 24 vdc battery Battery charger included 24 vdc starter and alternator Draw through carburetion Turbocharged intercooler water to air Inlet temperature at 110 F (43 C) Total system heat recovery including: oil, engine jacket, manifold, turbo, and exhaust gas Comprehensive engine controls monitor temperatures, pressures, and flow rates Onboard microprocessor-based control system: protects, parallels, and synchronizes all loads to utility monitors and captures 120 system data points monitors and captures electric and gas utility pulses 24/7 connection with Hess operations center Internet-based and point-to-point communication of data third party remote monitoring compatible ModBus TCP/IP capable Easily accessible, service-friendly design Rainproof, 11 gauge corrosion-resistant steel cabinet Premium sound attenuation at < 71 3 meters (h) Contains all mechanical, electrical, control and heat recovery components 18 months from delivery or 1 year from initial startup, whichever occurs first Packaged, wholly-engineered cogeneration and distributed generation systems Most compliant onsite systems in the industry (e.g., UL, Rule 21, IEEE, SCAQMD) Integrated, protective, paralleling, and synchronizing switchgear for simplified interconnection System operation in parallel or isolated from utility grid with emergency backup capability Multiple fuel options including natural gas, biogas, diesel, and LPG The Hess Microgen Advantage Internet based monitoring system: onboard data capture, storage, and communication, capable of 24/7 narrowband, broadband, and wireless connection Specifications and availability may change without notice. Contact Hess Microgen directly for the most up-to-date information. 01/01/ I n d u s t r i a l P a r k w a y C a r s o n C i t y, N V USA ( ) p h o n e ( ) f a x w w w. h e s s m i c r o g e n. c o m i n f h e s s m i c r o g e n. c o m Version 2.0

32 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix D Cention Absorption Chillers

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36 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix E Thermal Energy Storage

37 Thermal Storage Without an Enthalpy Wheel Thermal Storage Without an Enthalpy Wheel Cooling Coil Load Constant Chiller Production + Charge - Discharge Charging Rate Discharge Rate Hour MBH MBH MBH MBH MBH Total Load Stored Ton-hr Stored Average FoM 90% Tons Delta T 15 Max Tank Volume (gal) 330,652 Load Factor 0.58 Tank Volume (ft^3) 44,208

38 Load Profile for Design Day Tons Charge Thermal Storage Discharge Thermal Storage Without Thermal Storage With Thermal Storage Hour

39 Thermal Storage With Enthalpy Wheel Thermal Storage With Enthalpy Wheel Cooling Coil Load Constant Chiller Production + Charge - Discharge Charging Rate Discharge Rate Hour MBH MBH MBH MBH MBH Total Load Stored Ton-hr Stored Average FoM 90% Tons Delta T 15 Max Tank Volume (gal) 197,868 Load Factor 0.60 Tank Volume (ft^3) 26,455

40 Design Day Cooling Load Profile Discharge Thermal Storage Without Thermal Storage Load (Tons) Charge Thermal Storage With Thermal Storage Hour

41 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix F Enthalpy Wheel

42 Enthalpy Wheel Summer Conditions: Outdoor Air: T DB = 93 F W OA = gr/lb Return Air Conditions: T DB = 82 F W EA = 70 gr/lb Wheel Effectiveness is 80% T T T W W W, = TDBOA, ε ( T DBSA DBSA, DBSA, SA SA SA = 93 F 0.80 (93 F 82 F) = 84.2 F = W ε ( W OA OA W DBOA, EA T DBEA, gr gr gr = ( ) lb lb lb gr = lb ) ) Winter Conditions: Outdoor Air: T DB = 11 F W OA = 0.4 gr/lb Return Air Conditions: T DB = 78 F W EA = 70 gr/lb Wheel Effectiveness is 80% T T T W W W, = TDBOA, ε ( T DBSA DBSA, DBSA, SA SA SA = 32 F (78 F 32 F) = 64.6 F = W + ε ( W OA EA W DBEA, OA T DBOA, gr gr gr = ( ) lb lb lb gr = lb ) )

43 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix G Spark Gap Calculation

44 Spark Gap Location Monmouth County, New Jersey Electric $ $/kwh Natural Gas $7.95 $/MMBtu Electric $ kwh Btu $24.44 kwh Btu 1 MMBTU = MMBTU Electric $24.44 $/MMBTU Natural Gas $7.95 $/MMBTU Spark Gap $16.49 $/MMBTU

45 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix H Emissions

46 Emissions Boiler Emissions Natural Gas Boiler Emissions Fuel Used NO x SO x CO 2 Hydrocarbons ft^3 lbm lbm lbm lbm Conventional 6,613, NA System 1 262, NA System 2 2,875, NA System 3 560, NA System NA System 5 753, NA System 6 335, NA CHP CHP Emissions from Hess Specifications CHP System Electrical Emissions Electric Used Nox CO Nox CO CO2 bhp g/hr g/hr lbm lbm lbm System 1 1, ,776,331 System ,850,887 System ,850,887 System ,776,331 System ,850,887 System ,850,887

47 Utility Grid Emissions Emissions Produced by JCP&L and the Nationwide Average lbm Pollutant j /kwh Jersey Central Power and Light (JCP&L) Fuel % Energy Mix Particulates SO 2 /kwh NO x /kwh CO 2 /kwh Coal E E E E-01 Oil E E E E-02 Nat. Gas E E E E-01 Nuclear E E E E+00 Hydro/Wind E E E E+00 Totals E E E E-01 USA Average E E E E+00 Equivalent Electric Emissions if the power produced by the CHP system was produced by the Utility provider. Electrical Emissions Electric Used Particulates SO2 Nox CO2 kwh lbm lbm lbm lbm Conventional 3,253,260 1,252 14,769 9,531 3,225,463 Conventional Nationwide 3,253,260 2,092 24,540 14,444 4,490,485 System 1 9,855,000 3,792 44,738 28,873 9,770,794 Equivalent Electricity Generated CHP System 2 6,570,000 2,528 29,825 19,249 6,513,863 System 3 6,570,000 2,528 29,825 19,249 6,513,863 System 4 9,855,000 3,792 44,738 28,873 9,770,794 System 5 6,570,000 2,528 29,825 19,249 6,513,863 System 6 6,570,000 2,528 29,825 19,249 6,513,863

48 CHP Combined Heat and Power compared with Conventional Design Actual Emissions Produced Total Emissions Calculated from Electricity and Natural Gas Total Particulates SO2 NOx CO CO2 Thousand Btu lbm lbm lbm lbm lbm Conventional 45,269,258 1,318 14,769 9,855 NA 3,226,746 USA Average 45,269,258 2,158 24,540 14,768 NA 4,491,768 System 1 100,915, ,593 18,371 11,776,382 System 2 69,977, ,194 12,771 7,851,445 System 3 67,661, ,081 12,322 7,850,996 System 4 100,652, ,580 18,320 11,776,331 System 5 67,854, ,090 12,359 7,851,033 System 6 67,436, ,070 12,278 7,850,952 Total amount of emissions produced along with the MWh produced Total Emissions Calculated from Electricity and Natural Gas Total Particulates SO 2 NO X CO CO 2 MWh lbm lbm lbm lbm lbm Conventional 13,267 1,318 14,769 9,855 NA 3,226,746 USA Average 13,267 2,158 24,540 14,768 NA 4,491,768 System 1 29, ,593 18,371 11,776,382 System 2 20, ,194 12,771 7,851,445 System 3 19, ,081 12,322 7,850,996 System 4 29, ,580 18,320 11,776,331 System 5 19, ,090 12,359 7,851,033 System 6 19, ,070 12,278 7,850,952 CHP Normalized to show the emissions per MWh of used Total Emissions Calculated from Electricity and Natural Gas per MWh Total Particulates SO 2 NO X CO CO 2 MWh lbm/10 3 lbm/10 3 lbm/10 3 lbm/10 3 lbm Conventional , NA 243 USA Average , , NA 339 System System System System System System CHP

49 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix I Acoustical

50 Acoustics The equations below give the method of finding the A-weighted sound pressure level. The first step is to A-weight the sound pressure levels to make them all on equal loudness levels. For instance, sound pressure levels at the frequency of 125 Hz need to be 16.1 db higher to have the same loudness as a 1000 Hz noise at the same level. After the levels are all A-weighted, the following equation is used to find the combined A-weighted level. ( L P ) i 10 ( L ) = 10logΣ(10 ) P total The A-weighted sound pressure levels were give for the Hess micro-generator, but the octave band sound pressure levels for the were not given. After consulting with the acoustic professor, Courtney Burroughs, it was determined that a typical gasoline engine could be used for the analysis. The octave band sound pressure levels were found for the Hess generator by taking the gasoline engine octave band sound pressure levels and altering them to result in the A-weighted sound pressure level that was given with the turbine. Octave Bands Gas Engine L P (db) i A- Weighted Levels A- weighting Combined A-weighted Level = 88 db The new octave band levels were determined and are represented in the table below. Furthermore, the table includes the sound pressure levels that were found when the system included the sound attenuation.

51 Without Sound Attenuation Sound Attenuation Gas Microgenerator Microgenerator Octave Bands Engine L P (db) L P (db) A-weighted levels L P (db) A-weighting levels Combined A- weighted Level = 80 db 71 db

52 Jason Jones Mechanical Option Senior Thesis Report Spring 2005 Appendix J Life Cycle Cost

53 Base Case Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast Conventional System Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $659,151 $659,151 n/a n/a n/a $271,322 $81,351 $15,000 $659,151 $659,151 2 $271, % $218,896 $81, % $66,488 $15,000 $13, $298,990 $958,141 n/a n/a 3 $271, % $200,342 $81, % $62,401 $15,000 $12, $275,700 $1,233,841 n/a n/a 4 $271, % $187,740 $81, % $59,349 $15,000 $12, $259,430 $1,493,271 n/a n/a 5 $271, % $182,916 $81, % $55,688 $15,000 $11, $250,357 $1,743,628 n/a n/a 6 $271, % $177,065 $81, % $52,385 $15,000 $11, $240,643 $1,984,271 n/a n/a 7 $271, % $171,744 $81, % $50,441 $15,000 $10, $232,846 $2,217,117 n/a n/a 8 $271, % $169,270 $81, % $49,024 $15,000 $10, $228,447 $2,445,563 n/a n/a 9 Overhaul $271, % $165,795 $81, % $47,752 $15,000 $9, $223,216 $2,668,780 n/a n/a 10 $271, % $161,126 $81, % $46,311 $15,000 $9, $216,646 $2,885,425 n/a n/a 11 $271, % $155,437 $81, % $44,730 $15,000 $8, $208,937 $3,094,362 n/a n/a 12 $271, % $149,802 $81, % $42,708 $15,000 $8, $200,863 $3,295,225 n/a n/a 13 $271, % $143,365 $81, % $40,674 $15,000 $7, $191,994 $3,487,219 n/a n/a 14 $271, % $136,539 $81, % $38,639 $15,000 $7, $182,754 $3,669,973 n/a n/a 15 $271, % $129,931 $81, % $36,613 $15,000 $7, $173,759 $3,843,732 n/a n/a 16 Replace $271, % $124,145 $81, % $34,914 $15,000 $6, $165,931 $4,009,662 n/a n/a $0 Overhaul $0 Residual $659,151 $659,151 $4,069,830 $2,474,115 $1,220,265 $728,116 $225,000 $148,281 $4,009,662 $4,009,662 n/a n/a

54 CHP 1 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 1 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $2,068,989 $2,068,989 n/a n/a n/a ($596,375) $802,276 $25,000 $2,068,989 $2,068,989 ($1,409,838) 2 ($596,375) -4.92% ($481,142) $802, % $655,700 $25,000 $22, $197,234 $2,266,223 ($1,308,082) 3 ($596,375) -3.90% ($440,358) $802, % $615,390 $25,000 $21, $196,628 $2,462,850 ($1,229,010) 4 ($596,375) -1.60% ($412,659) $802, % $585,299 $25,000 $20, $193,207 $2,656,057 ($1,162,786) 5 ($596,375) 2.30% ($402,057) $802, % $549,186 $25,000 $19, $166,717 $2,822,775 ($1,079,147) 6 ($596,375) 1.64% ($389,194) $802, % $516,612 $25,000 $18, $146,073 $2,968,848 ($984,577) 7 ($596,375) 1.85% ($377,500) $802, % $497,448 $25,000 $17, $137,715 $3,106,563 ($889,447) 8 ($596,375) 3.49% ($372,061) $802, % $483,468 $25,000 $16, $128,328 $3,234,891 ($789,328) 9 Overhaul ($596,375) 2.84% ($364,424) $802, % $470,925 $25,000 $16, $122,616 $3,357,507 ($688,727) 10 ($596,375) 2.04% ($354,160) $802, % $456,718 $25,000 $15, $117,907 $3,475,413 ($589,988) 11 ($596,375) 1.29% ($341,655) $802, % $441,120 $25,000 $14, $114,082 $3,589,495 ($495,133) 12 ($596,375) 1.19% ($329,271) $802, % $421,179 $25,000 $13, $105,829 $3,695,324 ($400,100) 13 ($596,375) 0.49% ($315,122) $802, % $401,123 $25,000 $13, $99,259 $3,794,583 ($307,364) 14 ($596,375) 0.00% ($300,116) $802, % $381,056 $25,000 $12, $93,566 $3,888,149 ($218,177) 15 ($596,375) -0.08% ($285,594) $802, % $361,071 $25,000 $12, $87,502 $3,975,651 ($131,920) 16 Replace ($596,375) 0.32% ($272,876) $802, % $344,315 $25,000 $11, $82,892 $4,058,543 ($48,881) $0 Overhaul $0 Residual $2,068,989 $2,068,989 ($8,945,625) ($5,438,189) ######### $7,180,609 $375,000 $247,135 $4,058,543 $4,058,543 n/a >0.05

55 CHP 2 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 2 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $868,989 $868,989 n/a n/a n/a ($322,406) $556,322 $20,000 $868,989 $868,989 ($209,838) 2 ($322,406) -4.92% ($260,110) $556, % $454,682 $20,000 $18, $212,713 $1,081,702 ($123,561) 3 ($322,406) -3.90% ($238,062) $556, % $426,729 $20,000 $17, $205,944 $1,287,646 ($53,805) 4 ($322,406) -1.60% ($223,088) $556, % $405,864 $20,000 $16, $199,230 $1,486,876 $6, ($322,406) 2.30% ($217,356) $556, % $380,822 $20,000 $15, $179,137 $1,666,013 $77,615 6 ($322,406) 1.64% ($210,402) $556, % $358,234 $20,000 $14, $162,756 $1,828,769 $155,502 7 ($322,406) 1.85% ($204,080) $556, % $344,945 $20,000 $14, $155,079 $1,983,848 $233,269 8 ($322,406) 3.49% ($201,140) $556, % $335,251 $20,000 $13, $147,648 $2,131,496 $314,067 9 Overhaul ($322,406) 2.84% ($197,011) $556, % $326,553 $20,000 $12, $142,434 $2,273,930 $394, ($322,406) 2.04% ($191,462) $556, % $316,702 $20,000 $12, $137,518 $2,411,449 $473, ($322,406) 1.29% ($184,702) $556, % $305,886 $20,000 $11, $132,877 $2,544,326 $550, ($322,406) 1.19% ($178,007) $556, % $292,058 $20,000 $11, $125,188 $2,669,513 $625, ($322,406) 0.49% ($170,358) $556, % $278,151 $20,000 $10, $118,399 $2,787,912 $699, ($322,406) 0.00% ($162,246) $556, % $264,235 $20,000 $10, $112,091 $2,900,003 $769, ($322,406) -0.08% ($154,395) $556, % $250,377 $20,000 $9, $105,603 $3,005,606 $838, Replace ($322,406) 0.32% ($147,519) $556, % $238,758 $20,000 $9, $100,401 $3,106,007 $903,655 $0 Overhaul $0 Residual $868,989 $868,989 ($4,836,090) ($2,939,937) $8,344,830 $4,979,247 $300,000 $197,708 $3,106,007 $3,106,007 n/a 3.9

56 CHP 3 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 3 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $909,096 $909,096 n/a n/a n/a ($316,310) $537,911 $20,000 $909,096 $909,096 ($249,945) 2 ($316,310) -4.92% ($255,192) $537, % $439,634 $20,000 $18, $202,583 $1,111,679 ($153,538) 3 ($316,310) -3.90% ($233,561) $537, % $412,607 $20,000 $17, $196,323 $1,308,003 ($74,162) 4 ($316,310) -1.60% ($218,870) $537, % $392,432 $20,000 $16, $190,016 $1,498,019 ($4,748) 5 ($316,310) 2.30% ($213,246) $537, % $368,219 $20,000 $15, $170,643 $1,668,663 $74, ($316,310) 1.64% ($206,424) $537, % $346,379 $20,000 $14, $154,879 $1,823,542 $160,729 7 ($316,310) 1.85% ($200,221) $537, % $333,530 $20,000 $14, $147,522 $1,971,064 $246,053 8 ($316,310) 3.49% ($197,337) $537, % $324,156 $20,000 $13, $140,356 $2,111,420 $334,143 9 Overhaul ($316,310) 2.84% ($193,286) $537, % $315,746 $20,000 $12, $135,352 $2,246,772 $422, ($316,310) 2.04% ($187,842) $537, % $306,221 $20,000 $12, $130,657 $2,377,430 $507, ($316,310) 1.29% ($181,210) $537, % $295,763 $20,000 $11, $126,246 $2,503,676 $590, ($316,310) 1.19% ($174,641) $537, % $282,393 $20,000 $11, $118,888 $2,622,564 $672, ($316,310) 0.49% ($167,137) $537, % $268,945 $20,000 $10, $112,415 $2,734,979 $752, ($316,310) 0.00% ($159,178) $537, % $255,491 $20,000 $10, $106,414 $2,841,393 $828, ($316,310) -0.08% ($151,475) $537, % $242,091 $20,000 $9, $100,236 $2,941,629 $902, Replace ($316,310) 0.32% ($144,730) $537, % $230,857 $20,000 $9, $95,289 $3,036,918 $972,744 $0 Overhaul $0 Residual $909,096 $909,096 ($4,744,650) ($2,884,349) $8,068,665 $4,814,463 $300,000 $197,708 $3,036,918 $3,036,918 n/a 4.1

57 CHP 4 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 4 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $1,851,181 $1,851,181 n/a n/a n/a ($598,201) $800,187 $25,000 $1,851,181 $1,851,181 ($1,192,030) 2 ($598,201) -4.92% ($482,615) $800, % $653,992 $25,000 $22, $194,053 $2,045,234 ($1,087,094) 3 ($598,201) -3.90% ($441,706) $800, % $613,787 $25,000 $21, $193,677 $2,238,911 ($1,005,070) 4 ($598,201) -1.60% ($413,923) $800, % $583,775 $25,000 $20, $190,419 $2,429,331 ($936,059) 5 ($598,201) 2.30% ($403,288) $800, % $547,756 $25,000 $19, $164,056 $2,593,387 ($849,759) 6 ($598,201) 1.64% ($390,386) $800, % $515,267 $25,000 $18, $143,536 $2,736,923 ($752,653) 7 ($598,201) 1.85% ($378,656) $800, % $496,153 $25,000 $17, $135,264 $2,872,188 ($655,071) 8 ($598,201) 3.49% ($373,201) $800, % $482,209 $25,000 $16, $125,930 $2,998,117 ($552,554) 9 Overhaul ($598,201) 2.84% ($365,540) $800, % $469,699 $25,000 $16, $120,274 $3,118,391 ($449,612) 10 ($598,201) 2.04% ($355,244) $800, % $455,529 $25,000 $15, $115,633 $3,234,024 ($348,599) 11 ($598,201) 1.29% ($342,701) $800, % $439,971 $25,000 $14, $111,887 $3,345,911 ($251,549) 12 ($598,201) 1.19% ($330,279) $800, % $420,082 $25,000 $13, $103,724 $3,449,635 ($154,411) 13 ($598,201) 0.49% ($316,087) $800, % $400,078 $25,000 $13, $97,249 $3,546,885 ($59,666) 14 ($598,201) 0.00% ($301,035) $800, % $380,064 $25,000 $12, $91,655 $3,638,540 $31, ($598,201) -0.08% ($286,468) $800, % $360,130 $25,000 $12, $85,688 $3,724,227 $119, Replace ($598,201) 0.32% ($273,711) $800, % $343,418 $25,000 $11, $81,160 $3,805,387 $204,275 $0 Overhaul $0 Residual $1,851,181 $1,851,181 ($8,973,015) ($5,454,840) ######### $7,161,911 $375,000 $247,135 $3,805,387 $3,805,387 n/a 13.7

58 CHP 5 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 5 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $1,493,294 $1,493,294 n/a n/a n/a ($324,232) $539,444 $20,000 $1,493,294 $1,493,294 ($834,143) 2 ($324,232) -4.92% ($261,583) $539, % $440,887 $20,000 $18, $197,445 $1,690,739 ($732,598) 3 ($324,232) -3.90% ($239,410) $539, % $413,783 $20,000 $17, $191,650 $1,882,389 ($648,548) 4 ($324,232) -1.60% ($224,351) $539, % $393,550 $20,000 $16, $185,653 $2,068,042 ($574,771) 5 ($324,232) 2.30% ($218,587) $539, % $369,268 $20,000 $15, $166,352 $2,234,394 ($490,766) 6 ($324,232) 1.64% ($211,594) $539, % $347,366 $20,000 $14, $150,696 $2,385,090 ($400,820) 7 ($324,232) 1.85% ($205,236) $539, % $334,480 $20,000 $14, $143,458 $2,528,548 ($311,432) 8 ($324,232) 3.49% ($202,279) $539, % $325,080 $20,000 $13, $136,338 $2,664,886 ($219,323) 9 Overhaul ($324,232) 2.84% ($198,127) $539, % $316,646 $20,000 $12, $131,411 $2,796,298 ($127,518) 10 ($324,232) 2.04% ($192,546) $539, % $307,094 $20,000 $12, $126,826 $2,923,123 ($37,698) 11 ($324,232) 1.29% ($185,748) $539, % $296,605 $20,000 $11, $122,551 $3,045,674 $48, ($324,232) 1.19% ($179,015) $539, % $283,197 $20,000 $11, $115,319 $3,160,993 $134, ($324,232) 0.49% ($171,323) $539, % $269,712 $20,000 $10, $108,995 $3,269,988 $217, ($324,232) 0.00% ($163,165) $539, % $256,219 $20,000 $10, $103,156 $3,373,144 $296, ($324,232) -0.08% ($155,269) $539, % $242,781 $20,000 $9, $97,132 $3,470,276 $373, Replace ($324,232) 0.32% ($148,355) $539, % $231,514 $20,000 $9, $92,322 $3,562,598 $447,064 $0 Overhaul $0 Residual $1,493,294 $1,493,294 ($4,863,480) ($2,956,588) $8,091,660 $4,828,184 $300,000 $197,708 $3,562,598 $3,562,598 n/a 10.4

59 CHP 6 Analysis Month/Year: 4/2004 Years of Project Service: 15 FEMP Fiscal Year: 2004 DOE Region: Northeast System 6 Yrs before "On-Line": 1 Years in Analysis Period: 16 Disc. Rate: 5.0% Analysis Sector: Commercial NON-ANNUAL RECURRING COSTS ELECTRIC COSTS NATURAL GAS COSTS ANNUAL TOTAL COSTS CUMULATIVE RECURRING COSTS COSTS SAVINGS Payback Investment-Related Costs Operations-Related Costs Annual Electric Discounted Annual Nat Gas Discounted Annual Discounted Discounted Discounted Discounted (e.g., 1st cost, replacement, residual) (e.g., non-annual maintenance) Recurring Differential Electric Recurring Differential Nat Gas Recurring Recurring Total Cumulative Cumulative Discounted Year Description Discounted Description Discounted Electric Escalation w/fuel Esc. Nat Gas Escalation w/fuel Esc. (e.g., maintenance) Year Costs Costs Savings Payback # of Cost Constant $ PV $ of Cost Constant $ PV $ Constant $ % PV $ Constant $ % PV $ Constant $ PV $ Date PV $ PV $ PV $ yrs 0 First Cost $1,516,419 $1,516,419 n/a n/a n/a ($323,127) $536,122 $20,000 $1,516,419 $1,516,419 ($857,268) 2 ($323,127) -4.92% ($260,691) $536, % $438,172 $20,000 $18, $195,621 $1,712,040 ($753,900) 3 ($323,127) -3.90% ($238,594) $536, % $411,235 $20,000 $17, $189,918 $1,901,958 ($668,117) 4 ($323,127) -1.60% ($223,587) $536, % $391,127 $20,000 $16, $183,994 $2,085,952 ($592,681) 5 ($323,127) 2.30% ($217,842) $536, % $366,994 $20,000 $15, $164,823 $2,250,775 ($507,147) 6 ($323,127) 1.64% ($210,873) $536, % $345,227 $20,000 $14, $149,278 $2,400,054 ($415,783) 7 ($323,127) 1.85% ($204,536) $536, % $332,420 $20,000 $14, $142,098 $2,542,151 ($325,035) 8 ($323,127) 3.49% ($201,590) $536, % $323,078 $20,000 $13, $135,025 $2,677,177 ($231,613) 9 Overhaul ($323,127) 2.84% ($197,452) $536, % $314,696 $20,000 $12, $130,137 $2,807,313 ($138,533) 10 ($323,127) 2.04% ($191,890) $536, % $305,203 $20,000 $12, $125,591 $2,932,904 ($47,478) 11 ($323,127) 1.29% ($185,115) $536, % $294,779 $20,000 $11, $121,357 $3,054,261 $40, ($323,127) 1.19% ($178,405) $536, % $281,453 $20,000 $11, $114,185 $3,168,446 $126, ($323,127) 0.49% ($170,739) $536, % $268,051 $20,000 $10, $107,918 $3,276,365 $210, ($323,127) 0.00% ($162,609) $536, % $254,641 $20,000 $10, $102,134 $3,378,498 $291, ($323,127) -0.08% ($154,740) $536, % $241,286 $20,000 $9, $96,166 $3,474,665 $369, Replace ($323,127) 0.32% ($147,849) $536, % $230,089 $20,000 $9, $91,402 $3,566,067 $443,596 $0 Overhaul $0 Residual $1,516,419 $1,516,419 ($4,846,905) ($2,946,511) $8,041,830 $4,798,451 $300,000 $197,708 $3,566,067 $3,566,067 n/a 10.5

60 Life-Cycle Costs Summary Glazing Selection Example Analysis Saving Adjusted -to- Internal One-Time Costs Total Utility Maintenance Total Total Net Simple Discnt'd Investment Operations Invest Rate-of- 1st year LCC 1st year Undisc LCC LCC 1st year LCC Undisc LCC LCC Savings Payback Payback Related Related Ratio Return Case Description $ PV $ $ PV $ PV $ $ PV $ PV $ PV $ NS yrs yrs PV $ PV $ SIR AIRR Life-Cycle COSTS Base Conventional System $659,151 $659,151 $352,673 $4,910,860 $3,202,231 $15,000 $148,281 $5,795,011 $4,009,662 n/a n/a n/a $659,151 $3,350,511 n/a n/a CHP 1 System 1 $2,068,989 $2,068,989 $205,901 $2,599,546 $1,742,420 $25,000 $247,135 $5,043,535 $4,058,543 n/a n/a n/a $2,068,989 $1,989,554 n/a n/a CHP 2 System 2 ** $868,989 $868,989 $233,916 $3,079,125 $2,039,310 $20,000 $197,708 $4,248,114 $3,106,007 n/a n/a n/a $868,989 $2,237,018 n/a n/a CHP 3 System 3 * $909,096 $909,096 $221,601 $2,913,161 $1,930,114 $20,000 $197,708 $4,122,257 $3,036,918 n/a n/a n/a $909,096 $2,127,822 n/a n/a CHP 4 System 4 $1,851,181 $1,851,181 $201,986 $2,545,451 $1,707,072 $25,000 $247,135 $4,771,632 $3,805,387 n/a n/a n/a $1,851,181 $1,954,206 n/a n/a CHP 5 System 5 $1,493,294 $1,493,294 $215,212 $2,823,131 $1,871,597 $20,000 $197,708 $4,616,425 $3,562,598 n/a n/a n/a $1,493,294 $2,069,304 n/a n/a CHP 6 System 6 $1,516,419 $1,516,419 $212,995 $2,793,256 $1,851,940 $20,000 $197,708 $4,609,675 $3,566,067 n/a n/a n/a $1,516,419 $2,049,648 n/a n/a * alternative with least life-cycle cost ** alternative with most rapid simple payback Life-Cycle SAVINGS (negative entries indicate increased costs) CHP 1 System 1 ($1,409,838) ($1,409,838) $146,772 $2,311,314 $1,459,811 ($10,000) ($98,854) $751,476 ($48,881) ($48,881) 9.6 >0.05 $1,409,838 $1,360, % CHP 2 System 2 ** ($209,838) ($209,838) $118,757 $1,831,736 $1,162,920 ($5,000) ($49,427) $1,546,898 $903,655 $903, $209,838 $1,113, % ** CHP 3 System 3 * ($249,945) ($249,945) $131,072 $1,997,699 $1,272,116 ($5,000) ($49,427) $1,672,754 $972,744 $972, $249,945 $1,222, % * CHP 4 System 4 ($1,192,030) ($1,192,030) $150,687 $2,365,409 $1,495,159 ($10,000) ($98,854) $1,023,379 $204,275 $204, $1,192,030 $1,396, % CHP 5 System 5 ($834,143) ($834,143) $137,461 $2,087,729 $1,330,634 ($5,000) ($49,427) $1,178,586 $447,064 $447, $834,143 $1,281, % CHP 6 System 6 ($857,268) ($857,268) $139,678 $2,117,604 $1,350,291 ($5,000) ($49,427) $1,185,336 $443,596 $443, $857,268 $1,300, % * LCC Choice ** Simple Payback choice LCCa choice vs Simple Payback choice ($40,107) ($40,107) $12,315 $165,963 $109,196 $125,856 $69,089 $69,089 Analysis Assumptions: DOE/FEMP Fiscal Year 2004 Real Discount Rate for this Analysis 5.0% Number of Analysis Years 16 # of Years before Project Occupancy or Opration 1 DOE Fuel Price Escalation Region 1 (Northeast) Analysis Sector 2 (Commercial)