beecher falls

Rev 0.0

MARCH, 2012

“This publication is the result of tax-supported funding from the USDA Rural Development, and private foundation funding from the Neil and Louise Tillotson

Foundation. The document is not copyrightable. It may be reprinted with the customary crediting of the sources”

METER AND PRESSURE REGULATING STATION,

COMBINED HEAT AND POWER,

MARKET STUDY ANALYSIS

for

NORTHERN COMMUNITY INVESTMENT CORPORATION

off the pipeline facilities of

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

in

BEECHER FALLS, VT

prepared by

NORTHSTAR INDUSTRIES, L.L.C.

northstarind.com

126 Merrimack Street,

Methuen, MA 01844

978.975.5500

SECTION III: CAMOIN ASSOCIATES: MARKET STUDY ANALYSIS

TABLE OF CONTENTS SECTION I: NORTHSTAR INDUSTRIES: METERING & REGULATING STATION

1.0 EXECUTIVE SUMMARY ................................................................................................................................ 1

2.0 DESIGN BASELINE AND CRITERIA ........................................................................................................... 2 2.1 DESIGN CRIITERIA................................................................................................................................... 2 2.2 CODES AND STANDARDS ...................................................................................................................... 3 2.3 BASE DEISGN ............................................................................................................................................ 4

2.3.1 Mechanical Systems ............................................................................................................................ 4 2.3.2 Civil Structural and Architectural ....................................................................................................... 6 2.3.3 Electrical ............................................................................................................................................. 7 2.3.4 Communications .................................................................................................................................. 7 2.3.5 PNGTS RTU I/O List ......................................................................................................................... 10 2.3.6 Beecher Falls RTU I/O List ............................................................................................................... 11 2.3.7 Documentaion ................................................................................................................................... 12

3.0 STATION OPERATION ................................................................................................................................. 13

4.0 DESIGN CALCULATION ............................................................................................................................. 15 4.1 VELOCITY ................................................................................................................................................ 15 4.2 DESIGN PRESSURE................................................................................................................................. 16 4.3 HOOP STRESS .......................................................................................................................................... 17 4.4 PREHEAT .................................................................................................................................................. 18

5.0 SCOPE AND COST ......................................................................................................................................... 19 5.1 SCOPE OF WORK .................................................................................................................................... 19 5.2 COST ......................................................................................................................................................... 20

6.0 SCHEDULE ...................................................................................................................................................... 21

7.0 PRELIMINARY PROJECT DRAWINGS .................................................................................................... 22 SECTION II: ESSEX PARTNERSHIP: COMBINED HEAT AND POWER

8.0 COMBINED HEAT AND POWER ............................................................................................................... 23

9.0 STUDY SITE .................................................................................................................................................... 24 9.1 EXISTING CONDITIONS ........................................................................................................................ 24 9.2 INITIAL CONSTRAINTS ANALYSIS .................................................................................................... 27

10.0 PRELIMINARY PROJECT CONFIGURATION & BUILD OUT ........................................................ 29

11.0 PRELIMINARY EQUIPMENT SELECTION AND DESIGN BASIS ................................................... 30

12.0 REGULATORY ANALYSIS ...................................................................................................................... 32 12.1 REGULATION REQUIREMENTS .......................................................................................................... 32 12.2 PRELIMINARY REGULATORY TIMELINE & BUDGET ESTIMATE ................................................ 36

13.0 PRELIMINARY OPERATIONAL MODELS .......................................................................................... 37 13.1 STAFFING REQUIREMENTS ................................................................................................................. 37

13.2 ENVIRONMENTAL COMPLIANCE APPROACH ................................................................................ 38

14.0 PRELIMINARY ECONOMIC ANALYSIS .............................................................................................. 39 14.1 ECONOMIC FEASIBILITY MODEL DESCRIPTION ............................................................................ 39 14.2 MODEL LIMITATIONS ........................................................................................................................... 39 14.3 KEY INPUTS ............................................................................................................................................. 40 14.4 CASH ON CASH RESULTS ..................................................................................................................... 41 14.5 DEBT LEVERED RESULTS .................................................................................................................... 44

15.0 CONCLUSIONS ........................................................................................................................................... 48 16.0 APPENDICES………………………………………………………………………………………………

PNGTS METERING AND REGULATING STATION, AND

COMBINED HEAT AND POWER NORTHERN COMMUNITY INVESTMENT CORPORATION

Page 1

1.0 EXECUTIVE SUMMARY This Rev 0.0 Preliminary Engineering document outlines a design for a natural gas metering and pressure regulating station to be located in Beecher Falls, Vt. The proposed station and associated pipeline lateral will supply natural gas to a proposed Energy Park in Beecher Falls, Vt. from the Portland Natural Gas Transmission System (PNGTS). The report also describes work performed to evaluate potential options for siting and constructing a Combine Heat and Power (CHP) facility that would provide energy (in the form of electricity and steam or hot water) to tenants of the Energy Park. A Market Analysis is also being conducted for the site, but the results of that analysis are not yet complete, and therefore it is not reflected at the current time in this Rev 1.0 report. The natural gas station will be installed on a developed site near the PNGTS pipeline tap location. Northstar Industries, L.L.C. proposes to outfit a two room pre-cast concrete building with all of the equipment necessary to provide custody transfer quality gas measurement, preheating and pressure regulation. The facility will be designed to reduce the delivery pressure from the typical PNGTS operating level of 1,100 - 1,440 psig down to 100 psig. The 100 psig pipeline lateral pressure will be further regulated at inlets to companies within the Energy Park to satisfy equipment requirements for each company. The pipeline lateral will consist of an approximately 2,765’ long, direct-buried, 4” diameter coated steel line. There will also be a 150’+/- long crossing of Hall Stream that will require horizontal directional drilling (HDD) along the proposed pipeline route to the Energy Park. The final size of the facility will be determined when the economic analysis and electric generation portions of the study are complete. Based on the results of the economic analysis it appears that a minimum installed capacity of approximately 8 MW electrical demand (in addition to thermal products) with a capacity factor of at least 60% is required for economic viability of the Energy Park. This minimum threshold is sensitive to perturbations in capacity factor – loss of a single typical operating shift by the CHP host would result in an economic penalty. Results suggest that for an Energy Park concept to be viable at the study site, a CHP host with a robust demand will be required.



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____________________________________________________________________ NORTHSTAR INDUSTRIES, L.L.C., 126 Merrimack Street, Methuen, MA 01844 (978) 975-5500 Fax (978) 975-9975

2.0 DESIGN BASELINE AND CRITERIA 2.1 DESIGN CRITERIA Maximum gas flow rate 3.3 MMscfd (137.5 Mscfh) MAOP of the station high-pressure gas piping 1,440 psig MAOP of the lateral pipeline 200 psig Minimum design station inlet gas pressure 1,100 psig Design station outlet gas pressure 100 psig Minimum design station inlet gas temperature 32 F Design station outlet gas temperature 40 F Station piping pressure test range 2,160 psig (+25/-0 psi) Station piping pressure test duration 8 Hours Station piping pressure test medium Water or Nitrogen Lateral piping pressure test range 300 psig (+25/-0 psi) Lateral piping pressure test duration 8 Hours Lateral piping pressure test medium Water or Nitrogen Design temperature for all inside and buried piping components -20 F Design temperature for all above ground outside piping components

-50 F

Station and lateral piping design factor 0.5 Station indoor and buried piping specification API 5L Grade B Station indoor and buried flange specification ASTM A105 Station indoor and buried fitting specification ASTM A234 Above ground outdoor piping specification ASTM A333 Grade 6 Above ground outdoor piping flange specification ASTM A350 Grade LF2 Above ground outdoor piping fitting specification ASTM A420 Grade WPL6 Butt welds 100% NDT Fillet welds 100% NDT



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2.2 CODES AND STANDARDS The primary standards governing this design include:

US DOT 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards, Including All References

IBC 2000, International Building Code 2002 National Electrical Code ASTM A333, Specifications for Seamless and Welded Steel Pipe for Low-

Temperature Service ASTM A420, Standard Specification for Piping Fittings of Wrought Carbon Steel and

Alloy Steel for Low-Temperature Service ASTM A350, Standard Specification for Carbon and Low-Alloy Steel Forgings,

Requiring Notch Toughness Testing for Piping Components ASTM A320, Standard Specification for Alloy Steel Bolting Materials for Low-

Temperature Service ASTM A53, Specifications for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated

Welded and Seamless ASTM A106, Specifications for Seamless Carbon Steel Pipe for High-Temperature

Service API 5L, American Petroleum Institute - Specification for Line Pipe API 6D, American Petroleum Institute - Specification for Pipeline Valves API 1104, American Petroleum Institute - Welding of Pipelines and Related Facilities AGA-XF-0277, American Gas Association - Recommended Practices for

Classification of Gas Utility Areas for Electrical Installations Gas Measurement - Part 8, American Gas Association - Electronic Flow Computers

and Transducers ANSI B109.3, American National Standards Institute – ’92 Rotary-Type Gas

Displacement Meters PNGTS Engineering and Construction Standards PNGTS Approved Welding and Painting Procedures



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2.3 BASE DESIGN 2.3.1 Mechanical Systems Metering The measurement system will consist of a single 2” Instromet 3.5M high pressure rotary meter run with a 2” bypass. The meter run will include an inlet strainer, 2” inlet and outlet block valves, and separate pressure and temperature transmitters for both PNGTS and Beecher Falls. Meter Type Meter Pressure Maximum Flow Rate Minimum Flow Rate

2” Rotary 1,100 psig 312 Mscfh 8.9 Mscfh 2” Rotary 1,440 psig 425 Mscfh 12.1 Mscfh

Minimum flow rates are based upon manufacturer’s published values at +/- 1% accuracy. A flow restricting orifice plate will be installed downstream of the rotary meter to prevent the meter from over-ranging. This plate will be sized to restrict flow through the rotary meter to 90% of its capacity at critical flow conditions. Pressure Control and Overpressure Protection There will be two redundant runs available for pressure control, a primary and a secondary run. Each run will consist of (2) 2” Grove FlexFlo Model 900TE top entry boot style regulators configured in an upstream working monitor, downstream worker arrangement. The station inlet pressure will be reduced down to the 100 psig delivery pressure in (2) stages, and all of the regulators will feature 20% trim for optimal performance. A 4” emergency shutdown (ESD) Becker T0 ball valve with pneumatic actuator and remote temperature sensor will provide tertiary overpressure protection and allow PNGTS to remotely shut in the station. A fire inside the measurement room will also cause the valve to close automatically. When this valve closes due to high temperature, it will remain closed until it is manually reset. A token relief valve will also be included downstream of the ESD valve to relieve any excessive pressure buildup in the dead end pipeline lateral. All block valves will be double block and bleed ball valves with hand-wheel or lever operators. All blow downs, gauges, and sensing lines for each run will be enclosed between the block valves. Regulator

Size Trim

Capacity Regulator Set

Pressure Pipeline Pressure Maximum Flow Rate

2” 20% 100 psig 1,100 psig 383 Mscfh 2” 20% 100 psig 1,440 psig 508 Mscfh



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Maximum flow rates are based upon the use of non-ribbed boots and 20% capacity Cg values. The manufacturer recommends that operating conditions should not exceed approximately 85% of valve capacity at the selected trim level. Gas Preheat System The natural gas heating circuit will include a shell and tube heat exchanger, (2) 100% capacity gas-fired hydronic heaters and (2) 100% capacity circulation pumps. Natural gas will enter one side of the heat exchanger tube bundle at pipeline pressure, while a 50/50 solution of water and propylene glycol will enter the shell from the opposite side. The PNGTS RTU will control a three-way valve via an electronic actuator/positioner to modulate the flow of water/glycol solution through the heat exchanger. As the gas flows through the tubes, it will be heated to the level necessary to maintain a 40 F station outlet temperature. The heaters will be two-stage units, operating to maintain a given water/glycol temperature at their inlets. The heaters will fire up when their inlet water/glycol solution temperature falls below the internal aquastat set point. The two stages can be staggered so that each heater will normally operate on low fire, ramping up to full fire when the demand increases. Backup aquastats will shut the units off on high temperature and will require manual reset if activated. Standard IRI burner controls will provide high and low fuel pressure protection as well as double block and bleed protection. A low water cutoff on each heater will require manual reset. A flow switch will be mounted on the outlet of each heater to provide shutoff protection at low liquid flow. Common trouble contact closures will indicate heater problems and send discrete inputs to the PNGTS RTU. Preheat Design Criteria Minimum gas inlet temperature: 32 F Gas outlet temperature on the discharge of regulation: 40 F Mixture of water/propylene glycol solution: 50% / 50%, by volume Fluid temperature at the inlet of heat exchanger: 180 F Fluid temperature at the discharge of heat exchanger: 150 F Freezing point of the solution: -25 F Flow rate of the solution: 29 gpm System head requirement: 41 ft TDH Required pump motor power: ¾ HP Relief valve setting on the heaters: 125 psig Rupture disc setting on the heat exchanger: 75 psig @ 150F Heat exchanger requirement @ 1,440 psig inlet pressure: 378 MBtu/hr Heating system output (per unit): 405 MBtu/hr



Page 6


2.3.2 Civil/Structural and Architectural Meter Station The pre-cast concrete building will measure approximately 38’ L x 12’ W x 10’ H and will be located on a reinforced concrete foundation. Crushed stone will surround the building. A chain link fence with a 7-foot overall height, including 3 strands of barbed wire on top, will be installed around the facility perimeter. The fence will have (2) 6-foot wide swinging gates for vehicle entry and a single 3-foot wide personnel gate with emergency exit hardware. The building’s high-pressure gas room will be equipped with wall vents and a roof turbine to facilitate ventilation. Explosion proof lighting will be provided. There will be one set of 5’ x 7’ double doors to provide access to the metering and regulating equipment and the heat exchanger. The heater/DAC room will have vents installed to provide adequate combustion air and natural ventilation. A single set of 5’ x 7’ double doors will be provided for access to the heaters and the associated water/glycol solution piping and controls. Adequate general purpose lighting will be provided for the heater/DAC room. All building doors will be equipped with panic exit hardware. Pipeline Lateral The PNGTS tap location and meter station are proposed to be located on what is believed to be property of Charles and Amber Bates. The outlet pipeline will leave the meter station in a northwesterly direction and will travel along the north side of River Road to a point where it is suitable to leave the roadside and head in a northerly direction across property believed to be owned by Ethan Allen where there will be a HDD crossing required under Hall Stream. The pipeline will then turn northwesterly across other properties believed to be owned by Ethan Allen to a point where it crosses under Route 253. Once across the road, the pipeline will continue across other properties believed to be owned by Ethan Allen, cross under an abandoned State of N.H. rail bed and continue across property believed to be owned by Ethan Allen to the propery where the Energy Park is proposed.



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2.3.3 Electrical The electric service to the meter building will be 240 VAC, single phase, 3-wire, 200 Amp. The electric meter will be mounted outside the facility fence on a post to provide the power company with unrestricted access. A site ground grid will integrate the building grounding facilities with the perimeter fence. Separate uninterruptible power supplies (UPS) will be provided for the PNGTS and Beecher Falls 24 VDC systems. Each UPS will supply power to specific instrument and control devices in the event of an outage. A manual transfer switch and weather-tight receptacle will be provided for connection of a portable back-up generator. The electric design for the site will be based upon a hazardous designation (Class 1, Div. I) for the meter room and a non-hazardous designation for the heater/DAC room. Explosion proof or intrinsically safe equipment will be installed in the hazardous areas. Explosion proof lighting and outlets will be installed in the meter room. The water/glycol heaters will be wired with standard non-hazardous fittings and controls. The heaters will require 120 VAC for power. Fluorescent lighting with low-temperature ballasts will be provided in the heater/DAC room. Combustible gas detectors will be installed in both rooms for connection to the PNGTS RTU. The non-hazardous heater/DAC room will contain the electric service entrance at a breaker panel as well as communications facilities, the RTU(s), and the UPS units. All power and controls for the site will be distributed from this room. 2.3.4 Communications It is assumed that PNGTS will utilize satellite communications to relay information back to its SCADA host facility. It is further assumed that Beecher Falls will utilize a land based dedicated data line to integrate its RTU into its proposed control network.



Page 8


Responsibility and Controls Matrices Preliminary Responsibility Matrix: Portland Natural Gas Transmission System (PNGTS) – Beecher Falls (BF)

Item Design Permit Procure Own

Install

Operate Minor Maint.

Major Maint.

PNGTS Tap BF BF BF BF BF PNGTS PNGTS PNGTS

PNGTS Lateral BF BF BF BF BF PNGTS PNGTS PNGTS

PNGTS EGM BF BF BF BF BF PNGTS PNGTS PNGTS PNGTS Communications

BF BF BF BF BFPNGTS PNGTS PNGTS

BF Lateral BF BF BF BF BF BF BF BF

BF EGM BF BF BF BF BF BF BF BF

BF Communications

BF BF BF BF BF BF BF BF

Meter Building BF BF BF BF BF PNGTS PNGTS PNGTS Custody Transfer Metering


Preheat BF BF BF BF BF PNGTS PNGTS PNGTS Pressure Regulation


OPP BF BF BF BF BF PNGTS PNGTS PNGTS

Voice Telephone BF BF BF BF BF PNGTS PNGTS PNGTS

AC Power Feed BF BF BF BF BF PNGTS PNGTS PNGTS Site Development


Notes: 1. Northstar Industries, L.L.C. will provide all design, procurement and installation for all items

designated as Beecher Falls responsibility 2. Minor Maintenance includes valve lubrication and inspection, packing and valve seat

replacement, and repair of all instrumentation including that associated with EGM 3. Major Maintenance includes the purchase of major components for replacement or repair

required in maintaining the facilities including, but not limited to, regulators, meters, valves and other items not normally considered as routine or preventative maintenance

4. PNGTS will perform all minor and major maintenance, and Beecher Falls will be responsible for all of the associated costs as outlined in a separate facilities agreement between the parties



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Preliminary Controls Matrix: Portland Natural Gas Transmission System (PNGTS) – Beecher Falls (BF)

Item Party Meter Pulses PNGTS/BF PIT(s) and TIT(s) PNGTS/BF ESD Control PNGTS ESD Limits PNGTS Heater Control PNGTS Pump Control PNGTS Heater Alarms PNGTS Pump Alarms PNGTS TCV Control PNGTS Gas Detectors PNGTS Intrusion Alarms PNGTS RTU to RTU Modbus Communications PNGTS/BF



Page 10


2.3.5 PNGTS RTU I/O List

FUNCTION TAG NO. SIGNAL RANGE

Analog Inputs Meter Run Gas Pressure PIT-XXX 4 to 20 mA 0 to 2,000 psig Meter Run Gas Temperature TIT-XXX 4 to 20 mA -20 to 120 oF Heat Exchanger Outlet Gas Temperature TIT-XXX 4 to 20 mA -20 to 200 oF Station Outlet Gas Pressure PIT-XXX 4 to 20 mA 0 to 150 psig Station Outlet Gas Temperature TIT-XXX 4 to 20 mA -20 to 120 oF CVD: M&R Room AIT-XXX 4 to 20 mA 0 to 100% LEL CVD: Heater/DAC Room AIT-XXX 4 to 20 mA 0 to 100% LEL

Analog Outputs Temperature Control Valve Output ZVC-XXX 4 to 20 mA 0-100%

Discrete Inputs (0-1) ESD Valve - Closed ZSC-XXX Contact Closure, Dry Not - Closed ESD Valve - Open ZSO-XXX Contact Closure, Dry Not - Open DC Common Alarm JA-XXX Contact Closure, Dry Alarm- Normal AC Power Failure JA-XXX Contact Closure, Dry Normal - Alarm Heater 1 - Common Alarm BA-XXX Contact Closure, Dry Normal - Alarm Heater 2 - Common Alarm BA-XXX Contact Closure, Dry Normal - Alarm Pump 1 Status PBS-XXX Contact Closure, Dry Alarm - Normal Pump 2 Status PBS-XXX Contact Closure, Dry Alarm - Normal Common Intrusion Alarm ISW-XXX Contact Closure, Dry Alarm- Normal

Pulse Inputs

Meter Input FE-XXX Transistor, Isolator TBD

Discrete Outputs Heater 1 On/Off BC-XXX Relay Output On/Off Heater 2 On/Off BC-XXX Relay Output On/Off Pump 1 On/Off PBY-XXX Relay Output On/Off Pump 2 On/Off PBY-XXX Relay Output On/Off ESD Valve Open EYO-XXX Relay Output Not - Open ESD Valve Close EYC-XXX Relay Output Not - Close

Communications Port SCADA Host RS-232 Beecher Falls RTU RS-232 Modbus



Page 11


2.3.6 Beecher Falls RTU I/O List

FUNCTION TAG NO. SIGNAL RANGE Analog Inputs

Meter Run Gas Pressure PIT-XXX 4 to 20 mA 0 to 2,000 psig Meter Run Gas Temperature TIT-XXX 4 to 20 mA -20 to 120 oF

Discrete Inputs (0-1) DC Common JA-XXX Contact Closure, Dry Alarm- Normal AC Power Failure JA-XXX Contact Closure, Dry Normal - Alarm

Pulse Inputs

Meter Input FE-XXX Transistor, Isolator TBD

Communications Port SCADA Host RS-232 PNGTS RTU RS-232 Modbus



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2.3.7 Documentation Upon completion of the project, copies of a Project Data Book containing the following information will be forwarded to PNGTS and Beecher Falls.

DESIGN BASELINE AND CRITERIA PROJECT DRAWINGS DESIGN CALCULATIONS WELDING PROCEDURES AND QUALIFICATIONS TESTING RESULTS EQUIPMENT DOCUMENTATION

Project drawings include the following: Mechanical A Series – Architectural Drawings, Plan and Section Views D Series – Piping and Instrumentation Diagrams F Series – Fabrication Details M Series – Miscellaneous Mechanical Details P Series – Mechanical Plan and Section Views PS Series – Pipe Support Details W Series – Weld Maps Electrical E Series – Electrical, Communications and Controls Plans, Diagrams and Details Civil/Structural C Series – Site Plan S Series – Structural Details



Page 13


3.0 STATION OPERATION To assist in understanding the following Control Philosophy, please refer to the Piping and Instrumentation Diagram located in Section 7.0.

M A 2” Instromet rotary meter will measure all gas flowing to Beecher Falls. Beecher Falls will monitor the PNGTS custody transfer flow calculations and accumulators and will also perform independent flow calculations and accumulations. SCADA host alarms are recommended for flows below or in excess of design limits at both PNGTS and Beecher Falls. PIT The meter run will include pressure-indicating transmitters to measure the gas pressure used by PNGTS and Beecher Falls to convert the actual flow to standard conditions. An additional pressure transmitter will measure the station outlet pressure. This pressure is provided for use in monitoring, control, safety interlock, and alarming in the PNGTS RTU and SCADA host.

TIT The meter run will include temperature-indicating transmitters to measure the gas temperature used by PNGTS and Beecher Falls to convert the actual flow to standard conditions. Additional temperature transmitters will measure the heat exchanger outlet and station outlet temperatures. These temperatures are provided for use in monitoring, control, safety interlock, and alarming in the PNGTS RTU and SCADA host.

Preheat The station heaters and water/glycol solution circulation pumps will be remotely controlled via the PNGTS RTU. Local pushbutton control will also be available for the pumps. Discrete output signals from the PNGTS RTU will be used to start and stop the heaters and pumps. Alarm contacts in the heater controls will send discrete signals to the PNGTS RTU in the event of a heater failure. The station outlet gas temperature will be monitored via a TIT installed in the outlet piping. The TIT will provide a 4-20 mA analog input signal to the PNGTS RTU. Utilizing a proportional-integral-derivative (PID) algorithm, the PNGTS RTU will control the positioner on the 3-way valve in the water/glycol system. A 4-20 mA analog output signal from the PNGTS RTU will be sent to the temperature control valve positioner, and



Page 14


the valve will modulate the flow of water/glycol solution to the station heat exchanger to maintain a constant gas outlet temperature. ESD The emergency shutdown (ESD) valve will include a Becker actuator and will be controlled by solenoid valves. The solenoids will provide remote operation via discrete outputs from the PNGTS RTU to ensure that the Beecher Falls facilities can be isolated from the new metering facility for servicing or in the event of a pressure regulator failure. During normal operations of the pressure regulating facilities, the ESD valve will remain wide open. Limit switches to indicate 0 and 100% open will provide discrete inputs to the PNGTS RTU.



Page 15


4.0 DESIGN CALCULATIONS 4.1 VELOCITY v = QZ/(3.6 Pf A) v = Velocity (fps) Q = Flow rate (Mscfh) Pf = Pressure factor (psia/14.73 psia) A= Area (sq. ft.) Z = Compressibility Nominal Pipe Size

(inch)

Q (Mscfh)

Location Pressure (psig)

Pf A (ft2)

Z v (ft/s)

3/4 1.0 Fuel Gas 100 7.8 0.003 0.983 12 2 1.0 Fuel Gas 0.25 1.0 0.023 0.998 12 2 138 Station Inlet Piping 1,100 75.7 0.021 0.848 21 4 138 Station Outlet Piping 100 7.8 0.080 0.983 60 4 138 Lateral Piping 100 7.8 0.088 0.983 55

Notes: 1. All velocities assume a 60 ºF natural gas temperature



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4.2 DESIGN PRESSURE The following calculation is from 49 CFR 192.105 Design pressure; P = (2St/D)xFxExT P = Design pressure (psig) S = Specified minimum yield strength of pipe (psi) t = Nominal wall thickness (in) D = Nominal outside diameter of the pipe (in) F = Design factor (§192.111) E = Longitudinal joint factor (§192.113) T = Temperature derating factor (§192.115) The longitudinal joint factor as defined by §192.113 is: E = 1.00 The operating temperature is less than 250 degrees Fahrenheit. T = 1.00 The class location as defined by §192.5 is a Class 3: F = 0.5

Nominal Pipe Size

(inch)

Pipe Grade

S (psi)

t (inch)

D (inch)

F E

T P (psig)

3/4 API 5L Grade B/ ASTM A333 Grade 6

35,000 0.154 1.050 0.5 1.00 1.00 5,133

2 API 5L Grade B/ ASTM A333 Grade 6

35,000 0.154 2.375 0.5 1.00 1.00 2.269


35,000 0.218 2.375 0.5 1.00 1.00 3,213


35,000 0.337 4.500 0.5 1.00 1.00 2,621


35,000 0.237 4.500 0.5 1.00 1.00 1,843

All design pressures (P) are greater than the applicable 1,440 psig MAOP of the station and 200 psig MAOP of the pipeline lateral.



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4.3 HOOP STRESS h = Pr/t h = Hoop stress (psi) P = Pipeline pressure (psig) r = Radius of pipe (in) t = Wall thickness (in) MAOP = Maximum Allowable Operating Pressure (psig) SMYS = Specified Minimum Yield Strength (psi) Pressure

(psig)

MAOP

Nominal Pipe Size

(inch)

Pipe Grade

SMYS (psi)

Pipe Diameter

(inch)

t (inch)

h (psi)

% SMYS

1,440 3/4 API 5L Grade B/ ASTM A333 Grade 6

35,000 1.050 0.154 4,909 14.0

1,440 2 API 5L Grade B/ ASTM A333 Grade 6

35,000 2.375 0.218 7,844 22.4


35,000 4.500 0.337 9,614 27.5

200 4 API 5L Grade B/ ASTM A333 Grade 6

35,000 4.500 0.237 1,899 5.4

Pressure

(psig)

Test

Nominal Pipe Size

(inch)

Pipe Grade

SMYS (psi)

Pipe Diameter

(inch)

t (inch)

h (psi)

% SMYS

2,185 3/4 API 5L Grade B/ ASTM A333 Grade 6

35,000 1.050 0.154 7,449 21.3


35,000 2.375 0.218 11,902 34.0


35,000 4.500 0.337 14,588 41.7

300 4 API 5L Grade B/ ASTM A333 Grade 6

35,000 4.500 0.237 2,848 8.1

Notes: 1. All piping at <50% SMYS at applicable test pressure – pneumatic pressure tests allowable



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4.4 PREHEAT Temperature Change Across the Regulators Maximum inlet pressure 1,440 psig Design outlet pressure 100 psig Design minimum inlet temperature 32 F Design station outlet temperature 40 F The natural gas temperature drops roughly 1 F for every (1) atmosphere change in pressure T = {(1440 - 100)/(14.73)} + 40 - 32 = 99 F Temperature Change Across the Heat Exchanger Gas minimum inlet temperature 32 F Gas design outlet temperature 131 F Heat Rate Required Natural gas density 4.446 (10)-2 lbm/ft3 Natural gas specific heat 0.625 Btu/(lbm F) @ 1,440 psi Design maximum flow rate 137.5 Mscfh Q = m Cp T m = 6,113 lbm/hr Q = 378 MBtu/hr Water/Glycol Solution The solution will be 50% water and 50% propylene glycol Water/glycol specific gravity 1.038 Water/glycol specific heat 0.90 Btu/(lbm F) Water/Glycol Flow Rate Required T on the water/glycol side 30 F m = Q/(Cp T) m = 14,015 lbm/hr = 29 gpm Heating System Output 810 MBtu/hr (redundant 100% capacity

heaters) Heating System Solution Flow Rate 29 gpm



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5.0 SCOPE AND COST 5.1 SCOPE OF WORK The project scope includes: Engineering and design of the metering and regulating facility as discussed in this document Procurement of all materials for the metering and regulating facility including: Precast

concrete building with electrical outfitting and lighting, 2” rotary meter, all PNGTS and Beecher Falls pressure and temperature transmitters, heat exchanger, (2) gas detectors, ESD valve, 2” x 3” pressure relief valve, (4) 2” pressure regulators, 2” and 4” block valves, pipe and fittings, pipe supports, (2) Laars 100% capacity hydronic heaters, (2) 100% capacity circulation pumps, 3-way valve with electronic actuator/positioner, PNGTS and Beecher Falls RTU(s) and UPS(s)

Fabrication and assembly of the metering and pressure regulating facilities Welding, NDT and painting of components to PNGTS approved procedures and

specifications Installation of the PNGTS and Beecher Falls instrumentation, RTU(s) and UPS(s) within the

meter building Station and hot tap site development work including initial clearing and grading Installation of concrete foundations, crushed stone site, and perimeter fencing per Northstar’s

site plan (drawing NCI-0001-C2) Transportation and setting/installation of the concrete building and prefabricated piping

components Procurement and installation of field related materials such as interconnecting conduits,

cables and wires and grounding system components Engineering, procurement and installation of ~2,500’ long 4” station outlet lateral piping Engineering, procurement and installation of PNGTS pipeline tap and 2” inlet lateral piping (4) Sets of project data book documentation



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5.2 COST

Description (1),(2) Cost Estimated PNGTS Hot Tap, EGM Building, and Internal Review $150,000 Metering Facility Prefabricated Components (F.O.B. Shop Floor, Methuen, MA)

$850,000

Metering Facility Site Engineering and Development and Building Installation

$360,000

2,350’ Long Direct Buried Pipeline Lateral Engineering and Installation $520,000 ~150’ Long HDD under Hall Stream $160,000 Estimated PNGTS Engineering, Administrative and Miscellaneous Charges $20,000 Project Total $2,060,000 Notes

1. It is assumed that this project will have tax exempt status and that an exemption certificate will be provided during the contract development phase. If this is not the case, applicable usage tax on materials will be billed separately at cost.

2. Cost estimate is +/-15% accuracy level.



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6.0 SCHEDULE

Task Duration Preliminary Engineer Complete Facilities Interconnect Agreement 4 Weeks Procurement of Long Lead Materials 16-20 Weeks Final Design & Permitting 24 Weeks Pre-manufacturing of Components 4 Weeks Site Development & Installation 8 Weeks Project Data Book Delivery 2 Weeks A typical project of the magnitude outlined in this Preliminary Engineering document has project duration of less than 12 months. This schedule requires the execution of task items in conjunction with each other.



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7.0 PRELIMINARY PROJECT DRAWINGS NCI-0001-A1 Rev. 1 Architectural Plan View NCI-0001-D1 Rev. 1 Piping and Instrumentation Diagram NCI-0001-P1 Rev. 1 Piping Plan View NCI-0001-SS4 Rev. 1 Project Overview Map NCI-0001-C14 Rev. 1 Conceptual Site Layout; M&R Station

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EDGE OF ROAD

PNGTS PIPELINE



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8.0 COMBINED HEAT AND POWER The Essex Partnership (Essex) worked in collaboration with the Northstar Industries, Inc. (Northstar) team to assist the Northern Community Investment Corporation (NCIC) in evaluating the feasibility of developing a natural gas fired Combined Heat and Power (CHP) project as an integral component of a proposed “Energy Park” in Beecher Falls, Vermont. Since a host industry for the site has not been identified Essex tailored it’s evaluation to focus on a range of potential CHP installation schemes based on hypothetical load profiles representing a variety of generic industrial hosts, per discussions with NCIC and a revised Scope of Services dated May 9, 2011. Based on this approach, an economic feasibility model was developed that allows NCIC to assess the viability of a range of potential future hosts that could occupy an Energy Park. The Essex Partnership also developed a simplified screening tool that can be used by NCIC to quickly screen other potential CHP projects in the region, including smaller, single host opportunities. Ultimately, CHP’s and other forms of distributed generation can provide significant energy savings, but need to be carefully designed to match the end user’s energy profile. In order for natural gas to contribute to stimulating economic growth, the CHP project must be designed to provide steam, hot water, and electricity at attractive and compelling prices.



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9.0 STUDY SITE The study site is located in the Town of Canaan, situated in the extreme northeast corner of Vermont (Figure 1). The Canada-United States international border is coincident with the site’s northern limits. Immediately adjacent to the site is an Ethan Allen furniture component manufacturing facility. Until recently Ethan Allen employed a significant portion of the local

community. Due to various factors, the workforce at the Beecher Falls facility was reduced, resulting in economic hardships to the local area. The Portland Natural Gas Transmission (PNGT) pipeline is located within 1 mile of the site. 9.1 EXISTING CONDITIONS The study site encompasses approximately 550 acres of undeveloped (primarily forested) land in Beecher Falls, Vermont. Within close proximity to the site are the Canada-United States border, Ethan Allen furniture component manufacturing facility, and the Village of Canaan, Vermont. To the south of the site the Connecticut River forms the boundary between Vermont and New Hampshire (USA). Figure 2 depicts existing conditions at the study site relative to significant nearby features.

^

Figure 1 – Beecher Falls, VT Location Map (study site depicted by red triangle)



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An initial ecological inventory of the project site was conducted in the Fall of 2011 by Mr. Brett Engstrom. Site observations on the presence and relative distribution of distinct natural communities and associated flora and fauna were used to develop a preliminary natural resource inventory of the property. The inventory identified several potential wetland resources not identified by State GIS data layers as well as the occurrence of uncommon natural wetland communities and associated plants. The dominant natural community on the property is Red Spruce-Northern Hardwood Forest; common for the region. Additional, less common natural communities identified on the property

Figure 2 – Existing Conditions



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include several types of wet-mesic forests and seepage forests.1 Vermont does not recognize seepage forests in their natural community classification system and there are no formalized protection standards; however it is likely that they would be treated as wetlands and buffer zones should be anticipated. The location for development of the Energy Park will need to take these resources into consideration; the net result is anticipated to constrain siting options. The ecologist identified a small population of one rare plant (Hayden's Sedge, Carex haydenii) in the seepage woodland in the east corner of property), along with several other uncommon plants. The presence of this species will likely require coordination with the Vermont Nongame and Natural Heritage Program (NNHP) and increase the likelihood that seepage and wet-mesic forests will be regulated as wetlands. This assumption is due in part to the natural community’s function of providing habitat for at least one species of rare hydrophytic vegetation qualifying them for protection under the Vermont Wetland Rules. Results of the ecological inventory suggest significantly more wetlands may be present than indicated by available GIS mapping . The exact location and extent of wetland resources should be determined using field delineation methods outlined by the Army Corps of Engineers. Neither source identified the presence of on-site floodplains. USGS maps include a small stream draining the western third of the property toward the Connecticut River. These resources are discussed in more detail as part of the Initial Constraints Analysis. According to available topographic data from the State of Vermont (20-ft contour intervals), the site aspect is generally southeast facing. Although the topographic data is coarse (20-ft contour intervals), gradients appear to range from moderate to slight, steeper areas appear to be concentrated on the eastern portion of the site. The preliminary alignment of a lateral natural gas line to the site will require the new line to cross Hall’s Stream (a tributary to the Connecticut River) and associated riparian floodplain wetlands which are not located within the study site boundary. The crossing is anticipated to be completed using Horizontal Directional Drilling (HDD); a construction technique which is commonly employed for such installations in order to avoid and minimize potential impacts to sensitive environmental receptors. Construction period protection measures will need to be developed as more detailed natural resource information and protection requirements become available.

1 Seepage forests occur on slight slopes (<15%) and adjacent bottoms where an impervious soil layer (~30 cm deep), such as marine clay or packed till, forces seepage water near the surface (Maine Natural Areas Program).



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9.2 INITIAL CONSTRAINTS ANALYSIS Based on the information outlined above, potential constraints to development include:

The presence, extent and condition of all regulated resources on the site including: o Wetlands and associated setbacks; o Significant natural communities (i.e., seepage forests) o The unnamed stream indicated by GIS mapping; o “Uncommon” plant species (identified by the ecologist);

Existing site topography (particularly steep slopes); and

Availability of contiguous buildable area necessary to support an Energy Park. According to VT GIS data there are also several existing Underground Storage Tanks (USTs) in close proximity to the preliminary lateral gas line alignment. Additional detail on these features would be required to identify and evaluate appropriate avoidance strategies.

Figure 3 illustrates all known and potential constraints to development of the parcel. To be conservative we have assumed that VT ANR would treat seepage habitats and wet-mesic forests (identified by the ecologist) as wetland resources requiring a 50-ft buffer. These natural communities and their associated buffers, are designated as “Potentially Regulated Wetlands” and depicted in red (as opposed to blue) to help distinguish them from wetlands mapped by VT ANR and NH DEC



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Figure 3 – Initial Environmental Constraints. Note that limits of wetland resources are approximate and are intended for planning purposes only. Actual limits would be determined by field delineation.



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10.0 PRELIMINARY PROJECT CONFIGURATION & BUILD-OUT The following assumptions were made in evaluating the potential for a CHP project at the Beecher Falls site:

“Greenfield” development (i.e. currently undeveloped land);

Installation of a new lateral natural gas line (including crossing of Hall’s Stream);

Construction of a new 5-15 MW CHP generating facility and appurtenant works;

Primary function of the CHP facility would be to supply electricity and hot water/steam to currently unidentified host(s), however flexibility to export surplus capacity to the electric grid would be retained, and;

Concurrent, or future development of portions of the property to accommodate CHP host(s)

Because the specific host, or suite of hosts is unknown at this time, we could not develop a detailed project configuration. Rather, we evaluated a range of equipment options reflecting a range of project capacities. The equipment packages evaluated are described in the following section. Typical configurations for these equipment options are shown in the Appendix. To provide an indication of expected land requirements associated with the different options evaluated, Northstar, working with Essex developed preliminary plan-view drawings the show how the various equipment packages might be configured on a generic site. These sketches are shown in the Appendix.



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11.0 PRELIMINARY EQUIPMENT SELECTION AND DESIGN BASIS For the purposes of this study we evaluated installation of five generator sets, in nine configurations, designed to run on natural gas and provide CHP benefits. Typically combined heat and power projects are sized and designed to match the load profile of the host. The goal of this study is to determine the potential benefits of a CHP project at the Beecher Falls site to attract a new host; the potential load profile of which is not currently defined. In order to inform the market strategy for attracting an appropriate host, thresholds for CHP capacity and utilization were evaluated for a variety of installed capacities ranging from 2 MW to 16 MW. Pertinent details on each alternative evaluated are tabulated below.

No. Alternative

No. of

Units

Nominal Electrical Output

(kW)

Total Steam

(tons/hr)

Hot Water from Waste Heat

(tons/hr)

Total Fixed

O&M SC

Total Fixed O&M CHP

1 Caterpillar G3520 1 2,055 2.3 89 626,442 897,854

2 Caterpillar G3520 5 10,275 11.6 445 889,476 1,342,820

3 Solar Mercury 50 1 4,488 6.7 N/A 635,442 950,534

4 Solar Mercury 50 3 13,464 20.1 N/A 763,844 1,072,932

5 Solar Taurus 60 1 5,503 14.7 N/A 692,192 1,024,784

6 Solar Taurus 60 3 16,509 44.0 N/A 904,856 1,265,031

7 Solar Taurus 70 1 7,744 18.0 N/A 692,192 1,024,784

8 Solar Taurus 70 2 15,488 36.0 N/A 715,532 999,016

9 Solar Titan T130 1 14,470 31.7 N/A 530,295 827,970

Notes: 1. Net electrical output at ISO conditions will be approx. 10% lower. 2. Equipment performance based on vendor data. 3. Fixed O&M costs are based on plant availability (annual run hours); values above reflect the minimum

thresholds outlined in the results section. 4. Variable O&M is estimated at $5/MWH (simple cycle) and $7.50 (CHP). 5. Additional detail on each equipment option are provided as attachments.



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Five different equipment packages from Caterpillar/Solar were selected for evaluation based on their record of performance, reliability, and manufacturer support. A total of nine different equipment configurations, consisting of single and multiple unit arrangements based on the five equipment bases were evaluated. Four of the units are combustion turbines, one (Caterpillar G3520) is a reciprocating engine. The reciprocating engine option was selected due to the availability of smaller capacity units than are typically available with combustion turbines. All of the units have the ability to supply electrical and thermal (steam, hot water) products. In the context of CHP, the primary difference between reciprocating engines and combustion turbines is the source of the thermal products. In each case, thermal products are derived from waste heat by-products of electrical generation. However, in a reciprocating engines thermal products are limited to hot water derived from the engine radiator (“jacket water”). Thermal products from combustion turbines are derived from turbine exhaust and can be utilized to produce steam and/or hot water. Additional supporting details obtained from equipment vendors are provided as attachments.



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12.0 REGULATORY ANYLSIS There are several policy and guidance documents and programs related to electrical generation in Vermont. Vermont does not have a prescriptive policy to build in-State generation. The Sustainably Priced Energy Enterprise Development (SPEED) Program and the State Electricity Plan both encourage the development of renewable and or high efficiency generation resources (such as CHP). Forms of encouragement are typically associated with rate structure for project output through Standard Offer rates for specific generating technologies. 12.1 REGULATORY REQUIREMENTS Development of a generation facility and associated gas supply line at the study site will require several regulatory approvals. Assuming the project is engineered to meet the efficiency eligibility thresholds for VT’s SPEED program, we anticipate that the criteria contained in the regulations outlined below will be considered. In some instances a single regulatory proceeding will incorporate criteria included in other regulations (i.e., CPG includes wetland review, etc.).

1. Title 30 Section 248, Certificate of Public Good (CPG) - New and modified electrical generation and transmission facilities must receive a Certificate of Public Good (CPG) from the Vermont Public Service Board (PSB)2. There are no exemptions that would avoid having to secure a CPG for the Beecher Falls project. In order to ensure that a proposed project is economically, environmentally, and socially beneficial to the State’s rate payers the PSB evaluates the proposal based on ten criteria. The ten evaluation categories measure proposed projects against a range of performance criteria that evaluate the economic and environmental impacts of the project on the general good of the state, its ratepayers and communities, natural resources, historic properties and governmental services. Each category has impact thresholds which the PSB uses to gauge the relationship of the proposal to the applicable permitting criterion. The ten categories are listed below.

248(b)(1) Orderly Development of the Region 248(b)(2) Need for Present and Future Demand for Service 248(b)(3) System Stability and Reliability 248(b)(4) Economic Benefit to the State 248(b)(5) Aesthetics, Historic Sites, Air and Water Purity, the Natural

Environment and Public Health and Safety 248(b)(6) Consistency with Approved Integrated Resource Plan (IRP)

2 Replacement of existing facilities with equivalent facilities in the usual course of business, and electric generation facilities that are operated solely for on-site electricity consumption by the owner of those facilities do not require a CPG.



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248(b)(7) Consistency with Electrical Energy Plan 248(b)(8) Outstanding Resource Waters 248(b)(9) Solid Waste Management 248(b)(10) Existing Transmission Facilities

Securing a CPG can be a relatively lengthy and resource intensive undertaking. Because the process is quasi-judicial, exhibits must be prepared and submitted and testimony given subject to contested case schedules and procedures developed in accordance with the requirements of 3 V.S.A. § 809 which often requires resource experts. In addition to preparing for hearings, applicants must be prepared to respond to formal discovery and evidence submitted by interveners, state and local governmental agencies, the Department of Public Service (DPS), who serves as the public advocate, and other interested stakeholders. Technical hearings conducted by the PSB are governed by the Board’s Rules of Practice which apply the Vermont Rules of Civil Procedure and Evidence; see PSB Rule 2.000. Public hearings conducted under the Section 248 process represent additional points of exposure and risk. Conditions attached to a CPG can add significant costs and time to a project, especially if post-CPG proceedings or compliance filings are required. In the event that other relevant regulatory approvals (such as a Wetlands CUD) are not in hand at the time of PSB ruling a CPG can be issued conditionally, contingent upon the receipt of all other necessary approvals.

2. Clean Air Act, Construction & Operating Permits - The Vermont Air Pollution Control Division (APCD) of the Department of Environmental Conservation (DEC) implements the state and federal Clean Air Acts. The APCD issues construction and operating permits:

Construction Permits - A construction permit, or a determination by the APCD that a permit is not required, is necessary before a project can be installed, constructed or modified. Construction permits are valid for the life of the project and are only reissued if changes are planned for the permitted activity which require a permit review.

Operating Permits – Operating permits incorporate all the air pollution control requirements a facility is subject to into one document. Operating permits must be renewed every five years to incorporate any new requirements that may have been adopted since the original operating permit was issued.



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Construction and operating permits are further divided into four categories based primarily on emission criteria.

3. Clean Water Act – Section 404 (Wetlands and Waterways Dredge and Fill Permits) -

Regulates the placement of dredged or fill materials into wetlands and other Waters of the United States. A section 404 permit would likely cover activities associated with the proposed gas line stream crossing as well as any work within the boundaries of wetland resources located within the limit of disturbance. Depending on the footprint and scope of the development these activities may be eligible to be covered under Vermont’s Programmatic General Permit (PGP).

4. Vermont Wetland Rules, Conditional Use Determination (CUD) - The Vermont Wetland Rules identify and protect 10 functions and values of "significant" wetlands and establish a 3-tier wetland classification system to identify such wetlands. Any activity within the wetland review area that is not identified or determined to be an “allowed” use are considered “conditional” uses. “Allowed” and “conditional” uses are determined based on the wetland class for each resource area. Conditional uses are only allowed in significant wetlands or in adjacent buffer zones upon receiving a Conditional Use Determination (CUD).

5. Vermont Stormwater Rules - The Vermont Agency of Natural Resources (ANR) regulates stormwater discharges to surface waters that are not identified as impaired by stormwater runoff. ANR issues general permits to a category of projects, rather than on an individual project basis with certifications of compliance from stormwater consultants. State-issued general permits include coverage for:

Stormwater discharges from new development and redevelopment, and; Previously permitted stormwater discharges.

6. Vermont Endangered Species Law - The Vermont Nongame and Natural Heritage

Program (NHHP) provides protection for State listed species and significant natural communities. The NNHP is similar to the federal Endangered Species Act (ESA) in the review and consultation process however the species that are legally protected on the state level reflect the status of populations within Vermont and are therefore different from the federal listings either in status (endangered or threatened) or overall listing. While not currently on Vermont’s list of threatened and endangered species, C. haydenii (categorized by a recent site surveys as “rare”), could trigger requirements for a more



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detailed vegetative survey of the area. Additionally, the presence of several seepage forests and their associated plant communities (which can include relatively uncommon species), could trigger additional investigations. Depending on the results, project development could require protection, mitigation and/or enhancement measures.

7. Electrical Interconnection Agreement – Requirements for integration with the electrical grid will be review and negotiated with the local distribution utility (Vermont Electric Cooperative [VEC]); likely including coordination with the Vermont Electric Power Company (VELCO). The interconnection agreement will specify the type of electrical controls and protection necessary to safely interconnect the project. Depending on the final capacity and local system constraints interconnection may include upgrades and/or improvements to the distribution system outside of project boundary. The installed capacities being considered for this site are not anticipated to require review by ISO-New England.



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12.2 PRELIMINARY REGULATORY TIMELINE & BUDGET ESTIMATE Tabulated below is an indicative assessment of the regulatory requirements and process associated with obtaining the necessary approvals to construct and operate a CHP at the subject property. Estimates are intended to be used for planning purposes only.

Item Estimated

Time (months)

Budgetary Cost

Estimate Notes

Certificate of Public Good (Section 248)

36 $125-150k3

Contingent upon receipt of regulatory approvals and satisfying resource protection tests. Can be partially concurrent with other regulatory items.

Air Pollution Control (Construction & Operation) 6-12 $100-300k4

Emission control measures for base-load type facility are likely to require post combustion controls and/or run hour restrictions. Level of effort will be contingent on installed capacity.

Wetlands & Waterways (VT CUD & Corps 404) 9 $50-75k

Will address gas line stream crossing and effects to on-site wetlands and watercourses.

VT Stormwater 6 $50-75k5

Ensure adequate site drainage and runoff measures are implemented during and after construction.

VT NHHP Review

12 $25-50k

Presence of seepage forests and rare sedge likely to be considered. Site survey requirements can require multiple season events.

Local Approvals (Zoning, Building, etc.)

6 $25-40k Various anticipated, PSB review incorporates regional planning efforts.

Electrical Interconnection (VEC / VELCO)

6 $50-75K Likely initiated through VEC with technical assistance by VELCO.

TOTAL 2 yrs $425 -750k

3 Cost reflects procedural filings, outreach, hearings and other meetings, and preparation of exhibits. Costs for studies and other analytical work that would support the 248 filings are listed below with the individual permit requirements. 4 Costs will vary significantly depending on the size of the project, equipment, and anticipated run hours. Noise analyses are also handled as part of the Air Pollution Control permit. 5 Includes site drawings and engineering calculations.



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13.0 PRELIMARY OPERATIONAL MODELS 13.1 STAFFING REQUIREMENTS Proper operations and maintenance of the CHP asset is critical to meeting performance and availability goals. Specialized maintenance and overhaul work on some CHP components such as gas turbines and engines are typically carried out by the equipment manufacturer or supplier. Routine plant checks, lubrication, oil changes, filter changes, etc. can typically be completed by staff from the CHP host. However, even if the CHP host staff assume responsibility for routine maintenance proper training of plant operators, maintenance staff, and site managerial staff is critical. For our analysis we have included provisions for CHP staffing based on the following assumptions:

Description Solar Titan

Solar Taurus

Solar Mercury

Caterpillar 3516C-HD

Staffing Requirements

ANNUAL LABOR COST, EACH 1ST SHIFT, MON – FRI ($1,000’S) Simple Cycle, One Unit 448 448 448 448 Plant Manager/Operator

Simple Cycle, Multiple Units 448 616 616 784 Plant Mgr + Operator/Mechanic

Combined Cycle, One Unit 784 784 784 616 Plant Mgr + Operator/Mechanic

Combined Cycle, Multiple Units

784 952 952 1,120 Plant Mgr + Operator/Mechanics

ADDITIONAL LABOR COST, EACH ADDT'L HOUR, SUN – FRI ($/Hr) Simple Cycle, One Unit 50 50 50 50 Plant Manager/Operator

Simple Cycle, Multiple Units 76 76 76 101 Plant Mgr + Operator/Mechanic

Combined Cycle, One Unit 101 76 76 76 Plant Mgr + Operator/Mechanic

Combined Cycle, Multiple Units

101 101 101 126 Plant Mgr + Operator/Mechanics

Depending on operating hours, there will need to be enough trained people to provide cover for shift working, for planned or sudden staff absences, and staff transitions. Training should include hands-on use of the plant, overall philosophy and purpose of the plant, condition and performance monitoring, and identifying when specialized technical support is required. Lack of training can be disruptive to the cost-effective and reliable operation of a CHP plant. As more information about a potential host becomes available it may be possible to reduce the labor



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component of the operations and maintenance requirements if some of these responsibilities can be taken on by in-house staff. 13.2 ENVIRONMENTAL COMPLIANCE APPROACH Air emissions criteria are expected to be the primary driver of environmental compliance obligations. Typically, VT ANR will permit emission sources based on the anticipated annual emission profile. The emission profile from any source is determined in part by fuel type, efficiency of combustion, and post combustion controls. Based on these criteria the VT ANR will permit a set number of annual run hours for each source in order to maintain acceptable levels of air quality through control of pollutant loading. In order to function as a true CHP resource the project will need to operate as a base load resource (e.g., very few periods of non-operation). Typically, this will increase the anticipated pollutant loads and could restrict the allowable run hours. In order to allow a generation asset to function as a CHP and meet VT’s air quality protection standards we have assumed that post combustion emission controls would be required.



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14.0 PRELIMINARY ECONOMIC ANALYSIS Two cash flow models were developed as part of the study. The first is a screening tool designed to provide a rapid economic assessment of various forms of natural gas use/conversion at existing facilities. The second model is a more refined feasibility model that includes an analysis of economic performance based on specific input data related to equipment capacity and performance, capital expenditures, debt structure, operating expenditures, and revenues. The models can be used in conjunction beginning with potential opportunities being rapidly screened with the screening tool. Opportunities which appear to produce benefits based on screening results can then be subjected to more detailed analysis using the feasibility model. The following provides a brief summary of the more detailed feasibility model developed to evaluate the viability of an Energy park at the Beecher Falls study site. Additional information on key assumptions as well as instructions for the use of both the screening tool and the more detailed feasibility model is provided in the Appendix.. 14.1 ECONOMIC FEASIBILITY MODEL DESCRIPTION The Economic Feasibility model is a discounted cash flow analysis tool that evaluates capital expenditures (e.g., cost to construct), equipment performance characteristics (e.g., heat rates, capacity), operating expenditures (e.g., cost of fuel and O&M), and revenues (e.g. costs of goods or services provided). The model uses these key input variables to perform a 30-year cash flow analysis producing estimates of Net Present Value and Internal Rate of Return on an annual basis on up to nine different alternatives. The Appendix provides a detailed description of the model structure, a description of key input parameters, and instructions on its use. The actual model itself is being provided as a separate deliverable. 14.2 MODEL LIMITATIONS The Economic Feasibility Model is designed to evaluate the economic performance of a CHP asset at the Beecher Falls study site (Beecher Falls, VT). Results are intended to be used as a planning tool only; additional analysis is recommended prior to making investment decisions. The model has the flexibility to evaluate economic performance at other locations given the appropriate adjustments to key model inputs.



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14.3 KEY INPUTS Key assumptions made in developing the Economic Feasibility Model are summarized in the table below.

Item Value

Escalation 2.5%

Discount Rate 8.0%

Grant 10%

Depreciation Term 20

Investment Tax Credit 10%

Combined Fed + State Tax Rate 40%

Property Tax Rate (% of Invest. Cost) 1.0% Insurance Rate (% of Invest. Cost) 0.5% Natural Gas Interconnection Costs $2,060,000

Additional details regarding model inputs, as well as model operations are provided in the appendix.



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14.4 CASH ON CASH RESULTS The cash on cash results of nine alternative CHP projects using the financial inputs outlined above and in the Appendix are tabulated below. Two tables are provided, one showing results assuming simple-cycle operations, and one showing results for a combined-cycle operation. In a simple-cycle plant, there would be no secondary electrical generation with the steam produced by the plant. In the combined-cycle case, waste heat is captred and used to produce additional electicial generation. Note that the capacity factor6 for each alternative was adjusted to identify the minimum thresholds of economic viability where possible. 14.4.1 Cash on Cash – Simple Cycle

No. Alternative Installed Capacity

(MW)

Net Generation

(MWH)

Total Estimated

Costs ($1,000's)

Installed Costs

Electrical($/kW)

Capacity Factor

RunningCost

Eletrical(¢/kWH)

IRR Cumulative

NPV ($1,000s)

1 (1) Caterpillar G3520 2.1 18,001 6,106 2,971 100% 7.2 ###### (5,633)

2 (5) Caterpillar G3520 10.3 64,289 17,430 1,696 71% 7.2 8% 216

3 (1) Solar Mercury 50 4.5 39,313 11,726 2,613 100% 6.9 #NUM! (9,316)

4 (3) Solar Mercury 50 13.5 95,474 26,457 1,965 81% 6.9 8% 1,007

5 (1) Solar Taurus 60 5.5 48,204 10,675 1,940 100% 8.3 ###### (15,935)

6 (3) Solar Taurus 60 16.5 130,838 22,931 1,389 90% 8.3 8% 322

7 (1) Solar Taurus 70 7.7 67,834 12,568 1,623 100% 7.7 6% (2,072)

8 (2) Solar Taurus 70 15.5 96,905 20,602 1,330 71% 7.7 8% 493

9 (1) Solar Titan T130 14.5 75,447 16,155 1,116 60% 7.5 8% 27

6 Capacity factor is a measure of the amount of time that the CHP is operating to provide electrical and thermal benefits. For example a capacity factor of 50% indicates that the CHP is in operation 50% of the year (or 4,130 hours). A project can only produce revenues when operating, therefore, higher capacity factors generally improve project economics though increased production and revenues.



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14.4.2 Cash on Cash – Combined Cycle


(MW)

Net Generation

(MWH)

Total Estimated

Costs ($1,000's)

Installed Costs

Electrical ($/kW)

Capacity Factor

RunningCost

Electrical(¢/kWH)

Running Cost

Steam ($/Ton)

IRR Cumulative

NPV ($1,000s)

1 (1) Caterpillar G3520

2.1 18,001 7,065 3,438 100% 7.2 2.2 ###### (11,428)


10.3 77,146 20,720 2,017 86% 7.2 2.2 8% 4

3 (1) Solar Mercury 50 4.5 39,313 15,328 3,415 100% 6.9 1.7 ###### (18,824) 4 (3) Solar Mercury 50 13.5 112,322 36,842 2,736 95% 6.9 1.7 8% 1,527 5 (1) Solar Taurus 60 5.5 48,204 13,647 2,480 100% 8.3 0.9 ###### (15,524) 6 (3) Solar Taurus 60 16.5 110,180 31,209 1,890 76% 8.3 0.9 9% 1,566 7 (1) Solar Taurus 70 7.7 67,834 16,330 2,109 100% 7.7 1.1 7% (1,231) 8 (2) Solar Taurus 70 15.5 90,445 27,820 1,796 67% 7.7 1.1 8% (455) 9 (1) Solar Titan T130 14.5 78,464 22,067 1,525 62% 7.5 1.1 8% 225



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14.4.3 Findings Based on the modeling results shown above, the following trends emerge:

Capacity Factor / Host Demand - For this study project capacity factor was defined as a function of the CHP hosts operating schedule (e.g., number of shifts and operating days/week). Alternatives 1, 3, and 7 do not produce economic benefits even when the CHP is available 100% of the time. These alternatives are associated with the lowest installed capacities as well, suggesting that host demand is a critical driver of overall CHP economics. A CHP host with a robust demand profile (generally >8 MW) would be required to support an economically viable project .

Economies of Scale – Results indicate that multiple units and/or higher installed capacities produce stronger economic benefits. Using the installed costs ($/kw) as an indicator, it appears that the maximum threshold for installed costs for simple cycle are less than $1,700 and, less than $2,000/kw for combined cycle. Alternatives with installed costs greater than these thresholds do not appear to produce economic benefits. This finding reinforces the observation regarding minimum capacity factors noted above.



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14.5 DEBT LEVERED RESULTS In order to evaluate the potential upside of leveraging debt to improve economic performance, a debt levered economic analysis was completed. Key input assumptions outlined above were retained, with the following additions: Item Value Percent Debt 50%

Interest Rate 5.0%

Term (Yrs) 20 Similar to the cash on cash analysis, the capacity factor for each alternative was adjusted to identify the minimum thresholds of economic viability where possible. Results of the levered analysis support the findings noted for the cash on cash analysis. In some cases the minimum capacity factor threshold was lower – however project performance is clearly sensitive to this variable and even minor perturbations from the minimum thresholds may rendor the project uneconomic. Results of the debt levered model runs are shown in the tables below.



Page 45


14.5.1 Levered Results – Simple Cycle


(MW)

Net Generation

(MWH)

Total Estimated

Costs ($1,000's)

InstalledCosts

Electrical($/kW)

Capacity Factor

RunningCost

Electrical(¢/kWH)

IRR Cumulative

NPV ($1,000s)


2.1 18,001 6,106 2,971 100% 7.2 ###### (4,156)


10.3 53,574 17,430 1,696 60% 7.2 9% 837

3 (1) Solar Mercury 50

4.5 39,313 11,726 2,613 100% 6.9 ###### (5,903)


13.5 77,221 26,457 1,965 65% 6.9 9% 825

5 (1) Solar Taurus 60 5.5 48,204 10,675 1,940 100% 8.3 ###### (14,952) 6 (3) Solar Taurus 60 16.5 110,180 22,931 1,389 76% 8.3 9% 1,315 7 (1) Solar Taurus 70 7.7 67,834 12,568 1,623 100% 7.7 10% 1,306 8 (2) Solar Taurus 70 15.5 80,754 20,602 1,330 60% 7.7 9% 939

9 (1) Solar Titan T130

14.5 63,375 16,155 1,116 50% 7.5 8% 29



Page 46


14.5.2 Levered Results – Combined Cycle

No.

Alternative

Installed

Capacity (MW)

Net Generation (MWH)

Total Estimated Costs

($1,000's)

InstalledCosts

Electrical

($/kW)

Capacity Factor

RunningCost

Electrical

(¢/kWH)

Running Cost

Steam ($/Ton)

IRR

Cumulative

NPV ($1,000s)


2.1 18,001 7,065 3,438 100% 7.2 2.2 #####

# (9,584)


10.3 68,575 20,720 2,017 76% 7.2 2.2 9% 1,267


4.5 39,313 15,328 3,415 100% 6.9 1.7 #####

# (14,646)


13.5 95,474 36,842 2,736 81% 6.9 1.7 9% 1,954

5 (1) Solar Taurus 60 5.5 48,204 13,647 2,480 100% 8.3 0.9 #####

# (15,789)

6 (3) Solar Taurus 60 16.5 89,521 31,209 1,890 62% 8.3 0.9 8% 376 7 (1) Solar Taurus 70 7.7 64,604 16,330 2,109 95% 7.7 1.1 9% 786 8 (2) Solar Taurus 70 15.5 77,524 27,820 1,796 57% 7.7 1.1 8% 251


14.5 67,902 22,067 1,525 54% 7.5 1.1 8% 422



Page 47


14.5.3 Findings Based on the results above the following trends emerge:

Capacity Factor / Host Demand – Similar to the cash on cash analysis, a CHP host with a robust demand profile (generally >8 MW) would be required to make the project economically viable. The capacity factor for these alternatives ranges from 54-76%, depending on the alternative. Configurations with higher installed capacities can withstand lower capacity factors and retain economic viability due to economy of scale benefits.

Economies of Scale – Results indicate that multiple units and/or higher installed capacities produce stronger economic benefits. Using the installed costs ($/kw) as an indicator, it appears that the maximum threshold for installed costs for simple cycle are less than $1,700 and, less than $2,000/kw for combined cycle. Alternatives with installed costs greater than these thresholds do not appear to produce economic benefits. This finding reinforces the findings regarding minimum capacity factors (described above).



Page 48


15.0 CONCLUSIONS Based on the results of the economic analysis it appears that a minimum installed capacity of approximately 10 MW and a capacity factor of 76% is required for economic viability of the Energy Park. This minimum threshold is sensitive to perturbations in capacity factor – loss of a single typical operating shift by the CHP host would result in an economic penalty. This result suggests that for an Energy Park concept to be viable at the study site a CHP host with a robust demand will be required. Based on the preliminary Mark Analysis findings (Camoin Associates), this type of host does not appear to be readily available. The matrix below summarizes key installed capacity and capacity factor thresholds for each of the alternatives. The results below are based on a debt levered financing structure.


(MW)

Combined Cycle Simple Cycle

Capacity Factor

IRR Cum. NPV

($1,000s)

Capacity Factor

IRR Cum. NPV

($1,000s)


2.1 100% ###### (9,584) 100% ###### (4,156)


10.3 76% 9% 1,267 60% 9% 837

3 (1) Solar Mercury 50 4.5 100% ###### (14,646) 100% ###### (5,903) 4 (3) Solar Mercury 50 13.5 81% 9% 1,954 65% 9% 825 5 (1) Solar Taurus 60 5.5 100% ###### (15,789) 100% ###### (14,952) 6 (3) Solar Taurus 60 16.5 62% 8% 376 76% 9% 1,315 7 (1) Solar Taurus 70 7.7 95% 9% 786 100% 10% 1,306 8 (2) Solar Taurus 70 15.5 57% 8% 251 60% 9% 939 9 (1) Solar Titan T130 14.5 54% 8% 422 50% 8% 29

Based on the results above, Alternatives 1, 3 and 5 do not appear economic in simple or combined cycle mode. Economic benefits begin to be realized by the balance of alternatives given the right host profile. Regardless of the operating mode the minimum installed capacity threshold is approximately 8 MW. With some value engineering and optimization this threshold may be somewhat lower, however this can not be determined without detailed host demand profile information.



Page 49


Capacity factor also emerges as a driver of economic performance. Given the results above, there appear to be two minimum thresholds at play, the first relative to installed capacity, the second related to capacity factor. Higher installed capacities enjoy economy of scale benefits in terms of initial investment allowing for lower capacity factors. Alternatives with lower installed capacities may also be viable, but require significantly higher capacity factors. These results suggest that a viable CHP host will have at least one of the following traits: Simple Cycle CHP Host Threshold:

Require at least 8 MW of electrical demand and operate at a 60% capacity factor.

Combined Cycle CHP Host Threshold: Require at least 8 MW of electrical demand (in addition to thermal products) and operate

at a 57% capacity factor.

EQUIPMENT VENDOR DATA

Caterpillar G3520C

G3520C GAS ENGINE TECHNICAL DATA

ENGINE SPEED: 1200 FUEL:COMPRESSION RATIO: 11.3:1 FUEL SYSTEM: CAT LOW PRESSUREAFTERCOOLER - STAGE 1 MAX. INLET (°F): 198AFTERCOOLER - STAGE 2 MAX. INLET (°F): 130 FUEL PRESS. RANGE (PSIG): 0.50 - 5.0JACKET WATER - MAX. OUTLET (°F): 210 MIN. METHANE NUMBER: 80COOLING SYSTEM: JW+OC+1AC, 2AC RATED ALTITUDE (FT): 2595IGNITION SYSTEM: ADEM3 AT AIR TO TURBO. TEMP. (°F): 77EXHAUST MANIFOLD: DRY NOx EMISSION LEVEL: 0.5 g/bhp-hrCOMBUSTION: LOW EMISSION FUEL LHV (BTU/SCF): 905EFFECTIVE SERIAL NUMBER: GZL00141-Up APPLICATION: GENSET

NOTES LOAD 100% 75% 50%ENGINE POWER (WITHOUT FAN) (1) BHP 2248 1686 1124GENERATOR POWER (WITHOUT FAN) (2) EKW 1600 1201 800ENGINE EFFICIENCY (ISO 3046/1) (3) % 39.9 38.4 35.9ENGINE EFFICIENCY (NOMINAL) (3) % 38.9 37.5 35.1THERMAL EFFICIENCY (NOMINAL) (4) % 38.7 40.2 42.0TOTAL EFFICIENCY (NOMINAL) (5) % 77.7 77.6 77.1

FUEL CONSUMPTION (ISO 3046/1) (6) BTU/bhp-hr 6383 6629 7084FUEL CONSUMPTION (NOMINAL) (6) BTU/bhp-hr 6538 6791 7257AIR FLOW (77 °F, 14.7 psi) (7) SCFM 5089 3840 2648AIR FLOW (7) lb/hr 22564 17025 11741COMPRESSOR OUT PRESSURE in. HG (abs) 111 84.5 57.7COMPRESSOR OUT TEMPERATURE °F 395 323 231AFTERCOOLER AIR OUT TEMPERATURE °F 137 137 137INLET MAN. PRESSURE (8) in. HG (abs) 100.7 75.7 51.9INLET MAN. TEMPERATURE (MEASURED IN PLENUM) (9) °F 137 137 137TIMING (10) °BTDC 28 28 28EXHAUST STACK TEMPERATURE (11) °F 758 827 890

(12) CFM 12361 9870 7154EXHAUST MASS FLOW (12) lb/hr 23304 17601 12152

NOx (as NO2) (13) g/bhp-hr 0.50 0.50 0.50CO (14) g/bhp-hr 2.25 2.32 2.34THC (molecular weight of 15.84) (14) g/bhp-hr 8.52 9.44 11.11NMHC (molecular weight of 15.84) (14) g/bhp-hr 1.28 1.42 1.67CO2 (14) g/bhp-hr 448 464 485EXHAUST O2 (15) % DRY 10.3 10.1 9.9LAMBDA (15) 1.91 1.85 1.79

LHV INPUT (16) BTU/min 244932 190789 135926HEAT REJECTION TO JACKET (17) BTU/min 29437 25676 21757HEAT REJECTION TO ATMOSPHERE (18) BTU/min 6372 5325 4278HEAT REJECTION TO LUBE OIL (19) BTU/min 6005 5379 4612HEAT REJECTION TO EXHAUST (LHV to 77°F) (20) BTU/min 80334 67144 50844HEAT REJECTION TO EXHAUST (LHV to 350°F) (20) BTU/min 41900 37207 29255HEAT REJECTION TO A/C - STAGE 1 (21) BTU/min 17547 8357 1527HEAT REJECTION TO A/C - STAGE 2 (22) BTU/min 7934 5436 3269

CONDITIONS AND DEFINITIONS

ENGINE RATING IS WITH 2 ENGINE DRIVEN WATER PUMPS. PUMP POWER IS NOT INCLUDED IN HEAT BALANCE DATA.

FOR NOTES INFORMATION CONSULT PAGE THREE.

DM5856-02 (SUPERSEDES DM5694) 22-Oct-09PAGE 1 OF 3

ENGINE RATING OBTAINED AND PRESENTED IN ACCORDANCE WITH ISO 3046/1. DATA REPRESENTS CONDITIONS OF 77°F, 29.6 IN HG BAROMETRIC PRESSURE, 30% RELATIVE HUMIDITY, 10 IN H2O AIR FILTER RESTRICTION, AND 20 IN H2O EXHAUST STACK PRESSURE. ENGINE EFFICIENCY AND FUEL CONSUMPTION SPECIFICALLY NOTED AS ISO 3046/1 ARE REPRESENTED WITH 5 IN H2O AIR FILTER RESTRICTION AND 0 IN H2O EXHAUST STACK PRESSURE. CONSULT ALTITUDE CURVES FOR APPLICATIONS ABOVE MAXIMUM RATED ALTITUDE AND/OR TEMPERATURE. NO OVERLOAD PERMITTED AT RATING SHOWN.

EMISSION LEVELS ARE BASED ON THE ENGINE OPERATING AT STEADY STATE CONDITIONS AND ADJUSTED TO THE SPECIFIED NOx LEVEL AT 100% LOAD. EMISSION TOLERANCES SPECIFIED ARE DEPENDENT UPON FUEL QUALITY. METHANE NUMBER CANNOT VARY MORE THAN ± 3. PUBLISHED PART LOAD DATA IS WITH AIR FUEL RATIO CONTROL.

NAT GAS

HEAT BALANCE DATA

EMISSIONS DATA

ENGINE DATA

RATING AND EFFICIENCY

EXHAUST GAS FLOW (@ stack temp.)

WITH AIR FUEL RATIO CONTROL


30 35 40 45 50 55 60 65 70 75 80 85 to 100- - - - - 16 16 16 16 22 280 0 0 0 0 0.75 0.81 0.86 0.90 0.95 1.00

130 1.00 0.97 0.93 0.90 0.86 0.83 0.80 0.77 0.74 0.71 0.68 0.65 0.63120 1.00 0.98 0.95 0.91 0.88 0.84 0.81 0.78 0.75 0.72 0.69 0.67 0.64

AIR 110 1.00 1.00 0.96 0.93 0.89 0.86 0.83 0.79 0.76 0.73 0.71 0.68 0.65TO 100 1.00 1.00 0.98 0.94 0.91 0.87 0.84 0.81 0.78 0.75 0.72 0.69 0.66

TURBO 90 1.00 1.00 1.00 0.96 0.93 0.89 0.86 0.82 0.79 0.76 0.73 0.70 0.6780 1.00 1.00 1.00 0.98 0.94 0.91 0.87 0.84 0.81 0.78 0.74 0.72 0.69

(°F) 70 1.00 1.00 1.00 1.00 0.96 0.92 0.89 0.86 0.82 0.79 0.76 0.73 0.7060 1.00 1.00 1.00 1.00 0.98 0.94 0.91 0.87 0.84 0.81 0.77 0.74 0.7150 1.00 1.00 1.00 1.00 1.00 0.96 0.92 0.89 0.85 0.82 0.79 0.76 0.73

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000ALTITUDE (FEET ABOVE SEA LEVEL)

130 1.30 1.35 1.39 1.42 1.42 1.42 1.42 1.42 1.42 1.42 1.42 1.42 1.42120 1.24 1.29 1.33 1.36 1.36 1.36 1.36 1.36 1.36 1.36 1.36 1.36 1.36

AIR 110 1.18 1.23 1.27 1.30 1.30 1.30 1.30 1.30 1.30 1.30 1.30 1.30 1.30TO 100 1.12 1.16 1.21 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23

TURBO 90 1.06 1.10 1.14 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.1780 1.00 1.04 1.08 1.11 1.11 1.11 1.11 1.11 1.11 1.11 1.11 1.11 1.11

(°F) 70 1.00 1.00 1.02 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.0460 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0050 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000ALTITUDE (FEET ABOVE SEA LEVEL)

FUEL USAGE GUIDE:This table shows the derate factor required for a given fuel. Note that deration occurs as the methane number decreases. Methane number is a scale to measure

detonation characteristics of various fuels. The methane number of a fuel is determined by using the Caterpillar Methane Number Calculation program.

ALTITUDE DERATION FACTORS:This table shows the deration required for various air inlet temperatures and altitudes. Use this information along with the fuel usage guide chart to help

determine actual engine power for your site.

INLET AND EXHAUST RESTRICTION CORRECTIONS FOR ALTITUDE CAPABILITY:To determine the appropriate altitude derate factor to be applied to this engine for inlet or exhaust restrictions differering from the

standard conditions listed on page 1, a correction to the site altitude can be made to adjust for this difference. Add 139 feet to the site

altitude for each additional inch of H2O of exhaust stack pressure greater than spec sheet conditions. Add 279 feet to the site altitude for each

additional inch of H2O of inlet restriction greater than spec sheet conditions. If site inlet restriction or exhaust stack pressure

are less than spec sheet conditions, the same trends apply to lower the site altitude.

ACTUAL ENGINE RATING:It is important to note that the Altitude/Temperature deration and the Fuel Usage Guide deration are not cumulative. They are not to be added together. The

same is true for the Low Energy Fuel deration (reference the Caterpillar Methane Number Program) and the Fuel Usage Guide deration. However, the

Altitude/Temperature deration and Low Energy Fuel deration are cumulative; and they must be added together in the method shown below. To determine

the actual power available, take the lowest rating between 1) and 2).

1) (Altitude/Temperature Deration) + (Low Energy Fuel Deration)

2) Fuel Usage Guide Deration

Note: For NA's always add the Low Energy Fuel deration to the Altitude/Temperature deration. For TA engines only add the Low Energy Fuel

deration to the Altitude/Temperature deration whenever the Altitude/Temperature deration is less than 1.0 (100%). This will give the actual rating

for the engine at the conditions specified.

AFTERCOOLER HEAT REJECTION FACTORS:Aftercooler heat rejection is given for standard conditions of 77°F and 500 ft altitude. To maintain a constant air inlet manifold temperature, as the air to turbo

temperature goes up, so must the heat rejection. As altitude increases, the turbocharger must work harder to overcome the lower atmospheric pressure.

This increases the amount of heat that must be removed from the inlet air by the aftercooler. Use the aftercooler heat rejection factor to adjust for ambient and

altitude conditions. Multiply this factor by the standard aftercooler heat rejection. Failure to properly account for these factors could result in detonation and

cause the engine to shutdown or fail. For 2 Stage Aftercoolers with separate circuits, the 1st stage will collect 90% of the additional heat.

DM5856-02

28

FUEL USAGE GUIDE

CAT METHANE NUMBERIGNITION TIMING

PAGE 2 OF 3 22-Oct-09

DERATION FACTOR 1.00

ALTITUDE DERATION FACTORS

AFTERCOOLER HEAT REJECTION FACTORS


NOTES

1 ENGINE RATING IS WITH 2 ENGINE DRIVEN WATER PUMPS. TOLERANCE IS ± 3% OF FULL LOAD.

2 GENERATOR POWER DETERMINED WITH AN ASSUMED GENERATOR EFFICIENCY OF 95.45% AND POWER FACTOR OF 0.8 [GENERATOR POWER = ENGINE POWER x GENERATOR EFFICIENCY].

3 ISO 3046/1 ENGINE EFFICIENCY TOLERANCE IS (+)0, (-)5% OF FULL LOAD % EFFICIENCY VALUE. NOMINAL ENGINE EFFICIENCY TOLERANCE IS ± 2.5% OF FULL LOAD % EFFICIENCY VALUE.

4 THERMAL EFFICIENCY: JACKET HEAT + LUBE OIL HEAT + STAGE 1 A/C HEAT + EXH. HEAT TO 350°F.

5 TOTAL EFFICIENCY = ENGINE EFF. + THERMAL EFF. TOLERANCE IS ± 10% OF FULL LOAD DATA.

6 ISO 3046/1 FUEL CONSUMPTION TOLERANCE IS (+)5, (-)0% OF FULL LOAD DATA. NOMINAL FUEL CONSUMPTION TOLERANCE IS ± 2.5 % OF FULL LOAD DATA.

7 UNDRIED AIR. FLOW TOLERANCE IS ± 5 %

8 INLET MANIFOLD PRESSURE TOLERANCE IS ± 5 %

9 INLET MANIFOLD TEMPERATURE TOLERANCE IS ± 9°F.

10 TIMING INDICATED IS FOR USE WITH THE MINIMUM FUEL METHANE NUMBER SPECIFIED. CONSULT THE APPROPRIATE FUEL USAGE GUIDE FOR TIMING AT OTHER METHANE NUMBERS.

11 EXHAUST STACK TEMPERATURE TOLERANCE IS (+)63°F, (-)54°F.

12 WET EXHAUST. FLOW TOLERANCE IS ± 6 %

13 NOX TOLERANCES ARE ± 18 % OF SPECIFIED VALUE.

14 CO, CO2, THC, and NMHC VALUES ARE "NOT TO EXCEED".

15 O2% TOLERANCE IS ± 0.5; LAMBDA TOLERANCE IS ± 0.05. LAMBDA AND O2 LEVEL ARE THE RESULT OF ADJUSTING THE ENGINE TO OPERATE AT THE SPECIFIED NOX LEVEL.

16 LHV RATE TOLERANCE IS ± 2.5%.

17 TOTAL JW HEAT (based on treated water) = JACKET HEAT + LUBE OIL HEAT + STAGE 1 A/C HEAT + 0.90 x (STAGE 1 + STAGE 2) x (ACHRF-1). TOLERANCE IS ± 10 % OF FULL LOAD DATA.

18 RADIATION HEAT RATE BASED ON TREATED WATER. TOLERANCE IS ± 50% OF FULL LOAD DATA.

19 LUBE OIL HEAT RATE BASED ON TREATED WATER. TOLERANCE IS ± 20% OF FULL LOAD DATA.

20 EXHAUST HEAT RATE BASED ON TREATED WATER. TOLERANCE IS ± 10% OF FULL LOAD DATA.

21 STAGE 1 A/C HEAT (based on treated water) = STAGE 1 A/C HEAT + 0.90 x (STAGE 1 + STAGE 2) x (ACHRF-1). TOLERANCE IS ± 5 % OF FULL LOAD DATA.

22 STAGE 2 A/C HEAT (based on treated water) = STAGE 2 A/C HEAT + (STAGE 1 + STAGE 2) x 0.10 x (ACHRF - 1). TOLERANCE IS ± 5 % OF FULL LOAD DATA.

DM5856-02 PAGE 3 OF 3 22-Oct-09

Solar Mercury 50

Solar Taurus 60

Solar Taurus 70

Solar Titan 130

CHP CONCEPTUAL LAYOUT DRAWINGS

ECONOMIC MODELS & DOCUMENTATION

Model Documentation

Beecher Falls Energy Park Economic Models Feasibility Study Documentation and Instructions

Economic Models Two cash flow models were developed as part of the study. The first is a screening level model designed

to provide a rapid economic assessment of various forms of natural gas use/conversion at existing

facilities. The second model is a more refined feasibility model that includes detailed analysis of

economic performance based on specific input data related to equipment capacity and performance,

capital expenditures, debt structure, operating expenditures, and revenues. The models can be used in

conjunction beginning with potential opportunities being rapidly screened with the screening model.

Opportunities which appear to produce benefits based on screening model results can then be

subjected to more detailed analysis using the feasibility model. The following sections provide additional

details on each model as well as instructions for their intended use(s).

Screening Model Description The model is a simplified cash flow analysis tool which provides the user with opportunities to specify

capital expenditures (e.g., cost to construct), operating expenditures (e.g., cost of fuel and O&M), and

revenues (e.g. costs of goods or services provided). The model uses these key input variables to perform

a 30‐year cash flow analysis producing preliminary estimates of Net Present Value and Internal Rate of

Return on an annual basis. In order to facilitate the interpretation of model results the input tab has

been designed to instantly summarize key results both in tabular and graphic formats. The model was

developed on a spreadsheet platform with the following worksheets:

1. Summary: used to adjust key model inputs to reflect various project configurations. Summarized

results of cash flow analysis.

2. Financial Inputs: define financial model variables here.

3. Cash Flow Analysis: source of economic analysis results. Applies user defined input variables

from Summary and Financial Inputs worksheets to complete a discounted cash flow analysis.

This worksheet is “locked” to discourage alteration of the formulas which allow the analysis to

function properly.

Assumptions / Limitations The screening model is not intended to be used to make investment decisions. Rather, its function is to

provide a rapid and low cost way to evaluate the opportunity potential for a given customer. In this

context a “customer” can apply to a variety of potential end users of natural gas‐related products,

including; Combined Heat and Power, Compressed Natural Gas, Liquefied Natural Gas, Electrical Service,

Thermal Products (hot water or steam), or a combination of the above. The screening model has the

flexibility to incorporate additional commodities which may or may not be natural gas‐related.

Model results can be particularly sensitive to commodity prices, capacity factors (amount of time an

asset is utilized), capital costs and debt structure. All results should be independently verified to ensure

that errors and omissions of key input variables did not yield in accurate results. This tool is intended to

provide the user with a rapid assessment of the gross potential for a customer to benefit from natural

gas‐related goods and services. Additional refined analysis may be warranted if the screening tool

1


suggests the potential for customer benefits. The refined feasibility model is a logical next step in this

process.

Screening Model Inputs Key model inputs are defined by the user in yellow shaded cells.

The following input variables which can be defined by the user are located on the “Summary” tab:

1. Alternative Name: Concise identifier for the modeled scenario.

2. Description/Notes: Brief notation regarding specific elements of the modeled scenario. For

example, the analysis may be for delivered CNG with no electrical components. This space

provides the user/reviewer with a summary of the modeled scenario.

3. Investment Data: Capital costs to develop the modeled scenario. These data contain several

fields for various anticipated capital costs. It also has the functionality to incorporate potential

incentives (such as grants) which effectively reduce the capital costs. These data are entered in

$1,000’s.

2


4. Annual Data: These fields are used to define the staring points for the cash flow analysis. The

basic assumptions include provisions for operations and maintenance, insurance, taxes, the cost

to supply commodities, the price for delivered commodities, as well as the volume of each. The

model has the flexibility to model a variety of combinations of commodities. The costs for each

of these variables are individually defined and establish the “starting point” for the escalated

values over the term of the study.

In the table above the following input parameters are defined:

1. Annual operations and maintenance cost, including labor: For this example O&M is estimated

to be $700,000 in year one of the study, which corresponds to a large peaking or medium size

combined cycle project that is staffed two or more shifts.

2. Property Taxes: enter the estimated tax rate expressed as a percentage of the initial

investment. Typically assessors are willing to negotiate a levelized escalating tax payment as

opposed to a declining payment stream consisting of few very high initial payments which

rapidly depreciate. Experience with power generating facilities suggests a levelized rate ranging

between 1% and 2%.

3. Insurance: enter the annual insurance premium; expressed as a percentage of the initial

investment. For this example we selected 0.5% of the initial investment – which reflects our

experience with similar projects.

4. Other: placeholder for unspecified annual financial obligations associated with the project (e.g.,

lease payment, etc.). Values are expressed in thousands of dollars.

5. Natural Gas Purchases, delivered price: enter the volume and unit cost of the natural gas

commodity as delivered to the project from the pipeline. Volume is expressed in units of

mmBTU/year while the rate is expressed in $/mmBTU (individual unit price).

3


6. Cost of other commodities purchased, delivered price: placeholder for volume and unit costs

for additional project commodity purchases.

7. Electricity sold: enter the annual volume (MWH) and unit price ($/MWH) of electricity

generated and sold by the project. Note that in some instances the “sold” price may actually be

“avoided cost” if the generation displaces energy that would otherwise be purchased from the

grid.

8. Steam sold: enter the annual volume (tons) and unit price ($/ton) of steam generated and sold

(or utilized) by the project. Note that in some instances the “sold” price may actually be

“avoided cost” if the steam product displaces steam that would otherwise be purchased from

another source.

9. Hot water sold: enter the annual volume (tons) and unit price ($/ton) of hot water generated

and sold (or utilized) by the project. Note that in some instances the “sold” price may actually be

“avoided cost” if the hot water product displaces hot water that would otherwise be purchased

from another source.

10. Natural gas sold: enter the volume and unit cost of the natural gas commodity as provided by

the project to a third party or host. Volume is expressed in units of mmBTU/year while the rate

is expressed in $/mmBTU (individual unit price). The difference in the purchase price and the

sold price represents the gross profit margin on the natural gas commodity.

11. Other commodity sold: enter the volume and unit cost of an unidentified commodity as

provided by the project to a third party or host. Volume is expressed in units defined by the

user while the rate is expressed in cost per individual unit. The difference in the purchase price

and the sold price represents the gross profit margin on this “other” commodity.

The following variables drive the cash flow analysis over the 20‐year study period; they are located on

the “Financial Inputs” tab. They are described below:

1. General Escalation: annual increase in cost of goods. Generally reflects the anticipated rate of

inflation. Over the last 10 + years escalation has ranged from 2% to over 10%. In recent years

escalation has been in the range of 2% to 2.5%.

1. Energy Escalation: annual increase in the cost of energy. In the Northeast, where the primary

sources of generation are natural gas plants, energy costs track closely with natural gas prices.

Since the economic recession of 2008 energy costs have fallen for two reasons 1) a slowdown in

the economy reduced demand, and 2) insurgence of domestic natural gas production has

created a supply glut reducing gas costs. For this example we selected 2.5% annual escalation of

energy costs as a conservative estimate for a 30 year study period.

2. Fuel Escalation: annual increase in the cost of fuel. Development of domestic natural gas plays

(such as those in the Marcellus Shale formation) have created a supply glut driving down natural

gas costs over the past few years. However, concerns over potential environmental impacts

associated with the extraction process increase uncertainty of future gas pricing. For this

example we selected 2.5% annual escalation of fuel costs as a conservative estimate for a 30

year study period.

4


Note – energy and fuel escalation is separated from general escalation to allow greater flexibility in

evaluating scenarios with disparate commodity escalations.

3. Discount Rate: the opportunity cost of the capital invested at the outset of the project which is

not available for other purposes. It can be conceptualized as a “reverse interest rate”. (8%

utility, 6% municipal, 10% and up – developer)

4. Grant: % of capital costs which may be available as grants to reduce the initial investment. We

have selected 10% of capital costs as a grant value reflecting a middle of the road estimate of

incentives that may be available through either State and/or Federal sources such as the U.S.

Department of Agriculture – Rural Energy for America Program and the U.S. Treasury

Department.

5. Percent Debt: percentage of total capital costs which would be financed. (100% for municipal

bond issue; for private parties, up to 80% debt, but typically 50% to 75%)

6. Interest Rate: interest paid on financed portion of capital costs. Depends on term, strength of

project, balance sheet of the lender. In today’s lending environment: Municipal: 4‐6%, private

6‐8%

7. Term: duration of the financing arrangement. In today’s environment: Municipal: 10‐20 years;

private: 5‐10 years.

8. Depreciation Term: Depreciation of the capital investment for tax purposes. This model uses a

conservative straight line depreciation method.

9. Investment Tax Credit (ITC): Federal incentive program which currently allows up to 10% of CHP

capital costs to be recovered through a one‐time tax credit. The availability and eligibility criteria

for this Federal program are very dynamic and should be verified prior to evaluating

alternatives.

10. Combined Fed. + State Tax Rate: annual tax burden for the project (Typical range for a private

investor: 35 – 45%).

11. Commercial Operation Date: year the project is anticipated to be complete and operable.

Adjusting this value will adjust the initial capital and commodity costs according to the defined

escalation rates used in the cash flow analysis.

5


Screening Model Instructions The screening model can be used to provide a preliminary assessment of the potential for a particular

natural gas‐related project to provide economic benefits. Data specific to the potential project are

entered by the user on the Financial Inputs and Summary worksheets (as described above).

Users are cautioned to verify that all input data reflect the investment and commodity cost structure as

accurately as possible.

Results and Interpretation Guidance

The screening model uses IRR and NPV are used as high‐level indicators of the potential value of the

investment. These values are summarized in the Performance Projections table by study year.

Additionally, the NPV’s are illustrated graphically at the bottom of the page. These metrics are described

below.

1. IRR – Internal Rate of Return (IRR): is used to measure and compare the profitability of

projects. The IRR on an investment or project is the discount rate that makes the NPV of all cash

flows from a particular project equal to zero. When the IRR is greater than the discount rate the

project is anticipated to produce economic benefits.

2. Cumulative NPV (Net Present Value) ($1,000’s): a measure of how much value an investment

provides to the investor. Cumulative NPV represents the current worth of a future sum of

money or stream of cash flows given a specified rate of return. Future cash flows are discounted

at the discount rate. Generally, the higher the discount rate, the lower the present value of the

future cash flows. NPV is different from IRR, because NPV calculations use discounted cash flow

to quantify, in today's dollar terms, the projected net gain from the project in net dollar terms.

In general, projects which are estimated to produce an IRR greater than or equal to the specified

discount rate are considered to provide economic benefits. While the actual rate of return that a given

6


project ends up generating will often differ from its estimated IRR rate, a project with a substantially

higher IRR value than other available options would still provide a much better chance of strong growth.

If the screening model results suggest that the potential project will produce robust economic benefits

more refined analysis can be completed (see Refined Feasibility Model).

7


Refined Feasibility Model Description The model is a discounted cash flow analysis tool which provides the user with opportunities to specify

capital expenditures (e.g., cost to construct), equipment performance characteristics (e.g., heat rates,

capacity), operating expenditures (e.g., cost of fuel), and revenues (e.g. costs of goods or services

provided). The model uses these key input variables to perform a 30‐year cash flow analysis producing

estimates of Net Present Value and Internal Rate of Return on an annual basis on up to nine different

alternatives.

In order to facilitate the interpretation of model results the Executive Summary and Detailed Summary

tabs have been designed to instantly summarize key results both in tabular and graphic formats. The

model was developed on a spreadsheet (Microsoft© Excel) platform. This model is intended to build on

the results of the screening model and provide a more detailed analysis of project performance.

Assumptions / Limitations The Refined Feasibility Model was initially intended to evaluate the economic performance of a CHP

asset at the Beecher Falls study site (Beecher Falls, VT). Several assumptions and/or starting points

specific to the potential development of a CHP at this location are included.

The model has the flexibility to evaluate economic performance at other locations given the appropriate

adjustments to key model inputs. User defined inputs are adjusted in yellow shaded cells located on

worksheets with green tab colors. All other worksheets are password protected to protect the integrity

of critical formulas contained within each. Modifications to the model outside of the yellow shaded cells

may result in false or misleading results.

The following worksheets are available for modification by the user:

1. Plant Operations: defines the amount of time in hours per day and days per week the plant is

required to operate to meet the host’s demands (capacity factor). These inputs drive the

operating expenses and revenue calculations.

2. Financial Inputs: allows the user to define key variables associated with project financing.

Examples include; % debt, interest rate, term, property taxes, etc.

3. Commodity Inputs: defines the starting values for developing forward price curves for key

commodities necessary for project development and operations. Items such as fuel costs,

energy costs, and labor rates can be specified. These values create the “Year 1” commodity

values used in the cash flow analysis.

Regardless of the location, size, or type of natural gas‐related project evaluated the Refined Feasibility

Model is intended as a planning tool only; it is not intended for use in making investment decisions.

Prior to making final investment decisions we recommend completing a more detailed due diligence

assessment of the proposal to confirm key drivers of performance (e.g., regulatory requirements, cost

estimates, property taxes in the specific municipality, actual lenders’ requirements, etc.) and overall

feasibility.

8


Model Structure The Refined Feasibility Model is structured to perform discounted cash flow analysis on natural gas fired

generation and thermal assets. As noted above the model also has the flexibility to incorporate other

natural gas‐related products and services such as CNG into the analysis.

The model is a spreadsheet based tool which utilizes key variable inputs from several worksheets to

model the capital costs, evaluate project electrical and thermal performance and operating expenses.

These data are then automatically fed to individual cash flow analysis worksheets. Economic results

from each cash flow worksheet are summarized on the Executive Summary and Detailed Summary tabs.

The model structure is generally illustrated below, additional detail on key inputs associated with each

“box” in the graphic below are described in more detail in the next section.

9


Key Inputs The Refined Feasibility Model contains both adjustable (user defined) and fixed (pre‐determined)

variables. Fixed variables represent technical data primarily related to equipment performance

(obtained from vendors) as well as capital and operating expenses (engineer’s cost estimates). Fixed

variables are contained on password protected worksheets to prevent inadvertent modification or

alteration of key values and/or their associated formula linkages to other worksheets which are critical

to the proper functioning of the model.

The following worksheets are protected from editing (without the password), however are available to

view:

1. Executive Summary: provides a printable summary of the economic performance of all nine

alternatives based on the model input settings.

2. Detailed Summary: provides a detailed summary of economic performance as well as key input

variable settings.

3. Performance Characteristics: equipment performance characteristics including; equipment

costs, heat rate, electrical and thermal capacities, as well as O&M requirements.

4. O&M: documents variable O&M values for each equipment alternative and availability.

5. Forward Pricing: projects commodity values over the 30‐year term of the study.

6. Sources of Funds: documents the distribution of capital costs among equity, debt and grant

categories based on user defined inputs.

7. Plant Operations (Alts 1‐9): individual worksheets for each alternative describing the annual

plant performance characteristics such as; electrical generation, thermal products, overhaul

intervals, etc.

8. Cash Flow Analysis (Alts 1‐9): discounted cash flow analysis worksheets for each alternative.

These analyses dynamically update automatically based on user defined inputs.

9. Cost Estimates – Combined Cycle (Alts 1‐9): engineer’s cost estimates of capital costs to

develop the project including; permitting, engineering and construction when “Combined Cycle”

is selected as the operating mode by the user.

10. Cost Estimates – Simple Cycle (Alts 1‐9): engineer’s cost estimates of capital costs to develop

the project including; permitting, engineering and construction when “Simple Cycle” is selected

as the operating mode by the user.

Key user defined model inputs are adjusted by modifying the values in yellow shaded cells located on

the following worksheets/tabs:

1. Plant Operations

2. Financial Inputs

3. Commodity Inputs

Input variables available on each of these worksheets are described in more detail below.

10


The following input variables which can be defined by the user are located on the “Plant Operations”

tab:

1. Duct Firing (Yes/No): specify the inclusion of duct firing (Heat Recovery Steam Generator

[HRSG]) using the built in drop down menu. Duct firing is typically used to supplement steam

generation for relatively short durations by injecting natural gas into the exhaust path. While

this option can boost production it results in reduced fuel consumption efficiency (trade off).

2. Include Gas Interconnection Costs (Yes/No): specify whether to include the costs to provide the

necessary natural gas interconnection and/or associated facilities (compression) in the

economic analysis. This is selected using the built in drop down menu. Note – these costs can be

adjusted on the Financial Inputs worksheet. Current values are specific to the Beecher Falls

study site and should be revisited if evaluating an alternative location.

3. Operating Mode (Simple Cycle/ Combined Heat and Power): use the built‐in drop down menu

to select the equipment’s operating mode. The capital and operating costs differ depending on

the operating mode selected.

a. Simple Cycle: simple cycle operations do not capture the waste heat energy in exhaust

b. Combined Heat and Power (CHP): Steam generated with the waste heat is used for

industrial process, heating or cooling. Collectively, these three applications are referred

to as the thermal load. In facilities where the thermal load is highly variable duct firing

may be used to increase steam production; or when the thermal load drops off a small

steam turbine generator used to produce additional electricity.

4. Fuel Sales (mmBTU/yr): enter the

volume (mmBTU/yr) of natural gas

sold if fuel sales are anticipated as a

revenue source.

5. Other Revenue ($1,000’s/yr):

placeholder for

additional/miscellaneous revenues.

6. Plant Availability (typical hours/day):

used to specify the demand for CHP

services. For a CHP application this

would typically follow the hours of

operation (shifts). The model is set up

to automatically calculate annual

availability (capacity factor) based on

the selected hours of operation for a

typical week. Refinements can be

made to reflect weekday and

weekend operations.

11


The following input variables which can be defined by the user are located on the “Financial Inputs” tab:

2. General Escalation: annual increase in cost of goods. Generally reflects the anticipated rate of

inflation. Over the last 10 + years escalation has ranged from 2% to over 10%. In recent years

escalation has been in the range of 2% to 2.5%.

12. Energy Escalation: annual increase in the cost of energy. In the Northeast, where the primary

sources of generation are natural gas plants, energy costs track closely with natural gas prices.

Since the economic recession of 2008 energy costs have fallen for two reasons 1) a slowdown in

the economy reduced demand, and 2) insurgence of domestic natural gas production has

created a supply glut reducing gas costs.

13. Fuel Escalation: annual increase in the cost of fuel. Development of domestic natural gas plays

(such as those in the Marcellus Shale formation) have created a supply glut driving down natural

gas costs over the past few years. However, concerns over potential environmental impacts

associated with the extraction process increase uncertainty of future gas pricing.

Note – energy and fuel escalation is separated from general escalation to allow greater flexibility in

evaluating scenarios with disparate commodity escalations.

1. Discount Rate: the opportunity cost of the capital invested at the outset of the project which is

not available for other purposes. It can be conceptualized as a “reverse interest rate”.

2. Grant: % of capital costs which may be available as grants to reduce the initial investment.

3. Percent Debt: percentage of total capital costs which would be financed.

4. Interest Rate: interest paid on financed portion of capital costs.

5. Term: duration of the financing arrangement.

6. Depreciation Term: some energy projects are eligible for special tax depreciation terms. The

duration of such programs can be adjusted here.

14. Investment Tax Credit (ITC): Federal incentive program which currently allows up to 10% of CHP

capital costs to be recovered through a one‐time tax credit.The availability and eligibility criteria

for this Federal program are very dynamic and should be verified prior to evaluating

alternatives.

15. Combined Fed. + State Tax Rate: annual tax burden for the project, expressed as a percentage

of capital costs.

7. Commercial Operation Date: year the project is anticipated to be complete and operable.

Adjusting this value will adjust the initial capital and commodity costs according to the defined

escalation rates used in the cash flow analysis.

8. Insurance Rate: annual insurance premium based on % of investment costs to cover.

9. Natural Gas Interconnection Costs: capital costs to provide natural gas interconnection and/or

associated facilities. For the Beecher Falls model the natural gas interconnection cost estimate

was provided by Northstar Industries, Inc. and is specific to this location. These costs are site

12


specific. If the model is used to evaluate different locations the natural gas interconnection costs

should be revisited.

Instructions The refined feasibility model can be used to evaluate the potential for a particular natural gas‐related

project to provide economic benefits. Data specific to the potential project are entered by the user on

the Plant Operations, Financial Inputs and Commodity Inputs worksheets (as described above).

Users are cautioned to verify that all input data reflect the investment and commodity cost structure as

accurately as possible.

Results and Interpretation Guidance

After the input settings are updated to reflect the specifics of the opportunity the model will

automatically generate indicators of the project’s economics. The following provides guidance on

interpreting model results provided on the “Executive Summary” and/or the “Detailed Summary” tabs

of the workbook.

Executive Summary Tab Results 3. No. (Number): numerical identifier for each alternative.

4. Alternative: brief description of the alternative based on the selected equipment package.

5. Installed Capacity (MW): net installed electrical capacity of the alternative.

6. Net Generation (MWH): estimate of net annual electrical production based on the selected

input parameters (availability, etc.).

7. As‐Run Heat Rate (yr 1): measure of the amount of heat required to generate one kilowatt of

electricity. This can be thought of as fuel efficiency for power plants. Heat rate degradation

occurs as a function of run hours and informs the requirements for overhauls. Heat rate

degradation is actually an increase in the heat rate – accounting for losses in fuel conversion

efficiency from normal wear and tear resulting in the requirement for additional fuel and heat to

produce the same amount of energy.

8. Operating Mode: indicates the selected plant Operating Mode (Simple Cycle or Combined Heat

and Power).

9. Total Estimated Costs ($1,000’s): estimated initial investment to develop the project. Costs

include provisions for engineering, design, permitting, equipment procurement, construction, &

start‐up.

10. Installed Costs Electrical ($/kw): estimated initial investment costs to develop the project on a

dollar per unit of installed electrical generating capacity.

11. Capacity Factor: % of time on an annual basis that the alternative is operating at its full installed

capacity.

12. Running Costs Electrical ($/kwh): the project’s cost to produce one kwh of electrical energy.

This metric is useful in comparing the potential benefits of self‐generation with purchasing

energy from the grid.

13. Running Cost Steam ($/ton): the project’s cost to produce one ton of steam energy.

13


14. IRR – Internal Rate of Return (IRR): is used to measure and compare the profitability of

projects. The IRR on an investment or project is the discount rate that makes the NPV of all cash

flows from a particular project equal to zero. When the IRR is greater than the discount rate the

project is anticipated to produce economic benefits.

15. Cumulative NPV (Net Present Value) ($1,000’s): a measure of how much value an investment

provides to the investor. Cumulative NPV represents the current worth of a future sum of

money or stream of cash flows given a specified rate of return. Future cash flows are discounted

at the discount rate. Generally, the higher the discount rate, the lower the present value of the

future cash flows. NPV is different from IRR, because NPV calculations use discounted cash flow

to quantify, in today's dollar terms, the projected net gain from the project in net dollar terms.

Detailed Summary Tab Results The following results are provided on the Detailed Summary tab in addition to those noted above for the

Executive Summary tab. The detailed summary provides the user with a quick reference of key input

settings as well as summarizing the results of the analysis. To avoid duplication only those result fields

which are not described for the Executive Summary are outlined below.

1. Duct Firing: indicates the user selected setting (on the Plant Operations tab) regarding the

provision of duct firing.

2. Include Gas Interconnection Costs: indicates the user selected setting on whether or not to

include the gas interconnection costs in the economic analysis. The current value ($2M)

represents the estimated cost of interconnection to the Beecher Falls study site. If another site

is being evaluated this estimate will need to be revisited.

3. Fuel Sales (mmBTU): annual volume of natural gas re‐sold by the project. A value in this cell

indicates that natural gas fuel will be sold by the project to a third party.

4. Other Revenue ($1,000’s/yr): indicates the annual value of non‐generation related revenues.

This field was created as a placeholder in the event that an additional revenue stream is

available.

5. Plant Availability ‐ Days of the Week, Run Hours/Year & Capacity Factor: indicates the user

selected settings for plant availability. The data are displayed as follows:

a. Days of the Week: typical operations schedule broken down by days of the week.

b. Run Hours/Yr: extrapolated hours per year operations based on user selected days of

the week settings.

c. Capacity Factor: annual % of time the plant is operating at capacity.

6. Fuel Consumption (mmBTU/yr): annual volume of fuel consumed by the project to meet the

specified plant operations criteria. This value does not include fuel purchased for retail

purposes.

7. Financial Input Settings: summary of adjustable financial variables used in the economic

analysis.

8. Commodity Input Settings: summary of adjustable commodity variables used in the economic

analysis.

14


9. Commodity Pricing – Forward Outlook (graph): graphical representation of the trend in

commodity pricing outlook over the study period based on the user specified starting value and

associated escalation rates.

Interpretation Guidance Interpretation of modeling results requires a working knowledge of the economic performance metrics

and factors which influence them. Typically, the IRR and NPV are used as high‐level indicators of the

potential value of the investment taking investment, operations, revenues and financing into account.

However, when considering the potential benefits of a CHP application other factors, such as the cost to

produce energy, need to be considered. For example, if a customer can purchase energy from the grid at

a lower cost than self‐producing, the impetus for the investment becomes less obvious. In some

instances corporate branding or other less tangible factors may be the drivers of the investment

decision. Ultimately, the decision will be based on the investment profile and tolerance for risk of the

potential customer.

In general, projects which are estimated to produce an IRR greater than or equal to the specified

discount rate are considered to provide economic benefits. By definition (Investopedia), the IRR is

the discount rate that makes the NPV of all cash flows from a particular project equal to zero. When the

IRR is greater than the discount rate the project is anticipated to produce economic benefits.

Conceptually, IRR is the rate of growth a project is expected to generate. While the actual rate of return

that a given project ends up generating will often differ from its estimated IRR rate, a project with a

substantially higher IRR value than other available options would still provide a much better chance of

strong growth.

There are some nuances to interpreting these results and indicators which should be considered in the

context of the proponent’s investment profile. The following examples illustrate the evolution of the

NPV for three hypothetical projects, each with the same IRR (15%) but cumulative NPV’s ranging from

$5M to $20M. Each is discussed in more detail below.

15


Ex. 1: IRR = 15%, Cumulative NPV = $20M

Explanation: The example above illustrates how a project with an 18‐year payback period (when the NPV becomes positive) can still have a relatively high cumulative NPV. This type of result may reflect specifics of the financing structure, anticipated trends in commodity prices or other factors which influence overall project cash position. In this situation the investor is required to assume the risk that the factors which are anticipated to drive positive NPV will come to fruition. In a situation where future commodity pricing (which is highly volatile) is identified as the primary driver of value this risk needs to be carefully evaluated.

16



Explanation: Comparing the example above with example 1, there is the potential for a trade‐off in cumulative NPV to realize a shorter payback period. Note that the maximum penalty for this example is approximately $10M in year 8 of the study period, as opposed to a $12M penalty in year 13 of example 1. As discussed in Example 1 explanation, there are several factors which can influence the shape of the NPV curve.

17



Explanation: The example above illustrates a situation where the investor would assume relatively less risk than that required in examples 1 & 2 (maximum penalty of $5M in year 3 of the study). The tradeoff is that the cumulative NPV is $5M, in comparison to $20M or $12M as illustrated in examples 1 & 2, respectively.

18

SCREENING TOOL

Beecher Falls Energy Park Screening Tool Input / Summary

Alternative

Description/Notes

YearCumulative

NPV ($1,000's)IRR

Engineering & Permitting 100 2013 (1,575) #NUM!

Site Development 200 2015 (1,083) ‐29%

Electrical Plant 2000 2017 (638) ‐6%

Thermal Plant 300 2022 292 11%

Gas Facilities 2000 2027 1,001 16%

Interconnection 100 2032 1,530 17%

Other 0 2042 2,754 18%

Grants (subtracted from total) 100

Total Initial Investment 4,600

Units QuantityYr‐1 Rate/

Amount

O&M (including labor) $1,000's 1 700

Property Taxes (default, 1% of initial investment) % 1 1.0%

Insurance (default, 0.5% of initial investment) % 1 0.5%

Other $1,000's 1 50

Natural gas purchases, delivered price mmBTU 225,000 7.00

Cost of other commodities purchased, delivered price User Defined 1,000 1.00

Item

Initial Investment (2012 $1,000's)

Base Case

Initial Settings

Investment Data Performance Projections

Annual Data

Cost of other commodities purchased, delivered price User Defined 1,000 1.00

Electricity sold MWH 12,000 100.00

Steam sold Tons 13,000 7.50

Hot water sold Tons 500,000 1.00

Natural gas sold mmBTU 100,000 12.00

Other commodity sold User Defined 1,000 2.00

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

0 5 10 15 20 25 30$1,000's

Year

Cumulative Net Present Value

Cum NPV

For Planning Purposes Only NCIC Screening Tool_3‐22‐12.xlsx

Beecher Falls Energy Park Screening Tool Financial Inputs

Financial Variables

No. Item Name Value Comments/Instructions

1 General Escalation gex 2.5% Allowance

2 Energy Escalation eex 2.5% Allowance

3 Fuel Escalation fex 2.5% Allowance

4 Discount Rate drx 8.0% Present value of future cash flows; conceptually = Interest Rate in Reverse

5 Grant grt 10% Allowance

6 Percent Debt pdx 50% Allowance

7 Interest Rate irx 10.0% Allowance

8 Term (Yrs) ter 20 Allowance

9 Depreciation Term dep 20 Allowance ‐ Other options may be available (i.e., MACRES)

10 Investment Tax Credit itc 10% Eligibility, efficiency & In‐service deadline criteria apply.

11 Combined Fed + State Tax Rate itx 40% Allowance

12 Commercial Operation Date cod 2012 Enter anticipated year of need to escalate cost & revenue estimates

Notes/Instructions:

1 Financial variable inputs are used to define the financial environment in Year 0 of the model study.

Enter Data ONLY in Yellow Shaded Cells


Beecher Falls Energy Park Screening Tool Cashflow Analysis

Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Base CaseInitial Settings

No Item

1 Costs ($1,000's)

a Initial Investment 4,600

b O&M 700 718 735 754 773 792 812 832 853 874 896 918 941 965 989 1,014

c Other O&M 50 51 53 54 55 57 58 59 61 62 64 66 67 69 71 72

d Gas Fuel Purchased 1,575 1,614 1,655 1,696 1,739 1,782 1,827 1,872 1,919 1,967 2,016 2,067 2,118 2,171 2,225 2,281

e Other Commodity Purchased 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

f Property Taxes 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23

g Insurance 46 47 48 50 51 52 53 55 56 57 59 60 62 63 65 67

h Total Cost 2,454 2,515 2,577 2,641 2,707 2,774 2,843 2,913 2,985 3,059 3,135 3,213 3,293 3,375 3,458

2 Revenues ($1,000's)

a Electricty Sales 1,200 1,230 1,261 1,292 1,325 1,358 1,392 1,426 1,462 1,499 1,536 1,575 1,614 1,654 1,696 1,738

b Steam Sales 98 100 102 105 108 110 113 116 119 122 125 128 131 134 138 141

c Hot Water Sales 500 513 525 538 552 566 580 594 609 624 640 656 672 689 706 724

d Natural Gas Sales 1,200 1,230 1,261 1,292 1,325 1,358 1,392 1,426 1,462 1,499 1,536 1,575 1,614 1,654 1,696 1,738

e Other Sales 2 2 2 2 2 2 2 2 2 2 3 3 3 3 3 3

f Placeholder

g Total Revenues 3,074 3,151 3,230 3,311 3,394 3,479 3,565 3,655 3,746 3,840 3,936 4,034 4,135 4,238 4,344

3 Debt Service 2,300

a Principal 40 44 49 53 59 65 71 78 86 95 104 115 126 139 152

b Interest 230 226 222 217 211 205 199 192 184 175 166 156 144 132 118

c Total Debt Service 270 270 270 270 270 270 270 270 270 270 270 270 270 270 270

4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt 620 636 653 670 687 705 723 742 761 780 800 821 842 864 886

b Interest Payment (230) (226) (222) (217) (211) (205) (199) (192) (184) (175) (166) (156) (144) (132) (118)

c Depreciation (230) (230) (230) (230) (230) (230) (230) (230) (230) (230) (230) (230) (230) (230) (230)

d Taxable Income 160 180 201 223 246 269 294 320 347 375 404 435 468 502 538

e Fed & State Taxes 64 72 80 89 98 108 118 128 139 150 162 174 187 201 215

5 Cash Flows ($1,000's)


b Fed & State Income Tax (64) (72) (80) (89) (98) (108) (118) (128) (139) (150) (162) (174) (187) (201) (215)

c Debt Service (270) (270) (270) (270) (270) (270) (270) (270) (270) (270) (270) (270) (270) (270) (270)

d Cash after Taxes & Debt 286 294 302 310 319 327 335 344 352 360 368 377 385 393 400

6 Debt Coverage Ratio 2.1 2.1 2.1 2.1 2.2 2.2 2.2 2.3 2.3 2.3 2.4 2.4 2.4 2.5 2.5

7 Financial Calculations ($1,000's)

a Investment Tax Credits 460

b Equity 2,300

c Residual

d Cash after Taxes & Debt (1,840) 286 294 302 310 319 327 335 344 352 360 368 377 385 393 400

e NPV (1,840) 265 252 240 228 217 206 196 186 176 167 158 150 141 134 126

f Cum NPV (1,840) (1,575) (1,323) (1,083) (855) (638) (432) (237) (51) 125 292 450 599 741 874 1,001

g IRR 18% #NUM! #NUM! ‐29% ‐15% ‐6% 0% 4% 7% 10% 11% 13% 14% 14% 15% 16%


Beecher Falls Energy Park Screening Tool Cashflow Analysis

Study Year

Calendar Year

Base CaseInitial Settings

No Item

1 Costs ($1,000's)

a Initial Investment

b O&M

c Other O&M

d Gas Fuel Purchased

e Other Commodity Purchased

f Property Taxes

g Insurance

h Total Cost


a Electricty Sales

b Steam Sales

c Hot Water Sales

d Natural Gas Sales

e Other Sales

f Placeholder

g Total Revenues

3 Debt Service

a Principal

b Interest

c Total Debt Service

4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt

b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes



b Fed & State Income Tax

c Debt Service

d Cash after Taxes & Debt

6 Debt Coverage Ratio


a Investment Tax Credits

b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,039 1,065 1,092 1,119 1,147 1,176 1,205 1,235 1,266 1,298 1,330 1,363 1,398 1,432 1,468

74 76 78 80 82 84 86 88 90 93 95 97 100 102 105

2,338 2,397 2,456 2,518 2,581 2,645 2,711 2,779 2,849 2,920 2,993 3,068 3,144 3,223 3,304

1 2 2 2 2 2 2 2 2 2 2 2 2 2 2

23 23 23 23 23 23 23 23 23 23 23 23 23 23 23

68 70 72 74 75 77 79 81 83 85 87 90 92 94 96

3,544 3,632 3,723 3,815 3,910 4,007 4,107 4,209 4,313 4,421 4,530 4,643 4,759 4,877 4,998

1,781 1,826 1,872 1,918 1,966 2,015 2,066 2,118 2,170 2,225 2,280 2,337 2,396 2,456 2,517

145 148 152 156 160 164 168 172 176 181 185 190 195 200 205

742 761 780 799 819 840 861 882 904 927 950 974 998 1,023 1,049

1,781 1,826 1,872 1,918 1,966 2,015 2,066 2,118 2,170 2,225 2,280 2,337 2,396 2,456 2,517

3 3 3 3 3 3 3 4 4 4 4 4 4 4 4

4,453 4,564 4,678 4,795 4,915 5,038 5,164 5,293 5,425 5,561 5,700 5,842 5,988 6,138 6,292

168 185 203 223 246 0 0 0 0 0 0 0 0 0 0

102 86 67 47 25 0 0 0 0 0 0 0 0 0 0

270 270 270 270 270 0 0 0 0 0 0 0 0 0 0

909 932 956 980 1,005 1,031 1,057 1,084 1,112 1,140 1,169 1,199 1,230 1,261 1,293

(102) (86) (67) (47) (25) 0 0 0 0 0 0 0 0 0 0

(230) (230) (230) (230) (230) 0 0 0 0 0 0 0 0 0 0

576 616 659 703 751 1,031 1,057 1,084 1,112 1,140 1,169 1,199 1,230 1,261 1,293

230 246 263 281 300 412 423 434 445 456 468 480 492 504 517

909 932 956 980 1,005 1,031 1,057 1,084 1,112 1,140 1,169 1,199 1,230 1,261 1,293

(230) (246) (263) (281) (300) (412) (423) (434) (445) (456) (468) (480) (492) (504) (517)

(270) (270) (270) (270) (270) 0 0 0 0 0 0 0 0 0 0

408 415 422 429 435 619 634 651 667 684 702 720 738 757 776

2.5 2.5 2.6 2.6 2.6 NA NA NA NA NA NA NA NA NA NA

2,412

408 415 422 429 435 619 634 651 667 684 702 720 738 757 3,188

119 112 106 99 93 123 117 111 105 100 95 90 86 81 317

1,120 1,232 1,337 1,437 1,530 1,653 1,770 1,880 1,986 2,086 2,180 2,270 2,356 2,437 2,754

16% 16% 17% 17% 17% 17% 17% 18% 18% 18% 18% 18% 18% 18% 18%


Beecher Falls Energy Park Screening Tool Forward Pricing

Study Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

No Item

1 Nat Gas Costs ($/mm/BTU) 7.00 7.18 7.35 7.54 7.73 7.92 8.12 8.32 8.53 8.74 8.96 9.18 9.41 9.65 9.89

2 Retail Energy ($/MWH) 100.00 102.50 105.06 107.69 110.38 113.14 115.97 118.87 121.84 124.89 128.01 131.21 134.49 137.85 141.30

3 Steam Sold ($/Ton) 7.50 7.69 7.88 8.08 8.28 8.49 8.70 8.92 9.14 9.37 9.60 9.84 10.09 10.34 10.60

4 Hot Water Sold ($/Ton) 1.00 1.03 1.05 1.08 1.10 1.13 1.16 1.19 1.22 1.25 1.28 1.31 1.34 1.38 1.41

5 Nat Gas Sales ($/mmBtu) 12.00 12.30 12.61 12.92 13.25 13.58 13.92 14.26 14.62 14.99 15.36 15.75 16.14 16.54 16.96

6 Other Commodity Costs ($/Unit) 1.00 1.03 1.05 1.08 1.10 1.13 1.16 1.19 1.22 1.25 1.28 1.31 1.34 1.38 1.41

7 Other Commodity Sales ($/Unit) 2.00 2.05 2.10 2.15 2.21 2.26 2.32 2.38 2.44 2.50 2.56 2.62 2.69 2.76 2.83

Retail Energy ($/MWH)

100.00

150.00

200.00

250.00

$/M

WH

gy ($/ )

0.00

50.00

1 6 11 16 21 26 31

Year

Retail Energy ($/MWH)


Beecher Falls Energy Park Screening Tool Forward Pricing

Study Year

Calendar Year

No Item

1 Nat Gas Costs ($/mm/BTU)

2 Retail Energy ($/MWH)

3 Steam Sold ($/Ton)

4 Hot Water Sold ($/Ton)

5 Nat Gas Sales ($/mmBtu)

6 Other Commodity Costs ($/Unit)

7 Other Commodity Sales ($/Unit)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

10.14 10.39 10.65 10.92 11.19 11.47 11.76 12.05 12.35 12.66 12.98 13.30 13.63 13.98 14.32 14.68

144.83 148.45 152.16 155.97 159.87 163.86 167.96 172.16 176.46 180.87 185.39 190.03 194.78 199.65 204.64 209.76

10.86 11.13 11.41 11.70 11.99 12.29 12.60 12.91 13.23 13.57 13.90 14.25 14.61 14.97 15.35 15.73

1.45 1.48 1.52 1.56 1.60 1.64 1.68 1.72 1.76 1.81 1.85 1.90 1.95 2.00 2.05 2.10

17.38 17.81 18.26 18.72 19.18 19.66 20.15 20.66 21.18 21.70 22.25 22.80 23.37 23.96 24.56 25.17

1.45 1.48 1.52 1.56 1.60 1.64 1.68 1.72 1.76 1.81 1.85 1.90 1.95 2.00 2.05 2.10

2.90 2.97 3.04 3.12 3.20 3.28 3.36 3.44 3.53 3.62 3.71 3.80 3.90 3.99 4.09 4.20

Retail Non‐Energy Commodities ($/Unit)

10.00

15.00

20.00

25.00

30.00

$/U

nit

Retail Non Energy Commodities ($/Unit)

0.00

5.00

1 6 11 16 21 26 31

Year

Nat Gas Costs ($/mm/BTU) Steam Sold ($/Ton) Hot Water Sold ($/Ton)

Nat Gas Sales ($/mmBtu) Other Commodity Costs ($/Unit) Other Commodity Sales ($/Unit)


ECONOMIC FEASIBILITY MODEL

Beecher Falls Energy Park Economic Feasibility Model Use & Limitations

PLEASE READ ‐ INSTRUCTIONS FOR USE & LIMITATIONS

This screening tool has been developed to provide high‐level assessment of the potential benefits of a gas fired Combined Heat and Power (CHP) facility.

Typically CHP facilities are sized to meet the energy profile of a specific host. This tool is intended to back calculate the energy profile necessary to provide

the desired benefits to an unidentified/potential host. Conceptually, the results of the tool could be used to define host criteria which would inform efforts

to attract a host (or hosts) that satisfy the feasibility thresholds.

Planning level data were used to develop the tool. The results are not intended to be used to make investment decisions.

User's of this tool may modify certain key financial inputs using the yellow cells on the green tabs. The "Executive Summary" tab provides a summary of

model results only. The "Detailed Summary" tab provides a more comprehensive summary of model input assumptions and results. Both summary tabs

have been formatted to be "print ready".

All of the formulas contained in this file have been protected to help prevent unintended modifications and potentially mis‐leading or inaccurate results.

Protected worksheets are identified by red tabs.

Additional information on model development and proper use can be obtained by contacting:

The Essex Partnership, LLC

860‐581‐8111

401‐619‐4872

www.essexpartnership.com

For Planning Purposes Only NCIC_Economic Feasibility Model_3‐22‐12.xlsx

Executive and Detailed Summaries

Beecher Falls Energy Park Economic Feasibility Model Executive Summary

1 2 3 4 5 6 7 8 9 10 11 12 13

No. Alternative

Installed

Capacity

(MW)

Net Generation

(MWH)

As‐Run Heat

Rate

(yr 1)

Operating Mode

Total

Estimated Costs

($1,000's)

Installed

Costs

Electrical

($/kW)

Capacity

Factor

Running

Cost

Eletrical

(¢/kWH)

Running Cost

Steam ($/Ton)IRR

Cumulative

NPV

($1,000s)

1 (1) Caterpillar G3520 2.1 18,001 10,537 Combined Heat and Power 6,106 2,971 100% 7.2 N/A #DIV/0! (8,246)

2 (5) Caterpillar G3520 10.3 53,574 10,523 Simple Cycle 17,430 1,696 60% 7.2 N/A 9% 837

3 (1) Solar Mercury 50 4.5 39,313 9,999 Simple Cycle 11,726 2,613 100% 6.9 N/A #DIV/0! (5,903)

4 (3) Solar Mercury 50 13.5 77,221 9,987 Simple Cycle 26,457 1,965 65% 6.9 N/A 9% 825

5 (1) Solar Taurus 60 5.5 48,204 12,234 Simple Cycle 10,675 1,940 100% 8.3 N/A #DIV/0! (14,952)

6 (3) Solar Taurus 60 16.5 110,180 12,243 Simple Cycle 22,931 1,389 76% 8.3 N/A 9% 1,315

7 (1) Solar Taurus 70 7.7 67,834 11,269 Simple Cycle 12,568 1,623 100% 7.7 N/A 10% 1,306

8 (2) Solar Taurus 70 15.5 80,754 11,253 Simple Cycle 20,602 1,330 60% 7.7 N/A 9% 939

9 (1) Solar Titan T130 14.5 63,375 10,962 Simple Cycle 16,155 1,116 50% 7.5 N/A 8% 29

Notes:

1 Net Electrical Output is at ISO conditions.

2 Net Electrical Output for the combustion turbine options at summer conditions will be approximately 10% lower.

3 Equipment prices and performance based on indicative vendor quotes.

4 Cost estimates for site work, auxiliary electrical, auxiliary mechanical and administration are based on recent experience for similar projects.

5 Cost estimates include: 5% contigency on the Engine/Generator; 20% contingency on the balance of plant (BOP) and site work; and a 15% allowance for AFUDC.

6 Cost estimates include a $400,000 allowance for permitting, based on recent experience with similar projects in Vermont.

7 Cost of land acquisition, gas pipeline interconnection, metering or compression/pressure reduction facilities are not included.

8 Annual run hours determined by user inputs located on the Plant Operations tab.

9 Fixed O&M costs include provisions for labor associated with plant operations; these costs are adjusted based on user specified plant availability (run hours).

10 Variable O&M includes cost of consumables, minor and major maintenance overhauls.

11 Categories for Fixed and Variable O&M $/kWh for "Simple" and "Combined Cycle" reflect the relative O&M complexity of each technology.

12 Caterpillar steam @ 20 psig; all other options at 150 psig.

13 Steam production costs represent the incremental cost of the heat recovery system and a variable cost component for consummables equivalent to 1/2 ¢/kWH.


Beecher Falls Energy Park Economic Feasibility Model Detailed Summary

Plant Operations Settings

No. Alternative

Installed

Capacity

(MW)

Net

Generation

(MWH)

Operating ModeDuct

Firing

Include Gas

Interconnection

Costs

Total

Estimated

Costs

($1,000's)

Installed

Costs

Electrical

($/kW)

Fuel Sales

(mmBTU)

Other Revenue

($1,000s/yr)Mon Tue Wed Thu Fri Sat Sun

Run

Hours/Y

ear

Capacity

FactorGeneration Duct Firing Total

Running

Cost

Eletrical

(¢/kWH)

Running

Cost

Steam

($/Ton)

IRR

Cumulative

NPV

($1,000s)

1 (1) Caterpillar G3520 2.1 18,001 Combined Heat and Power No Yes 6,106 2,946 ‐ ‐ 24 24 24 24 24 24 24 8,760 100% 189,681 ‐ 189,681 7.2 N/A #DIV/0! (8,246)

2 (5) Caterpillar G3520 10.3 53,574 Simple Cycle No Yes 17,430 1,691 ‐ ‐ 8 12 16 16 16 16 16 5,214 60% 563,735 ‐ 563,735 7.2 N/A 9% 837

3 (1) Solar Mercury 50 4.5 39,313 Simple Cycle No Yes 11,726 2,601 ‐ ‐ 24 24 24 24 24 24 24 8,760 100% 393,072 ‐ 393,072 6.9 N/A #DIV/0! (5,903)

4 (3) Solar Mercury 50 13.5 77,221 Simple Cycle No Yes 26,457 1,961 ‐ ‐ 14 16 16 16 16 16 16 5,735 65% 189,681 ‐ 189,681 6.9 N/A 9% 825

5 (1) Solar Taurus 60 5.5 48,204 Simple Cycle No Yes 10,675 1,930 ‐ ‐ 24 24 24 24 24 24 24 8,760 100% 189,681 ‐ 189,681 8.3 N/A #DIV/0! (14,952)

6 (3) Solar Taurus 60 16.5 110,180 Simple Cycle No Yes 22,931 1,386 ‐ ‐ 24 24 16 16 16 16 16 6,674 76% 189,681 ‐ 189,681 8.3 N/A 9% 1,315

7 (1) Solar Taurus 70 7.7 67,834 Simple Cycle No Yes 12,568 1,616 ‐ ‐ 24 24 24 24 24 24 24 8,760 100% 189,681 ‐ 189,681 7.7 N/A 10% 1,306

8 (2) Solar Taurus 70 15.5 80,754 Simple Cycle No Yes 20,602 1,327 ‐ ‐ 8 12 16 16 16 16 16 5,214 60% 189,681 ‐ 189,681 7.7 N/A 9% 939

9 (1) Solar Titan T130 14.5 63,375 Simple Cycle No No 16,155 1,089 ‐ ‐ 8 8 8 12 16 16 16 4,380 50% 189,681 ‐ 189,681 7.5 N/A 8% 29

Financial Input Settings

No. Item Value Comments

1 General Escalation 2.5% Allowance

2 Energy Escalation 2.5% Allowance

3 Fuel Escalation 2.5% Allowance

4 Discount Rate 8.0% Allowance

5 Grant 10% Allowance

6 Percent Debt 50% Allowance

7 Interest Rate 5.0% Allowance

8 Term (Yrs) 20 Allowance

9 Depreciation Term 20 Allowance ‐ Other options may be available (i.e., MACRES)

10 Investment Tax Credit 10% Eligibility, efficiency & In‐service deadline criteria apply. See

11 Combined Fed + State Tax Rate 40% Allowance

12 Property Tax Rate (% of Invest. Cost) 1.0% Allowance

13 Commercial Operation Date 2012 Enter anticipated year of need to escalate cost & revenue estimates

14 Insurance Rate (% of Invest. Cost) 0.5% Allowance

Commodity Input Settings Note: Chart will update based on values on Commodity Inputs tab

Plant Run Hours (typical hrs/day)

Note to Users: This sheet provides a snapshot of key model inputs and results. The values on this tab automatically update based on selections made on specificed input tabs. It is intended to provide a detailed summary of the modeling assumptions and associated results.

It is not designed for adjusting model inputs.

Fuel Consumption (mmBTU/yr)

6

8

10

12

14

60

80

100

120

140

160

$/m

mBTU

(gas only)

$'s/M

WH

($/kW‐yr, FCM only)

Commodity Pricing ‐ Forward Outlook

No. Item Value Comments

1 Gas ($/mmBtu) 6.00 Enter year 1 forward pricing value

2 Energy ($/MWH) 70 Enter year 1 forward pricing value

3 Avoided Distribution ($/MWH) 30 Enter year 1 forward pricing value

4 FCM ($/kW‐Yr) 24.00 Enter year 1 forward pricing value

5 Credits/RECs ($/MWH) 0 Enter year 1 forward pricing value

6 Steam ($/Ton) 7.50 Enter year 1 forward pricing value

7 Fuel Sales ($/mmBTU) 8.00 Enter year 1 forward pricing value

8 Other 0.00 Enter year 1 forward pricing value

9 Labor Rate ‐ Plant Mgr. / Opr. ($/hr) 40 Labor costs for plant operations

10 Labor Rate ‐ Plant Opr. / Mech. ($/hr) 30 Labor costs for plant operations (CC & Add'l Shifts)

11 Labor Overhead Multiplier (%) 1.4 Labor overhead multiplier

12 Night & Weekend Labor Rate Premium 1.2 Shift work premium

0

2

4

0

20

40

2012 2017 2022 2027 2032 2037 2042

Calendar Year

Energy ($/MWH) Avoided Distribution ($/MWH) FCM ($/kW‐Yr) Credits/RECs ($/MWH)

Steam ($/Ton) Retail Fuel Sales ($/mmBtu) Other Gas ($/mmBtu)


User Defined Input Tabs:

• Plant Operations

• Financial Inputs

• Commodity Inputs

Beecher Falls Energy Park Economic Feasibility Model Plant Operations


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

No. Alternative

Installed

Capacity

(MW)

Net Generation

(MWH)

Duct

Firing

Include Gas

Interconn. CostOperating Mode

Total

Estimated

Costs

($1,000's)

Installed

Costs

Electrical

($/kW)

Fuel Sales

(mmBTU)

Other Revenue

($1,000s/yr)Mon Tue Wed Thu Fri Sat Sun

Run

Hours

/Year

Capacity

Factor

1 (1) Caterpillar G3520 2.1 18,001 No Yes Combined Heat and Power 6,106 2,946 ‐ ‐ 24 24 24 24 24 24 24 8,760 100%

2 (5) Caterpillar G3520 10.3 53,574 No Yes Simple Cycle 17,430 1,691 ‐ ‐ 8 12 16 16 16 16 16 5,214 60%

3 (1) Solar Mercury 50 4.5 39,313 No Yes Simple Cycle 11,726 2,601 ‐ ‐ 24 24 24 24 24 24 24 8,760 100%

4 (3) Solar Mercury 50 13.5 77,221 No Yes Simple Cycle 26,457 1,961 ‐ ‐ 14 16 16 16 16 16 16 5,735 65%

5 (1) Solar Taurus 60 5.5 48,204 No Yes Simple Cycle 10,675 1,930 ‐ ‐ 24 24 24 24 24 24 24 8,760 100%




9 (1) Solar Titan T130 14.5 63,375 No No Simple Cycle 16,155 1,089 ‐ ‐ 8 8 8 12 16 16 16 4,380 50%

Notes/Instructions:

1 Specifiy duct firing capabiliites (Column 5)

2 Include gas interconnection costs in analysis (Column 6)

3 Operating Mode (Column 7) is used to specify combined or simple cycle operations.

4 Fuel Sales (Column 10) is used to specify potential revenues from sale of natural gas fuel.

5 Other Revenue (Column 11) is used to specify additional project revenues.

6

Plant Availability (typical hrs/day)

Plant Availability (Columns 12‐18) are used to specify the number of hours per typical day that the plant would be

available to support the host. These entries drive the annual availability of the plant (Capacity Factor) and are used to

calculate the labor component of Fixed O&M.


Beecher Falls Energy Park Economic Feasibility Model Financial Inputs

Financial Variables


1 General Escalation gex 2.5% Allowance

2 Energy Escalation eex 2.5% Allowance

3 Fuel Escalation fex 2.5% Allowance

4 Discount Rate drx 8.0% Present value of future cash flows; conceptually = Interest Rate in Reverse

5 Grant grt 10% Allowance

6 Percent Debt pdx 50% Allowance

7 Interest Rate irx 5.0% Allowance

8 Term (Yrs) ter 20 Allowance

9 Depreciation Term dep 20 Allowance ‐ Other options may be available (i.e., MACRES)

10 Investment Tax Credit itc 10% Eligibility, efficiency & In‐service deadline criteria apply.

11 Combined Fed + State Tax Rate itx 40% Allowance

12 Property Tax Rate (% of Invest. Cost) ptr 1.0% Allowance

13 Commercial Operation Date cod 2012 Enter anticipated year of need to escalate cost & revenue estimates

14 Insurance Rate (% of Invest. Cost) ins 0.5% Allowance

15 Natural Gas Interconnection Costs ngx 2,060 $1,000s (2011) from NorthStar Industries (October 2011)

Notes/Instructions:

1 Financial variable inputs are used to define the financial environment in Year 0 of the model study.



Beecher Falls Energy Park Economic Feasibility Model Commodity Inputs

Commodity Pricing Variables Note: Chart will update based on year 1 commodity values and escalation rates (defined on this tab)


1 Gas ($/mmBtu) gas 6.00 Enter year 1 forward pricing value

2 Energy ($/MWH) ene 70 Enter year 1 forward pricing value

3 Avoided Distribution ($/MWH) adx 30 Enter year 1 forward pricing value

4 FCM ($/kW‐Yr) fcm 24.00 Enter year 1 forward pricing value

5 Credits/RECs ($/MWH) rec 0 Enter year 1 forward pricing value

6 Steam ($/Ton) stm 7.50 Enter year 1 forward pricing value, $7.50 IS A PLACEHOLDER VALUE

7 Hot Water ($/Ton) hwt 0.50 Enter year 1 forward pricing value, $0.50 IS A PLACEHOLDER VALUE

8 Fuel Sales ($/mmBTU) fsl 8.00 Enter year 1 forward pricing value

9 Other oth 0.00 Enter year 1 forward pricing value

10 Labor Rate ‐ Plant Mgr. / Opr. ($/hr) mgr 40 Labor costs for plant operations

11 Labor Rate ‐ Plant Opr. / Mech. ($/hr) opr 30 Labor costs for plant operations (CC & Add'l Shifts)

12 Labor Overhead Multiplier ovr 1.4 Labor overhead multiplier

13 Night & Weekend Labor Rate Premium prm 1.2 Shift work premium

Notes/Instructions:

1 Commodity variable inputs are used to define market conditions in Year 0 of the model study.


2

4

6

8

10

12

14

20

40

60

80

100

120

140

160

$/m

mBTU

(gas only)

$'s/M

WH

($/kW‐yr, FCM only)

Commodity Pricing ‐ Forward Outlook


0

2

0

20

2012 2017 2022 2027 2032 2037 2042

Calendar Year

Energy ($/MWH) Avoided Distribution ($/MWH) FCM ($/kW‐Yr) Credits/RECs ($/MWH)

Steam ($/Ton) Retail Fuel Sales ($/mmBtu) Other Gas ($/mmBtu)


Equipment Performance Characteristics and Operations

Beecher Falls Energy Park Economic Feasibility Model Performance Characteristics

Column No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

No. AlternativeNo. of

UnitsParasitic Load

Nominal

Electrical

Output (kW)

Net Summer

Capability (MW)

Net Winter

Capability (MW)

Exhaust Heat

MMBTU/hr

No Duct Firing @

ISO

Water Jacket

Waste Heat

(MMBTU/hr)

Steam from

Waste Heat

(tons/hr)

Steam

Duct Firing

(tons/hr)

Total Steam

(tons/hr)

Hot Water

182° F

from Waste

Heat

(tons/hr)

Gross Plant

Heat Rate

Btu/kWH

HHV

Duct Firing fuel

Consump

MMBTU/hr

Electrical

Heat Rate

Btu/kWH HHV

Heat Rate

Degradation

Hours

of

Operation

per

Year

Variable

O&M

($/MWH)

Simple Cycle

1 (1) Caterpillar G3520 1 3% 2,055 1,993 2,055 4.3 2.2 2.3 0.0 2.3 89 4,644 0 10,491 3% 8,760 5.00

2 (5) Caterpillar G3520 5 3% 10,275 9,967 10,275 21.4 11.2 11.6 0.0 11.6 445 4,644 0 10,491 3% 5,214 5.00

3 (1) Solar Mercury 50 1 3% 4,488 3,700 5,000 15.6 N/A 6.7 0.0 6.7 N/A 4,521 37.7 9,955 3% 8,760 5.00

4 (3) Solar Mercury 50 3 3% 13,464 11,100 15,000 46.8 N/A 20.1 0.0 20.1 N/A 4,521 113.1 9,955 3% 5,735 5.00

5 (1) Solar Taurus 60 1 3% 5,503 4,700 6,000 30.2 N/A 14.7 0.0 14.7 N/A 4,510 21.2 12,199 3% 8,760 5.00




9 (1) Solar Titan T130 1 3% 14,470 12,800 15,600 31.7 N/A 31.7 0.0 31.7 N/A 4,389 88.2 10,934 3% 4,380 5.00

Notes

1 Net Electrical Output is at ISO conditions.

2 Net Electrical Output for the combustion turbine options at summer conditions will be approximately 10% lower.

3 Equipment prices and performance based on indicative vendor quotes.

4 Cost of land acquisition, gas pipeline interconnection, metering or compression/pressure reduction facilities are not included.

5 Annual run hours determined by user inputs located on the Plant Operations tab.

6 Fixed O&M costs include provisions for labor associated with plant operations; these costs are adjusted based on user specified plant availability (run hours).

7 Variable O&M includes cost of consumables, minor and major maintenance overhauls.

8 Categories for Fixed and Variable O&M $/kWh for "Simple" and "Combined Cycle" reflect the relative O&M complexity of each technology.

9 Caterpillar steam @ 20 psig; all other options at 150 psig.

10 EFH ‐ Equivalent Fire Hours. Running total of hours of equipment operation; used to specify timing of equipment maintenance overhauls.

11 Start/Stop Penalty (EFH) ‐ EFH proxy for equipment degradation in addition to normal wear and tear resulting from intermittent operation (i.e., cold starts).


Beecher Falls Energy Park Economic Feasibility Model Performance Characteristics

Column No.

No. Alternative





5 (1) Solar Taurus 60





Notes

1 Net Electrical Output is at ISO con

2 Net Electrical Output for the comb

3 Equipment prices and performanc

4 Cost of land acquisition, gas pipel

5 Annual run hours determined by u

6 Fixed O&M costs include provisio

7 Variable O&M includes cost of con

8 Categories for Fixed and Variable

9 Caterpillar steam @ 20 psig; all ot

10 EFH ‐ Equivalent Fire Hours. Runn

11 Start/Stop Penalty (EFH) ‐ EFH pro

18 19 20 21 22 23 24 25 26

Variable O&M

($/MWH)

Combined Heat and

Power (CHP)

Fixed O&M

SC

(less labor)

Fixed O&M SC

(labor only)

Total Fixed

O&M SC

Fixed O&M

CHP

(less labor)

Fixed O&M

CHP

(labor only)

Total Fixed

O&M CHP

Start/Stop

Penalty (EFH)

Overhaul

Interval

(EFH)

7.50 174,500 451,942 626,442 234,500 663,354 897,854 2 60,000

7.50 458,500 430,976 889,476 658,500 684,320 1,342,820 2 60,000

7.50 183,500 451,942 635,442 243,500 707,034 950,534 2 60,000

7.50 328,500 435,344 763,844 458,500 614,432 1,072,932 2 60,000

7.50 240,250 451,942 692,192 317,750 707,034 1,024,784 2 60,000

7.50 398,750 506,106 904,856 556,250 708,781 1,265,031 2 60,000

7.50 240,250 451,942 692,192 317,750 707,034 1,024,784 2 60,000

7.50 319,500 396,032 715,532 437,000 562,016 999,016 2 60,000

7.50 298,500 231,795 530,295 393,500 434,470 827,970 2 60,000


Beecher Falls Energy Park Economic Feasibility Model O&M

Item

No.Description

Solar

Titan

Solar

Taurus

Solar

Mercury

Caterpillar

3516C‐HD

1 Individual Unit Costs, Simple Cycle

a Vendor Annual Inspections, PMs, calibr. 25,000 25,000 25,000 25,000

b Miscelaneous Parts 20,000 15,000 10,000 10,000

c ANR Annual Emissions Fees, Title V 25,000 25,000 25,000 25,000

d Oil. Lubes 5,000 3,000 2,000 2,000

e Waste Oil Disposal 2,000 1,500 1,000 1,000

f Demin Use, Demurge, and Regen 1,500 1,000 1,000 0

g Waste Water Disposal 1,000 750 500 0

h Annual Emission Testing 5,000 5,000 5,000 5,000

i Electrical Testing, Relays, Metering 3,000 3,000 3,000 3,000

j Subtotal, Simple Cycle Costs per Unit 87,500 79,250 72,500 71,000

2 Additional Individual Unit Costs, Combined Heat and Power

a HRSG 25,000 20,000 15,000 15,000

b Miscelaneous Parts 10,000 10,000 10,000 10,000

c Inspections, Certification 10,000 10,000 10,000 10,000

d Subtotal, Thermal Cycle Costs per Unit 45,000 40,000 35,000 35,000

3 Subtotal Fixed O&M Cost / Unit, Combined Heat and Power 132,500 119,250 107,500 106,000

4 Shared Plant Costs, Simple Cycle

a Powerhouse, utiities, maintenance 100,000 75,000 50,000 50,000

b Security systems & Surveilance 25,000 20,000 15,000 10,000

c Gorunds maintenance 20,000 15,000 10,000 7,500

d Balance of plant maintenace 30,000 20,000 10,000 10,000

e GSU & switchyard maint. & calibrations 15,000 10,000 5,000 5,000

f Phone, IT 5,000 5,000 5,000 5,000

g Misc materials and supplies 1,000 1,000 1,000 1,000

h Vehicle 15,000 15,000 15,000 15,000

i Subtotal Shared Plant Costs, Simple Cycle 211,000 161,000 111,000 103,500

5 Additional Shared Plant Costs, Combined Heat and Power

a Additional powerhouse, utilties, maint. 25,000 18,750 12,500 12,500

b Water supply & treatment systems 25,000 18,750 12,500 12,500

c Subtotal Shared Plant Costs, Thermal Cycle 50,000 37,500 25,000 25,000

6 Subtotal Shared Plant Costs,Combined Heat and Power 261,000 198,500 136,000 128,500

7 Labor Cost, each 1st shift, Mon ‐ Fri

a Simple Cycle, One Unit 448 448 448 448 Plant Manager/Operator

b Simple Cycle, Multiple Units 448 616 616 784 Plant Mgr + Operator/Mechanic

c Combined Cycle, One Unit 784 784 784 616 Plant Mgr + Operator/Mechanic

d Combined Cycle, Multiple Units 784 952 952 1,120 Plant Mgr + Operator/Mechanics

8 Additional Labor Cost, each addt'l hour, Sun ‐ Fri

a Simple Cycle, One Unit 50 50 50 50 Plant Manager/Operator

b Simple Cycle, Multiple Units 76 76 76 101 Plant Mgr + Operator/Mechanic

c Combined Cycle, One Unit 101 76 76 76 Plant Mgr + Operator/Mechanic

d Combined Cycle, Multiple Units 101 101 101 126 Plant Mgr + Operator/Mechanics

9 Variable O&M Simple Cycle, $/MWH

a Maintenace Overhauls 3.00 3.00 3.00 3.00

b Consumables, SCR chemicals 2.00 2.00 2.00 2.00

c SubtotalVariable O&M Simple Cycle, $/MWH 5.00 5.00 5.00 5.00

10 Additional Variable O&M (Consumables), CHP, $/MWH 2.50 2.50 2.50 2.50

a SubtotalVariable O&M Combined Cycle, $/MWH 7.50 7.50 7.50 7.50

Fixed O&M

Var. O

&M

Notes


Beecher Falls Energy Park Economic Feasibility Model O&M

No. Alternative & Operating Mode

Simple Cycle Mon Tue Wed Thu Fri Sat Sun Total

1 (1) Caterpillar G3520 65,229 65,229 65,229 65,229 65,229 62,899 62,899 451,942

2 (5) Caterpillar G3520 23,296 44,262 65,229 65,229 65,229 83,866 83,866 430,976

3 (1) Solar Mercury 50 65,229 65,229 65,229 65,229 65,229 62,899 62,899 451,942

4 (3) Solar Mercury 50 55,619 63,482 63,482 63,482 63,482 62,899 62,899 435,344

5 (1) Solar Taurus 60 65,229 65,229 65,229 65,229 65,229 62,899 62,899 451,942

6 (3) Solar Taurus 60 94,931 94,931 63,482 63,482 63,482 62,899 62,899 506,106

7 (1) Solar Taurus 70 65,229 65,229 65,229 65,229 65,229 62,899 62,899 451,942

8 (2) Solar Taurus 70 32,032 47,757 63,482 63,482 63,482 62,899 62,899 396,032

9 (1) Solar Titan T130 23,296 23,296 23,296 33,779 44,262 41,933 41,933 231,795

No. Alternative & Operating Mode

Combined Heat and Power Mon Tue Wed Thu Fri Sat Sun Total

1 (1) Caterpillar G3520 94,931 94,931 94,931 94,931 94,931 94,349 94,349 663,354

2 (5) Caterpillar G3520 58,240 84,448 110,656 110,656 110,656 104,832 104,832 684,320

3 (1) Solar Mercury 50 103,667 103,667 103,667 103,667 103,667 94,349 94,349 707,034

4 (3) Solar Mercury 50 80,954 91,437 91,437 91,437 91,437 83,866 83,866 614,432

5 (1) Solar Taurus 60 103,667 103,667 103,667 103,667 103,667 94,349 94,349 707,034

6 (3) Solar Taurus 60 133,370 133,370 91,437 91,437 91,437 83,866 83,866 708,781

7 (1) Solar Taurus 70 103,667 103,667 103,667 103,667 103,667 94,349 94,349 707,034

8 (2) Solar Taurus 70 49,504 70,470 91,437 91,437 91,437 83,866 83,866 562,016

9 (1) Solar Titan T130 40,768 40,768 40,768 61,734 82,701 83,866 83,866 434,470

Fixed O&M ‐ Lab

or Component Breakdown

Annual Labor Costs

Annual Labor Costs

Labor costs are determined by the user defined operating mode and daily run hours (Plant Operations tab) and are based on user defined labor and overhead cost assumptions

(Commodities tab).


Beecher Falls Energy Park Economic Feasibility Model Forward Pricing

Study Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

No Item

1 Gas ($/mmBtu) 6.00 6.15 6.30 6.46 6.62 6.79 6.96 7.13 7.31 7.49 7.68 7.87 8.07 8.27 8.48

2 Energy ($/MWH) 70.00 71.75 73.54 75.38 77.27 79.20 81.18 83.21 85.29 87.42 89.61 91.85 94.14 96.50 98.91

3 Avoided Distribution ($/MWH) 30.00 30.75 31.52 32.31 33.11 33.94 34.79 35.66 36.55 37.47 38.40 39.36 40.35 41.36 42.39

4 FCM ($/kW‐Yr) 24.00 24.60 25.22 25.85 26.49 27.15 27.83 28.53 29.24 29.97 30.72 31.49 32.28 33.08 33.91

5 Credits/RECs ($/MWH) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

6 Steam ($/Ton) 7.50 7.69 7.88 8.08 8.28 8.49 8.70 8.92 9.14 9.37 9.60 9.84 10.09 10.34 10.60

7 Hot Water ($/Ton) 0.50 0.51 0.53 0.54 0.55 0.57 0.58 0.59 0.61 0.62 0.64 0.66 0.67 0.69 0.71

8 Retail Fuel Sales ($/mmBtu) 8.00 8.20 8.41 8.62 8.83 9.05 9.28 9.51 9.75 9.99 10.24 10.50 10.76 11.03 11.30

9 Other 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00


Beecher Falls Energy Park Economic Feasibility Model Forward Pricing

Study Year

Calendar Year

No Item

1 Gas ($/mmBtu)

2 Energy ($/MWH)

3 Avoided Distribution ($/MWH)

4 FCM ($/kW‐Yr)

5 Credits/RECs ($/MWH)

6 Steam ($/Ton)

7 Hot Water ($/Ton)

8 Retail Fuel Sales ($/mmBtu)

9 Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

8.69 8.91 9.13 9.36 9.59 9.83 10.08 10.33 10.59 10.85 11.12 11.40 11.69 11.98 12.28 12.59

101.38 103.92 106.51 109.18 111.91 114.70 117.57 120.51 123.52 126.61 129.78 133.02 136.35 139.75 143.25 146.83

43.45 44.54 45.65 46.79 47.96 49.16 50.39 51.65 52.94 54.26 55.62 57.01 58.43 59.89 61.39 62.93

34.76 35.63 36.52 37.43 38.37 39.33 40.31 41.32 42.35 43.41 44.49 45.61 46.75 47.92 49.11 50.34

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

10.86 11.13 11.41 11.70 11.99 12.29 12.60 12.91 13.23 13.57 13.90 14.25 14.61 14.97 15.35 15.73

0.72 0.74 0.76 0.78 0.80 0.82 0.84 0.86 0.88 0.90 0.93 0.95 0.97 1.00 1.02 1.05

11.59 11.88 12.17 12.48 12.79 13.11 13.44 13.77 14.12 14.47 14.83 15.20 15.58 15.97 16.37 16.78

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00


Cost Estimates and Financing Data

Beecher Falls Energy Park Economic Feasibility Model Sources of Funds

C.O.D 2012 $$

No. Alternative Operating Mode

Gas Interconnect

CostPlant Investment

Cost

Investment Cost

Used in AnalysisGrants Equity Debt Total

1 (1) Caterpillar G3520 Combined Heat and Power $ 2,112 $ 3,942 $ 6,106 611$ 2,748$ 2,748$ 6,106$

2 (5) Caterpillar G3520 Simple Cycle $ 2,112 $ 15,266 $ 17,430 1,743$ 7,843$ 7,843$ 17,430$

3 (1) Solar Mercury 50 Simple Cycle $ 2,112 $ 9,561 $ 11,726 1,173$ 5,277$ 5,277$ 11,726$

4 (3) Solar Mercury 50 Simple Cycle $ 2,112 $ 24,293 $ 26,457 2,646$ 11,906$ 11,906$ 26,457$

5 (1) Solar Taurus 60 Simple Cycle $ 2,112 $ 8,511 $ 10,675 1,068$ 4,804$ 4,804$ 10,675$




9 (1) Solar Titan T130 Simple Cycle $ 2,112 $ 15,761 $ 16,155 1,615$ 7,270$ 7,270$ 16,155$

Plant Cost Estimate Summary (detailed under separate cover)

No. AlternativeTotal Estimated Costs CHP

(2012 $1,000's)

Estimated Costs

Simple Cycle

(2012 $1,000's)

Gas

Interconnection

Costs (2012$)

Estimated Costs

Simple Cycle

COD $$

Gas Interconnect

Costs

(COD $)

Total Simple

Cycle Cost

COD $

1 (1) Caterpillar G3520 $ 4,901 $ 3,942 $ 2,112 $ 3,942 $ 2,112 $ 6,053

2 (5) Caterpillar G3520 $ 18,556 $ 15,266 $ 2,112 $ 15,266 $ 2,112 $ 17,377

3 (1) Solar Mercury 50 $ 13,164 $ 9,561 $ 2,112 $ 9,561 $ 2,112 $ 11,673

4 (3) Solar Mercury 50 $ 34,678 $ 24,293 $ 2,112 $ 24,293 $ 2,112 $ 26,405

5 (1) Solar Taurus 60 $ 11,482 $ 8,511 $ 2,112 $ 8,511 $ 2,112 $ 10,623

6 (3) Solar Taurus 60 $ 29,045 $ 20,767 $ 2,112 $ 20,767 $ 2,112 $ 22,878

7 (1) Solar Taurus 70 $ 14,166 $ 10,404 $ 2,112 $ 10,404 $ 2,112 $ 12,515

8 (2) Solar Taurus 70 $ 25,656 $ 18,438 $ 2,112 $ 18,438 $ 2,112 $ 20,549

9 (1) Solar Titan T130 $ 21,529 $ 15,761 $ 2,112 $ 15,761 $ 2,112 $ 17,872

Notes:

1 See Plant Operations sheet to select inclusion of gas interconnection costs as well as Combined or Simple Cycle operations to specify initial investment estimate.

2 See Plant Operations sheet to select Commercial Operation Date to specify appropriate escalation factors to cost estimates.

3 Cost estimates are in 2012 $1,000s and are intended for planning purposes only.

4 Esimates include permitting allowances according to installed capacity: $500k (<5MW), $600k (5‐10MW), or $750k (10‐15MW)

5 Contingency of 20% (5% on Equipment) is included.

6 15% allowance for funds during construction (AFUDC) is included.

7 Cost estimate details are provided on separate worksheets in this workbook.

Initial Estimate 2012 $$


Beecher Falls Energy Park Economic Feasibility Model Alt 1 - CHP

(1) Caterpillar G3520

Item No Description Qty RateAmount $1,000s

Comments

1 Site Prepa Demo & Prep 1.5 100 150 Allowanceb Crane pad 0 16 0 N/Ac Engine/Gen foundation 1 27 27 Allowanced Control Building 1.5 125 188 N/Ae 13.8 kV Switchgear Pad 1 15 15 Scaled from recent projectf GSU Pad 0 32 0 N/Ag S/S transformer Pad 1 5 5 N/Ah Paving 1.5 11 16 Allowancei Fencing, lighting, security 1.5 5 8 Allowancej Tank pad & containment 0 27 0 Allowance

k Subtotal 409

2 Generating Unita Equipment 1 900 900 Vendor Quoteb Shipping 1 50 50 Allowancec Installation 1 108 108 Vendor Quoted Start-Up 0 0 Includede Subtotal 1,058

3 Auxiliary Mechanical 27a Fuel storage tank 0 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 25 25 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 1 260 260 Vendor Quotei Subtotal 285

4 Thermal Network 1 400 400 Vendor estimate

5 Auxiliary Electricala 13.8 kV Switchgear 1 500 500 Vendor est, complete paralleling system.b Low voltage Switchgear 1 25 25 Engineer's estimatec GSU 0 145 0 Engineer's estimated Interconnection 1 100 100 Allowancee Other 0 0f Subtotal 625

6 Administrative Costsa Engineering and Design 1 139 139 Allowance, 5% of Directsb Permitting 1 500 500 Allowancec Owner's costs 1 162 162 Allowanced Other 0 0e Subtotal 800

7 Summary1 Site Prep 4092 Generating Unit 1,0583 Auxiliary Mechanical 2854 Thermal Network 4005 Auxiliary Electrical 6256 Administrative Costs 8007 Subtotal 0 0 3,577

6 Contingency @ 20% 580 5% contingency on T/G unit

7 Total 4,158

8 AFUDC 15% 624

9 Grand Total 4,901 2012$$


Beecher Falls Energy Park Economic Feasibility Model Alt 1-SC



Comments

1 Site Prepa Demo & Prep 1 100 100 Allowanceb Crane pad 0 16 0 N/Ac Engine/Gen foundation 1 27 27 Allowanced Control Building 0 125 0 N/Ae 13.8 kV Switchgear Pad 1 15 15 Scaled from recent projectf GSU Pad 0 32 0 N/Ag S/S transformer Pad 1 5 5 N/Ah Paving 1 11 11 Allowancei Fencing, lighting, security 1 5 5 Allowancej Tank pad & containment 0 27 0 Allowance

k Subtotal 163

2 Generating Unita Equipment 1 900 900 Vendor Quoteb Shipping 1 50 50 Allowancec Installation 1 108 108 Vendor Quoted Start-Up 0 0 Includede Subtotal 1,058

3 Auxiliary Mechanical 27a Fuel storage tank 0 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 25 25 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 1 260 260 Vendor Quotei Subtotal 285


5 Auxiliary Electricala 13.8 kV Switchgear 1 500 500 Vendor est, complete paralleling system.b Low voltage Switchgear 1 25 25 Engineer's estimatec GSU 0 145 0 Engineer's estimated Interconnection 1 100 100 Allowancee Other 0 0f Subtotal 625




7 Total 3,344

8 AFUDC 15% 502

9 Grand Total 3,942 2012$$





Comments

1 Site Prepa Demo & Prep 1.5 200 300 Allowanceb Crane pad 0 16 0 N/Ac Engine/Gen foundation 5 27 135 Allowanced Control Building 1.5 200 300 N/Ae 13.8 kV Switchgear Pad 5 15 75 Scaled from recent projectf GSU Pad 0 32 0 N/Ag S/S transformer Pad 1 5 5 N/Ah Paving 1.5 25 38 Allowancei Fencing, lighting, security 1.5 5 8 Allowancej Tank pad & containment 0 27 0 N/A

k Subtotal 861

2 Generating Unita Equipment 5 900 4,500 Vendor Quoteb Shipping 5 50 250 Allowancec Installation 5 108 538 Vendor Quoted Start-Up 0 0 Includede Subtotal 5,288

3 Auxiliary Mechanical 27a Fuel storage tank 0 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 5 260 1,300 Vendor Quotei Subtotal 1,355

4 Thermal Network 5 400 2,000 Vendor estimate

5 Auxiliary Electricala 13.8 kV Switchgear 5 500 2,500 Vendor est, complete paralleling system.b Low voltage Switchgear 1 100 100 Engineer's estimatec GSU 0 446 0 Engineer's estimated Interconnection 1 200 200 Allowancee Other 0 0f Subtotal 2,800

6 Administrative Costsa Engineering and Design 1 615 615 Allowance, 5% of Directsb Permitting 1 600 600 Allowancec Owner's costs 1 162 162 Allowanced Other 0 0e Subtotal 1,377

7 Summary1 Site Prep 8612 Generating Unit 5,2883 Auxiliary Mechanical 1,3554 Thermal Network 2,0005 Auxiliary Electrical 2,8006 Administrative Costs 1,3777 Subtotal 0 0 13,681

6 Contingency @ 20% 2,061 5% contingency on T/G unit

7 Total 15,742

8 AFUDC 15% 2,361

9 Grand Total 18,556 2012$$


Beecher Falls Energy Park Economic Feasibility Model Alt 2-SC



Comments

1 Site Prepa Demo & Prep 1 200 200 Allowanceb Crane pad 0 16 0 N/Ac Engine/Gen foundation 5 27 135 Allowanced Control Building 1 200 200 N/Ae 13.8 kV Switchgear Pad 5 15 75 Scaled from recent projectf GSU Pad 0 32 0 N/Ag S/S transformer Pad 1 5 5 N/Ah Paving 1 25 25 Allowancei Fencing, lighting, security 1 5 5 Allowancej Tank pad & containment 0 27 0 N/A

k Subtotal 645

2 Generating Unita Equipment 5 900 4,500 Vendor Quoteb Shipping 5 50 250 Allowancec Installation 5 108 538 Vendor Quoted Start-Up 0 0 Includede Subtotal 5,288

3 Auxiliary Mechanical 27a Fuel storage tank 0 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 5 260 1,300 Vendor Quotei Subtotal 1,355


5 Auxiliary Electricala 13.8 kV Switchgear 5 500 2,500 Vendor est, complete paralleling system.b Low voltage Switchgear 1 100 100 Engineer's estimatec GSU 0 446 0 Engineer's estimated Interconnection 1 200 200 Allowancee Other 0 0f Subtotal 2,800


7 Summary1 Site Prep 6452 Generating Unit 5,2883 Auxiliary Mechanical 1,3554 Thermal Network 05 Auxiliary Electrical 2,8006 Administrative Costs 1,2667 Subtotal 0 0 11,355


7 Total 12,951

8 AFUDC 15% 1,943

9 Grand Total 15,266 2012$$



(1) Solar Mercury 50


Comments


k Subtotal 562

2 Generating Unita Equipment 1 4,000 4,000 Vendor Quoteb Shipping 1 207 207 Allowancec Installation 1 200 200 Allowanced Start-Up 1 160 160 Vendor Quotee Subtotal 4,567

3 Auxiliary Mechanical 27a Fuel storage tank 0b Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 1 500 500 Miscellaneousi Subtotal 555

4 Thermal Network 1 2,283 2,283 Allowance: 50% of T/G Island

5 Auxiliary Electricala 13.8 kV Switchgear 1 162 162 Engineer's estimateb Low voltage Switchgear 1 118 118 Engineer's estimatec GSU 1 269 269 Engineer's estimated Interconnection 1 194 194 Engineer's estimatee Other 0 0f Subtotal 743


7 Summary1 Site Prep 5622 Generating Unit 4,5673 Auxiliary Mechanical 5554 Thermal Network 2,2835 Auxiliary Electrical 7436 Administrative Costs 1,0977 Subtotal 0 0 9,807


7 Total 11,168

8 AFUDC 15% 1,675

9 Grand Total 13,164 2012$$


Beecher Falls Energy Park Economic Feasibility Model Alt 3 - SC



Comments


k Subtotal 420


3 Auxiliary Mechanical 27a Fuel storage tank 0b Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 1 500 500 Miscellaneousi Subtotal 555

4 Thermal Network 0 2,283 0 Allowance: 50% of T/G Island





7 Total 8,111

8 AFUDC 15% 1,217

9 Grand Total 9,561 2012$$





Comments


k Subtotal 420


3 Auxiliary Mechanical 27a Fuel storage tank 0b Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 3 500 1,500 Miscellaneousi Subtotal 1,555


5 Auxiliary Electricala 13.8 kV Switchgear 3 162 485 Engineer's estimateb Low voltage Switchgear 1 118 118 Engineer's estimatec GSU 1 492 492 Engineer's estimated Interconnection 1.5 194 291 Engineer's estimatee Other 0 0f Subtotal 1,386




7 Total 20,609

8 AFUDC 15% 3,091

9 Grand Total 24,293 2012$$





Comments


k Subtotal 562


3 Auxiliary Mechanical 27a Fuel storage tank 0b Fuel forwarding & filter 1 55 55 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 3 500 1,500 Miscellaneousi Subtotal 1,555


5 Auxiliary Electricala 13.8 kV Switchgear 3 162 485 Engineer's estimateb Low voltage Switchgear 1 118 118 Engineer's estimatec GSU 1 492 492 Engineer's estimated Interconnection 2 194 291 Engineer's estimatee Other 0 0f Subtotal 1,386

6 Administrative Costsa Engineering and Design 1 1,203 1,203 Allowance, 5% of Directsb Permitting 1 600 600 Allowancec Owner's costs 1 162 162 Allowanced Other 0 0e Subtotal 1,964



7 Total 29,419

8 AFUDC 15% 4,413

9 Grand Total 34,678 2012$$



(1) Solar Taurus 60


Comments


k Subtotal 343

2 Generating Unita Equipment 1 3,236 3,236 Vendor Quoteb Shipping 1 175 175 Vendor Quotec Installation 1 200 200 Vendor estimated Start-Up 1 150 130 Vendor Quotee Subtotal 3,741

3 Auxiliary Mechanical 27a Fuel storage tank 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 27 27 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 1 500 500 Miscellaneousi Subtotal 527




7 Summary1 Site Prep 3432 Generating Unit 3,7413 Auxiliary Mechanical 5274 Thermal Network 05 Auxiliary Electrical 7796 Administrative Costs 1,0317 Subtotal 0 0 6,422


7 Total 7,221

8 AFUDC 15% 1,083

9 Grand Total 8,511 2012$$



(1) Solar Taurus 60


Comments


k Subtotal 473








7 Total 9,741

8 AFUDC 15% 1,461

9 Grand Total 11,482 2012$$



(3) Solar Taurus 60


Comments


k Subtotal 413


3 Auxiliary Mechanical 27a Fuel storage tank 108 0 40,000 gal, scaled from recent projectb Fuel forwarding & filter 1 27 27 Allowancec Raw water tank 0 0 N/Ad Water treatment 0 0 N/Ae Demin water tank 0 0 N/Af Waste water tank 0 27 0 N/Ag Compressed air facility 0 0 N/Ah CO catalyst & SCR 3 500 1,500 Miscellaneousi Subtotal 1,527






7 Total 17,617

8 AFUDC 15% 2,643

9 Grand Total 20,767 2012$$



(3) Solar Taurus 60


Comments


k Subtotal 506








7 Total 24,640

8 AFUDC 15% 3,696

9 Grand Total 29,045 2012$$



(1) Solar Taurus 70


Comments


k Subtotal 498




5 Auxiliary Electricala 13.8 kV Switchgear 1 156 156 Engineer's estimateb Low voltage Switchgear 1 118 118 N/Ac GSU 1 389 389 N/Ad Interconnection 1 194 194 N/Ae Other 0 0f Subtotal 858




7 Total 12,018

8 AFUDC 15% 1,803

9 Grand Total 14,166 2012$$



(1) Solar Taurus 70


Comments


k Subtotal 360




5 Auxiliary Electricala 13.8 kV Switchgear 1 156 156 Engineer's estimateb Low voltage Switchgear 1 118 118 N/Ac GSU 1 389 389 N/Ad Interconnection 1 194 194 N/Ae Other 0 0f Subtotal 858


7 Summary1 Site Prep 3602 Generating Unit 4,7903 Auxiliary Mechanical 7774 Thermal Network 05 Auxiliary Electrical 8586 Administrative Costs 1,1017 Subtotal 0 0 7,885


7 Total 8,826

8 AFUDC 15% 1,324

9 Grand Total 10,404 2012$$



(2) Solar Taurus 70


Comments


k Subtotal 498




5 Auxiliary Electricala 13.8 kV Switchgear 2 156 312 Engineer's estimateb Low voltage Switchgear 1 118 118 N/Ac GSU 1 494 494 N/Ad Interconnection 1.5 194 291 N/Ae Other 0 0f Subtotal 1,216




7 Total 21,765

8 AFUDC 15% 3,265

9 Grand Total 25,656 2012$$



(2) Solar Taurus 70


Comments


k Subtotal 360




5 Auxiliary Electricala 13.8 kV Switchgear 2 156 312 Engineer's estimateb Low voltage Switchgear 1 118 118 N/Ac GSU 1 494 494 N/Ad Interconnection 1.5 194 291 N/Ae Other 0 0f Subtotal 1,216




7 Total 15,642

8 AFUDC 15% 2,346

9 Grand Total 18,438 2012$$



(1) Solar Titan T130


Comments

1 Site Prepa Demo & Prep 1.5 170 255 Allowanceb Crane pad 1 27 27 Scaled from recent projectc Engine/Gen foundation 1 120 120 Allowanced Control Building 1.5 150 225 Rehab Existinge 13.8 kV Switchgear Pad 1 22 22 Scaled from recent projectf GSU Pad 1 43 43 Scaled from recent projectg Water Tank Pads 0 16 0 Allowanceh Paving 1.5 20 30 Allowancei Fencing, lighting, security 1.5 20 30 Scaled from recent projectj Other 0

k Subtotal 752

2 Generating Unita Equipment 1 7,100 7,100 Vendor quoteb Shipping 1 355 355 Vendor quotec Installation 1 215 215 Allowanced Start-Up 1 160 160 Vendor quotee Subtotal 7,830

3 Auxiliary Mechanical 27a Fuel storage tank 0 162 0 N/Ab Fuel forwarding & filter 1 40 40 N/Ac Water tanks 0 32 0 N/Ad Water treatment 0 81 0 N/Ae SCR & CEMs 0 108 0 N/Af Gas piping & fittings 0 323 0 N/Ag Gas Compressor 0 538 0 N/Ah CO catalyst & SCR 1 1,200 1,200 Allowance for Miscellaneousi Subtotal 1,240

4 Thermal Network 1 3,915 3,915 Allowance, 50% ff Generating Island

5 Auxiliary Electricala 13.8 kV Switchgear 1 162 162 Engineer's estimateb Low voltage Switchgear 1 118 118 Engineer's estimatec GSU 1 495 495 Engineer's estimated Interconnection 1 300 300 Engineer's estimatee Other 1 270 270 Allowance for Miscellaneousf Subtotal 1,345

6 Administrative Costsa Engineering and Design 1 754 754 5% of Directsb Permitting 1 750 750 Allowancec Owner's costs 1 188 188 Allowanced Other 0e Subtotal 1,693

7 Summary1 Site Prep 5952 Generating Unit 7,8303 Auxiliary Mechanical 1,6764 Thermal Network 3,9155 Auxiliary Electrical 1,1946 Administrative Costs 5387 Subtotal 0 0 15,748


7 Total 18,264

8 AFUDC + Esc 15% 2,740

9 Grand Total, Installed 21,529 2012$$





Comments

1 Site Prepa Demo & Prep 1 170 170 Allowanceb Crane pad 1 27 27 Scaled from recent projectc Engine/Gen foundation 1 120 120 Allowanced Control Building 1 150 150 Rehab Existinge 13.8 kV Switchgear Pad 1 22 22 Scaled from recent projectf GSU Pad 1 43 43 Scaled from recent projectg Water Tank Pads 0 16 0 Allowanceh Paving 1 20 20 Allowancei Fencing, lighting, security 1 20 20 Scaled from recent projectj Other 0

k Subtotal 572

2 Generating Unita Equipment 1 7,100 7,100 Vendor quoteb Shipping 1 355 355 Vendor quotec Installation 1 215 215 Allowanced Start-Up 1 160 160 Vendor quotee Subtotal 7,830

3 Auxiliary Mechanical 27a Fuel storage tank 0 162 0 N/Ab Fuel forwarding & filter 1 40 40 N/Ac Water tanks 0 32 0 N/Ad Water treatment 0 81 0 N/Ae SCR & CEMs 0 108 0 N/Af Gas piping & fittings 0 323 0 N/Ag Gas Compressor 0 538 0 N/Ah CO catalyst & SCR 1 1,200 1,200 Allowance for Miscellaneousi Subtotal 1,240

4 Thermal Network 0 3,915 0 Allowance, 50% ff Generating Island

5 Auxiliary Electricala 13.8 kV Switchgear 1 162 162 Engineer's estimateb Low voltage Switchgear 1 118 118 Engineer's estimatec GSU 1 495 495 Engineer's estimated Interconnection 1 300 300 Engineer's estimatee Other 1 270 270 Allowance for Miscellaneousf Subtotal 1,345

6 Administrative Costsa Engineering and Design 1 549 549 5% of Directsb Permitting 1 750 750 Allowancec Owner's costs 1 188 188 Allowanced Other 0e Subtotal 1,488

7 Summary1 Site Prep 5952 Generating Unit 7,8303 Auxiliary Mechanical 1,6764 Thermal Network 05 Auxiliary Electrical 1,1946 Administrative Costs 5387 Subtotal 0 0 11,833


7 Total 13,371

8 AFUDC + Esc 15% 2,006

9 Grand Total, Installed 15,761 2012$$


Cash Flow Analysis

Beecher Falls Energy Park Economic Feasibility Model Alt1 - Plant Ops

Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Combined Heat and Power

No Item

1 Production

a Installed Capacity (MW) 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06

b Run Hours 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760

c Gross Generation (MWH) 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001

d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

e Net Generation (MWH) 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461

f Tons of Steam from Waste Heat (tons) 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384

g Tons of Steam from Duct Firing (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Tons of Hot Water from Waste Heat (tons) 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233

i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2 Performance Characteristics

a Major Overhaul Interval (EFHrs) 60,000

b Net Heat Rate,HHV, Btu/kWH 10,491

c HR Degradation between OH's 3.0%

d Start/Stop Penalty (EFHrs) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Cumulative Run Hours 8,760 17,519 26,279 35,038 43,798 52,557 0 8,760 17,519 26,279 35,038 43,798 52,557 0 8,760 17,519

f As‐Run Heat Rate,HHV,Btu/kWH 10,537 10,583 10,629 10,675 10,721 10,767 10,491 10,537 10,583 10,629 10,675 10,721 10,767 10,491 10,537 10,583

g Duct Burner Fuel Consumption (MMBtu/hr) HHV 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

3 Fuel Consumed (MMBtu)

a Gas for Energy 189,681 190,508 191,335 192,162 192,989 193,817 188,854 189,681 190,508 191,335 192,162 192,989 193,817 188,854 189,681 190,508

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year



No Item

1 Production

a Installed Capacity (MW)

b Run Hours

c Gross Generation (MWH)

d Parasitic Load (%)

e Net Generation (MWH)

f Tons of Steam from Waste Heat (tons)

g Tons of Steam from Duct Firing (tons)

h Tons of Hot Water from Waste Heat (tons)

i Other


a Major Overhaul Interval (EFHrs)

b Net Heat Rate,HHV, Btu/kWH

c HR Degradation between OH's

d Start/Stop Penalty (EFHrs)

e Cumulative Run Hours

f As‐Run Heat Rate,HHV,Btu/kWH

g Duct Burner Fuel Consumption (MMBtu/hr) HHV


a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06 2.06

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760

18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001 18,001

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461 17,461

20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384 20,384

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233 779,233

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

26,279 35,038 43,798 52,557 0 8,760 17,519 26,279 35,038 43,798 52,557 0 8,760 17,519 26,279

10,629 10,675 10,721 10,767 10,491 10,537 10,583 10,629 10,675 10,721 10,767 10,491 10,537 10,583 10,629

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

191,335 192,162 192,989 193,817 188,854 189,681 190,508 191,335 192,162 192,989 193,817 188,854 189,681 190,508 191,335

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Production


b Run Hours 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%




h Tons of Hot Water from Waste Heat (tons) 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145

i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0






e Cumulative Run Hours 5,942 11,902 17,881 23,879 29,897 35,934 41,993 48,072 54,173 60,296 0 6,169 12,362 18,580 24,822 31,091




a Gas for Energy 563,735 565,410 567,090 568,775 570,467 572,163 573,866 575,574 577,289 579,010 562,065 563,798 565,539 567,286 569,041 570,802

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year


Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28 10.28

5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214

53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574 53,574

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967 51,967

60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666 60,666

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145 2,319,145

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

1081 1108 1135 1164 1193 1223 1253 1285 1317 1350 1383 1418 1453 1490 1527

37,386 43,707 50,057 56,435 0 6,437 12,904 19,403 25,933 32,497 39,095 45,727 52,394 59,098 0

10,688 10,721 10,754 10,787 10,491 10,525 10,559 10,593 10,627 10,662 10,696 10,731 10,766 10,801 10,491

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

572,571 574,348 576,132 577,925 562,065 563,874 565,691 567,517 569,353 571,197 573,051 574,915 576,789 578,673 562,065

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Production


b Run Hours 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%




h Tons of Hot Water from Waste Heat (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0










a Gas for Energy 393,072 394,786 396,500 398,214 399,928 401,643 391,358 393,072 394,786 396,500 398,214 399,928 401,643 391,358 393,072 394,786

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year


Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49 4.49

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760

39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313 39,313

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133 38,133

58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689 58,689

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

26,279 35,038 43,798 52,557 0 8,760 17,519 26,279 35,038 43,798 52,557 0 8,760 17,519 26,279

10,086 10,129 10,173 10,217 9,955 9,999 10,042 10,086 10,129 10,173 10,217 9,955 9,999 10,042 10,086

38 38 38 38 38 38 38 38 38 38 38 38 38 38 38

396,500 398,214 399,928 401,643 391,358 393,072 394,786 396,500 398,214 399,928 401,643 391,358 393,072 394,786 396,500

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Production


b Run Hours 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%





i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0






e Cumulative Run Hours 6,463 12,927 19,390 25,854 32,317 38,780 45,244 51,707 58,171 0 6,463 12,927 19,390 25,854 32,317 38,780




a Gas for Energy 771,224 773,708 776,192 778,677 781,161 783,645 786,130 788,614 791,098 768,739 771,224 773,708 776,192 778,677 781,161 783,645

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year


Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46 13.46

5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735

77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221 77,221

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905 74,905

115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282 115,282

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

728 728 728 728 728 728 728 728 728 728 728 728 728 728 728

45,244 51,707 58,171 0 6,463 12,927 19,390 25,854 32,317 38,780 45,244 51,707 58,171 0 6,463

10,180 10,212 10,245 9,955 9,987 10,019 10,052 10,084 10,116 10,148 10,180 10,212 10,245 9,955 9,987

113 113 113 113 113 113 113 113 113 113 113 113 113 113 113

786,130 788,614 791,098 768,739 771,224 773,708 776,192 778,677 781,161 783,645 786,130 788,614 791,098 768,739 771,224

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

(1) Solar Taurus 60

Simple Cycle

No Item

1 Production

a Installed Capacity (MW) 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50 5.50

b Run Hours 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735 5,735

c Gross Generation (MWH) 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562 31,562

d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

e Net Generation (MWH) 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615 30,615

f Tons of Steam from Waste Heat (tons) 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199 84,199

g Tons of Steam from Duct Firing (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Tons of Hot Water from Waste Heat (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0





d Start/Stop Penalty (EFHrs) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Cumulative Run Hours 5,735 11,471 17,206 22,942 28,677 34,412 40,148 45,883 51,619 57,354 0 5,735 11,471 17,206 22,942 28,677 34,412 40,148 45,883 51,619 57,354 0 5,735 11,471 17,206 22,942 28,677 34,412 40,148 45,883 51,619

f As‐Run Heat Rate,HHV,Btu/kWH 12,234 12,269 12,304 12,339 12,374 12,409 12,444 12,479 12,514 12,549 12,199 12,234 12,269 12,304 12,339 12,374 12,409 12,444 12,479 12,514 12,549 12,199 12,234 12,269 12,304 12,339 12,374 12,409 12,444 12,479 12,514

g Duct Burner Fuel Consumption (MMBtu/hr) HHV 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21


a Gas for Energy 386,128 387,232 388,336 389,440 390,544 391,648 392,753 393,857 394,961 396,065 385,024 386,128 387,232 388,336 389,440 390,544 391,648 392,753 393,857 394,961 396,065 385,024 386,128 387,232 388,336 389,440 390,544 391,648 392,753 393,857 394,961

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

(3) Solar Taurus 60

Simple Cycle

No Item

1 Production

a Installed Capacity (MW) 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51

b Run Hours 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674

c Gross Generation (MWH) 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180

d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

e Net Generation (MWH) 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874

f Tons of Steam from Waste Heat (tons) 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929

g Tons of Steam from Duct Firing (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Tons of Hot Water from Waste Heat (tons) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0





d Start/Stop Penalty (EFHrs) 520 520 520 520 520 520 520 520 520 520 520 520 520 520 520 520 520 520

e Cumulative Run Hours 7,194 14,388 21,582 28,776 35,970 43,164 50,357 57,551 0 7,194 14,388 21,582 28,776 35,970 43,164 50,357 57,551 0

f As‐Run Heat Rate,HHV,Btu/kWH 12,243 12,287 12,331 12,375 12,418 12,462 12,506 12,550 12,199 12,243 12,287 12,331 12,375 12,418 12,462 12,506 12,550 12,199

g Duct Burner Fuel Consumption (MMBtu/hr) HHV 64 64 64 64 64 64 64 64 64 64 64 64 64 64 64 64 64 64


a Gas for Energy 1,348,917 1,353,752 1,358,587 1,363,421 1,368,256 1,373,090 1,377,925 1,382,760 1,344,083 1,348,917 1,353,752 1,358,587 1,363,421 1,368,256 1,373,090 1,377,925 1,382,760 1,344,083

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year

(3) Solar Taurus 60

Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

18 19 20 21 22 23 24 25 26 27 28 29 30

2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51 16.51

6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674 6,674

110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180 110,180

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874 106,874

293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929 293,929

0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0

520 520 520 520 520 520 520 520 520 520 520 520 520

7,194 14,388 21,582 28,776 35,970 43,164 50,357 57,551 0 7,194 14,388 21,582 28,776

12,243 12,287 12,331 12,375 12,418 12,462 12,506 12,550 12,199 12,243 12,287 12,331 12,375

64 64 64 64 64 64 64 64 64 64 64 64 64

1,348,917 1,353,752 1,358,587 1,363,421 1,368,256 1,373,090 1,377,925 1,382,760 1,344,083 1,348,917 1,353,752 1,358,587 1,363,421

0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(1) Solar Taurus 70

Simple Cycle

No Item

1 Production


b Run Hours 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%





i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0










a Gas for Energy 764,428 767,761 771,095 774,428 777,761 781,095 761,094 764,428 767,761 771,095 774,428 777,761 781,095 761,094 764,428 767,761

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year

(1) Solar Taurus 70

Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74

8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760 8,760

67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834 67,834

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799 65,799

157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763 157,763

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

26,279 35,038 43,798 52,557 0 8,760 17,519 26,279 35,038 43,798 52,557 0 8,760 17,519 26,279

11,367 11,417 11,466 11,515 11,220 11,269 11,318 11,367 11,417 11,466 11,515 11,220 11,269 11,318 11,367

40 40 40 40 40 40 40 40 40 40 40 40 40 40 40

771,095 774,428 777,761 781,095 761,094 764,428 767,761 771,095 774,428 777,761 781,095 761,094 764,428 767,761 771,095

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(2) Solar Taurus 70

Simple Cycle

No Item

1 Production


b Run Hours 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%





i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0






e Cumulative Run Hours 5,942 11,884 17,826 23,768 29,710 35,652 41,594 47,536 53,478 59,420 0 5,942 11,884 17,826 23,768 29,710




a Gas for Energy 908,757 911,449 914,140 916,832 919,524 922,216 924,908 927,600 930,292 932,984 906,065 908,757 911,449 914,140 916,832 919,524

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year

(2) Solar Taurus 70

Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49 15.49

5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214 5,214

80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754 80,754

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332 78,332

187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813 187,813

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

728 728 728 728 728 728 728 728 728 728 728 728 728 728 728

35,652 41,594 47,536 53,478 59,420 0 5,942 11,884 17,826 23,768 29,710 35,652 41,594 47,536 53,478

11,420 11,453 11,487 11,520 11,553 11,220 11,253 11,287 11,320 11,353 11,387 11,420 11,453 11,487 11,520

81 81 81 81 81 81 81 81 81 81 81 81 81 81 81

922,216 924,908 927,600 930,292 932,984 906,065 908,757 911,449 914,140 916,832 919,524 922,216 924,908 927,600 930,292

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Production


b Run Hours 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380


d Parasitic Load (%) 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%





i Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0






e Cumulative Run Hours 5,108 10,216 15,323 20,431 25,539 30,647 35,754 40,862 45,970 51,078 56,185 0 5,108 10,216 15,323 20,431




a Gas for Energy 694,713 696,483 698,253 700,022 701,792 703,562 705,332 707,101 708,871 710,641 712,410 692,944 694,713 696,483 698,253 700,022

b Gas for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Other



Study Year

Calendar Year


Simple Cycle

No Item

1 Production


b Run Hours







i Other










a Gas for Energy

b Gas for Steam

c Other

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47 14.47

4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380 4,380

63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375 63,375

3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3%

61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474 61,474

138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996 138,996

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

728 728 728 728 728 728 728 728 728 728 728 728 728 728 728

25,539 30,647 35,754 40,862 45,970 51,078 56,185 0 5,108 10,216 15,323 20,431 25,539 30,647 35,754

11,074 11,102 11,129 11,157 11,185 11,213 11,241 10,934 10,962 10,990 11,018 11,046 11,074 11,102 11,129

88 88 88 88 88 88 88 88 88 88 88 88 88 88 88

701,792 703,562 705,332 707,101 708,871 710,641 712,410 692,944 694,713 696,483 698,253 700,022 701,792 703,562 705,332

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0


Beecher Falls Energy Park Economic Feasibility Model Alt1 - Cashflow Analysis

Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027



No Item

1 Costs ($1,000's)


b Fixed O&M 898 920 943 967 991 1,016 1,041 1,067 1,094 1,121 1,149 1,178 1,208 1,238 1,269 1,300

c Variable O&M 475 487 499 512 525 538 551 565 579 594 608 624 639 655 672 688

d Gas Fuel for Electricity 1,138 1,172 1,206 1,242 1,278 1,316 1,314 1,353 1,393 1,434 1,476 1,519 1,564 1,562 1,608 1,655

e Gas Fuel for Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Gas Fuel for Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other Fuel

h Transportation 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

i Property Taxes 61 63 64 66 67 69 71 73 74 76 78 80 82 84 86 88

j Insurance 31 31 32 33 34 35 35 36 37 38 39 40 41 42 43 44

k Major Maintenance 100 0 0 0 0 0 116 0 0 0 0 0 0 138 0 0

l Other

m Total Cost 2,673 2,745 2,819 2,895 2,973 3,129 3,094 3,177 3,263 3,351 3,441 3,534 3,719 3,678 3,777


a Energy 1,222 1,253 1,284 1,316 1,349 1,383 1,417 1,453 1,489 1,526 1,565 1,604 1,644 1,685 1,727 1,770

b Avoided Distribution 524 537 550 564 578 593 607 623 638 654 671 687 704 722 740 759

c Forward Capacity Market (FCM) 48 49 50 52 53 54 55 57 58 60 61 63 64 66 68 69

d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 153 157 161 165 169 173 177 182 186 191 196 201 206 211 216 221

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Hot Water 390 399 409 420 430 441 452 463 475 487 499 511 524 537 551 564

h Total Revenues 2,395 2,455 2,516 2,579 2,643 2,710 2,777 2,847 2,918 2,991 3,066 3,142 3,221 3,301 3,384


a Principal 83 87 92 96 101 106 111 117 123 129 135 142 149 157 165

b Interest 137 133 129 124 119 114 109 104 98 92 85 78 71 64 56


4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt (278) (290) (303) (316) (330) (419) (317) (331) (345) (360) (376) (392) (498) (376) (393)


c Depreciation (586) (586) (586) (586) (586) (586) (586) (586) (586) (586) (586) (586) (586) (586) (586)

d Taxable Income (1,002) (1,010) (1,018) (1,027) (1,035) (1,120) (1,012) (1,021) (1,029) (1,038) (1,047) (1,056) (1,156) (1,027) (1,035)

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

5 Cash Flows($1,000's)


b Fed & State Income Tax 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

c Debt Service (220) (220) (220) (220) (220) (220) (220) (220) (220) (220) (220) (220) (220) (220) (220)

d Cash after Taxes & Debt (499) (511) (523) (536) (550) (640) (537) (551) (566) (581) (596) (612) (719) (597) (614)

6 Debt Coverage Ratio < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0

7 Financial calculations ($1,000's)

a Investment Tax Credits 611

b Equity 2,748

c Residual

d Cash after Taxes & Debt (2,137) (499) (511) (523) (536) (550) (640) (537) (551) (566) (581) (596) (612) (719) (597) (614)

e NPV (2,137) (462) (438) (416) (394) (374) (403) (313) (298) (283) (269) (256) (243) (264) (203) (193)

f Cum NPV (7,635) (2,599) (3,037) (3,452) (3,847) (4,221) (4,624) (4,938) (5,235) (5,518) (5,787) (6,043) (6,286) (6,550) (6,753) (6,947)

g IRR #DIV/0!



Study Year

Calendar Year



No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M

d Gas Fuel for Electricity

e Gas Fuel for Steam

f Gas Fuel for Sales

g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy

b Avoided Distribution

c Forward Capacity Market (FCM)

d Credits/RECs

e Steam

f Fuel Sales

g Hot Water

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes

5 Cash Flows($1,000's)



c Debt Service



7 Financial calculations ($1,000's)


b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,333 1,366 1,400 1,435 1,471 1,508 1,546 1,584 1,624 1,665 1,706 1,749 1,793 1,837 1,883

706 723 741 760 779 798 818 839 860 881 903 926 949 973 997

1,704 1,754 1,806 1,859 1,857 1,912 1,968 2,026 2,085 2,147 2,210 2,207 2,272 2,339 2,408

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

91 93 95 98 100 103 105 108 110 113 116 119 122 125 128

45 46 48 49 50 51 53 54 55 57 58 59 61 62 64

0 0 0 0 164 0 0 0 0 0 0 195 0 0 0

3,879 3,983 4,091 4,201 4,421 4,372 4,490 4,611 4,735 4,862 4,993 5,255 5,197 5,337 5,480

1,814 1,860 1,906 1,954 2,003 2,053 2,104 2,157 2,211 2,266 2,323 2,381 2,440 2,501 2,564

778 797 817 837 858 880 902 924 947 971 995 1,020 1,046 1,072 1,099

71 73 75 76 78 80 82 84 87 89 91 93 96 98 100

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

227 233 238 244 251 257 263 270 277 283 291 298 305 313 321

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

578 593 608 623 638 654 671 688 705 722 740 759 778 797 817

3,468 3,555 3,644 3,735 3,828 3,924 4,022 4,123 4,226 4,332 4,440 4,551 4,665 4,781 4,901

173 181 190 200 210 0 0 0 0 0 0 0 0 0 0

48 39 30 20 10 0 0 0 0 0 0 0 0 0 0

220 220 220 220 220 0 0 0 0 0 0 0 0 0 0

(410) (428) (447) (466) (592) (447) (467) (488) (509) (531) (553) (704) (532) (555) (580)

(48) (39) (30) (20) (10) 0 0 0 0 0 0 0 0 0 0

(586) (586) (586) (586) (586) 0 0 0 0 0 0 0 0 0 0

(1,044) (1,053) (1,063) (1,072) (1,189) (447) (467) (488) (509) (531) (553) (704) (532) (555) (580)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

(410) (428) (447) (466) (592) (447) (467) (488) (509) (531) (553) (704) (532) (555) (580)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

(220) (220) (220) (220) (220) 0 0 0 0 0 0 0 0 0 0

(631) (649) (667) (686) (813) (447) (467) (488) (509) (531) (553) (704) (532) (555) (580)

< 0 < 0 < 0 < 0 < 0 NA NA NA NA NA NA NA NA NA NA

3,202

(631) (649) (667) (686) (813) (447) (467) (488) (509) (531) (553) (704) (532) (555) 2,622

(184) (175) (167) (159) (174) (89) (86) (83) (80) (77) (75) (88) (62) (60) 261

(7,131) (7,306) (7,473) (7,632) (7,807) (7,895) (7,981) (8,064) (8,145) (8,222) (8,297) (8,385) (8,447) (8,506) (8,246)



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 174 179 183 188 192 197 202 207 212 218 223 229 234 240 246 252

j Insurance 87 89 92 94 96 99 101 104 106 109 112 114 117 120 123 126


l Other

m Total Cost 4,982 5,117 5,256 5,398 5,545 5,695 5,850 6,009 6,172 6,452 6,364 6,538 6,715 6,898 7,086


a Energy 3,638 3,729 3,822 3,917 4,015 4,116 4,219 4,324 4,432 4,543 4,657 4,773 4,892 5,015 5,140 5,268

b Avoided Distribution 1,559 1,598 1,638 1,679 1,721 1,764 1,808 1,853 1,899 1,947 1,996 2,046 2,097 2,149 2,203 2,258


d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Hot Water 390 399 409 420 430 441 452 463 475 487 499 511 524 537 551 564

h Total Revenues 5,971 6,120 6,273 6,430 6,591 6,756 6,925 7,098 7,275 7,457 7,644 7,835 8,030 8,231 8,437


a Principal 237 249 262 275 288 303 318 334 350 368 386 406 426 447 470

b Interest 392 380 368 355 341 327 312 296 279 261 243 224 203 182 160


4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt 989 1,003 1,018 1,032 1,046 1,061 1,075 1,089 1,104 1,005 1,279 1,297 1,315 1,333 1,351


c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (274) (248) (222) (194) (166) (138) (108) (78) (47) (128) 165 202 240 279 320

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 66 81 96 112 128


a Cash, Pre‐Tax, Pre‐Debt 989 1,003 1,018 1,032 1,046 1,061 1,075 1,089 1,104 1,005 1,279 1,297 1,315 1,333 1,351

b Fed & State Income Tax 0 0 0 0 0 0 0 0 0 0 (66) (81) (96) (112) (128)

c Debt Service (629) (629) (629) (629) (629) (629) (629) (629) (629) (629) (629) (629) (629) (629) (629)




a Investment Tax Credits 1,743

b Equity 7,843

c Residual


e NPV (6,100) 333 321 308 296 284 272 260 248 237 174 250 233 217 202 187

f Cum NPV 775 (5,767) (5,446) (5,138) (4,842) (4,559) (4,287) (4,027) (3,779) (3,541) (3,367) (3,117) (2,884) (2,667) (2,465) (2,278)

g IRR 9%



Study Year

Calendar Year


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Hot Water

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

5,100 5,244 5,391 5,543 5,526 5,682 5,843 6,009 6,179 6,354 6,534 6,719 6,909 7,105 7,074

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

259 265 272 279 286 293 300 308 315 323 331 340 348 357 366

129 133 136 139 143 146 150 154 158 162 166 170 174 178 183

0 0 0 0 328 0 0 0 0 0 0 0 0 0 420

7,279 7,477 7,681 7,890 8,259 8,148 8,370 8,599 8,834 9,075 9,323 9,578 9,840 10,109 10,572

5,400 5,535 5,674 5,815 5,961 6,110 6,262 6,419 6,580 6,744 6,913 7,085 7,263 7,444 7,630

2,314 2,372 2,432 2,492 2,555 2,618 2,684 2,751 2,820 2,890 2,963 3,037 3,113 3,190 3,270

355 364 373 382 392 402 412 422 433 443 455 466 478 490 502

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

578 593 608 623 638 654 671 688 705 722 740 759 778 797 817

8,648 8,864 9,086 9,313 9,546 9,784 10,029 10,280 10,537 10,800 11,070 11,347 11,631 11,921 12,219

493 518 544 571 599 0 0 0 0 0 0 0 0 0 0

136 112 86 59 30 0 0 0 0 0 0 0 0 0 0

629 629 629 629 629 0 0 0 0 0 0 0 0 0 0

1,369 1,387 1,405 1,423 1,287 1,637 1,659 1,681 1,703 1,725 1,747 1,769 1,791 1,812 1,647

(136) (112) (86) (59) (30) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

361 404 448 493 385 1,637 1,659 1,681 1,703 1,725 1,747 1,769 1,791 1,812 1,647

145 162 179 197 154 655 664 672 681 690 699 708 716 725 659

1,369 1,387 1,405 1,423 1,287 1,637 1,659 1,681 1,703 1,725 1,747 1,769 1,791 1,812 1,647

(145) (162) (179) (197) (154) (655) (664) (672) (681) (690) (699) (708) (716) (725) (659)

(629) (629) (629) (629) (629) 0 0 0 0 0 0 0 0 0 0

595 596 597 596 503 982 995 1,009 1,022 1,035 1,048 1,061 1,074 1,087 988


9,140

595 596 597 596 503 982 995 1,009 1,022 1,035 1,048 1,061 1,074 1,087 10,128

174 161 149 138 108 195 183 172 161 151 142 133 125 117 1,007

(2,105) (1,943) (1,794) (1,656) (1,548) (1,353) (1,170) (998) (837) (686) (544) (411) (287) (170) 837



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 117 120 123 126 129 133 136 139 143 146 150 154 158 162 166 170

j Insurance 59 60 62 63 65 66 68 70 71 73 75 77 79 81 83 85


l Other

m Total Cost 3,845 3,952 4,062 4,174 4,290 4,442 4,446 4,570 4,697 4,828 4,962 5,100 5,280 5,285 5,432


a Energy 2,669 2,736 2,804 2,875 2,946 3,020 3,096 3,173 3,252 3,334 3,417 3,502 3,590 3,680 3,772 3,866



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 4,000 4,100 4,202 4,307 4,415 4,525 4,638 4,754 4,873 4,995 5,120 5,248 5,379 5,514 5,651


a Principal 160 168 176 185 194 204 214 225 236 248 260 273 287 301 316

b Interest 264 256 247 239 229 220 210 199 188 176 163 150 137 122 107


4 Taxes ($1,000's)



c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (980) (979) (978) (977) (976) (1,008) (889) (886) (883) (880) (877) (874) (909) (766) (760)

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0




c Debt Service (423) (423) (423) (423) (423) (423) (423) (423) (423) (423) (423) (423) (423) (423) (423)

d Cash after Taxes & Debt (268) (275) (283) (291) (299) (340) (231) (239) (247) (256) (266) (275) (324) (195) (204)




b Equity 5,277

c Residual

d Cash after Taxes & Debt (4,104) (268) (275) (283) (291) (299) (340) (231) (239) (247) (256) (266) (275) (324) (195) (204)

e NPV (4,104) (249) (236) (224) (214) (203) (214) (135) (129) (124) (119) (114) (109) (119) (66) (64)

f Cum NPV (5,466) (4,353) (4,589) (4,813) (5,027) (5,230) (5,444) (5,580) (5,709) (5,833) (5,951) (6,065) (6,174) (6,294) (6,360) (6,425)

g IRR #DIV/0!



Study Year

Calendar Year


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

3,532 3,636 3,743 3,853 3,848 3,961 4,078 4,198 4,322 4,449 4,579 4,574 4,709 4,847 4,990

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

174 178 183 187 192 197 202 207 212 217 223 228 234 240 246

87 89 91 94 96 98 101 103 106 109 111 114 117 120 123

0 0 0 0 164 0 0 0 0 0 0 195 0 0 0

5,584 5,739 5,898 6,062 6,277 6,283 6,458 6,637 6,822 7,011 7,206 7,461 7,468 7,676 7,889

3,963 4,062 4,163 4,267 4,374 4,483 4,595 4,710 4,828 4,949 5,073 5,199 5,329 5,463 5,599

1,698 1,741 1,784 1,829 1,875 1,921 1,969 2,019 2,069 2,121 2,174 2,228 2,284 2,341 2,400

132 135 138 142 146 149 153 157 161 165 169 173 177 182 186

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

5,793 5,938 6,086 6,238 6,394 6,554 6,718 6,886 7,058 7,234 7,415 7,601 7,791 7,985 8,185

332 348 366 384 403 0 0 0 0 0 0 0 0 0 0

92 75 58 39 20 0 0 0 0 0 0 0 0 0 0

423 423 423 423 423 0 0 0 0 0 0 0 0 0 0

209 199 188 176 118 271 260 249 236 223 209 140 322 309 296

(92) (75) (58) (39) (20) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

(754) (748) (741) (735) (774) 271 260 249 236 223 209 140 322 309 296

0 0 0 0 0 108 104 99 94 89 84 56 129 124 118

209 199 188 176 118 271 260 249 236 223 209 140 322 309 296

0 0 0 0 0 (108) (104) (99) (94) (89) (84) (56) (129) (124) (118)

(423) (423) (423) (423) (423) 0 0 0 0 0 0 0 0 0 0

(214) (225) (236) (247) (306) 163 156 149 142 134 125 84 193 186 177


6,149

(214) (225) (236) (247) (306) 163 156 149 142 134 125 84 193 186 6,326

(63) (61) (59) (57) (66) 32 29 25 22 20 17 10 22 20 629

(6,487) (6,548) (6,607) (6,664) (6,730) (6,698) (6,669) (6,643) (6,621) (6,602) (6,585) (6,574) (6,552) (6,532) (5,903)



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 265 271 278 285 292 299 307 314 322 330 339 347 356 365 374 383

j Insurance 132 136 139 142 146 150 153 157 161 165 169 174 178 182 187 192


l Other

m Total Cost 6,402 6,577 6,758 6,943 7,134 7,329 7,530 7,737 7,887 7,976 8,195 8,419 8,651 8,888 9,132


a Energy 5,243 5,374 5,509 5,646 5,788 5,932 6,081 6,233 6,388 6,548 6,712 6,880 7,052 7,228 7,409 7,594



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 7,951 8,150 8,353 8,562 8,776 8,996 9,220 9,451 9,687 9,929 10,178 10,432 10,693 10,960 11,234


a Principal 360 378 397 417 438 460 483 507 532 559 587 616 647 679 713

b Interest 595 577 558 539 518 496 473 449 423 397 369 340 309 276 242


4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt 1,549 1,572 1,596 1,619 1,643 1,666 1,690 1,714 1,800 1,954 1,983 2,013 2,042 2,072 2,103


c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income 82 123 166 209 253 299 346 394 505 686 743 802 862 925 989

e Fed & State Taxes 33 49 66 84 101 120 138 158 202 274 297 321 345 370 395



b Fed & State Income Tax (33) (49) (66) (84) (101) (120) (138) (158) (202) (274) (297) (321) (345) (370) (395)

c Debt Service (955) (955) (955) (955) (955) (955) (955) (955) (955) (955) (955) (955) (955) (955) (955)





b Equity 11,906

c Residual


e NPV (9,260) 519 487 456 426 399 373 348 325 321 335 313 293 273 254 237

f Cum NPV 764 (8,741) (8,254) (7,799) (7,372) (6,973) (6,601) (6,253) (5,928) (5,606) (5,271) (4,958) (4,665) (4,392) (4,138) (3,901)

g IRR 9%



Study Year

Calendar Year


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

7,002 7,200 7,403 7,374 7,582 7,797 8,018 8,244 8,477 8,717 8,963 9,216 9,477 9,439 9,706

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

393 403 413 423 434 444 455 467 479 491 503 515 528 541 555

196 201 206 211 217 222 228 233 239 245 251 258 264 271 277

0 0 0 160 0 0 0 0 0 0 0 0 0 205 0

9,382 9,639 9,904 10,097 10,209 10,490 10,778 11,073 11,377 11,689 12,010 12,339 12,677 12,924 13,069

7,784 7,978 8,178 8,382 8,592 8,807 9,027 9,252 9,484 9,721 9,964 10,213 10,468 10,730 10,998

3,336 3,419 3,505 3,592 3,682 3,774 3,869 3,965 4,064 4,166 4,270 4,377 4,486 4,599 4,714

395 405 415 426 437 447 459 470 482 494 506 519 532 545 559

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

11,515 11,803 12,098 12,401 12,711 13,028 13,354 13,688 14,030 14,381 14,740 15,109 15,487 15,874 16,271

749 786 825 867 910 0 0 0 0 0 0 0 0 0 0

207 169 130 89 45 0 0 0 0 0 0 0 0 0 0

955 955 955 955 955 0 0 0 0 0 0 0 0 0 0

2,133 2,164 2,195 2,304 2,501 2,539 2,576 2,614 2,653 2,692 2,731 2,770 2,809 2,949 3,202

(207) (169) (130) (89) (45) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

1,055 1,123 1,193 1,344 1,584 2,539 2,576 2,614 2,653 2,692 2,731 2,770 2,809 2,949 3,202

422 449 477 537 634 1,015 1,031 1,046 1,061 1,077 1,092 1,108 1,124 1,180 1,281

2,133 2,164 2,195 2,304 2,501 2,539 2,576 2,614 2,653 2,692 2,731 2,770 2,809 2,949 3,202

(422) (449) (477) (537) (634) (1,015) (1,031) (1,046) (1,061) (1,077) (1,092) (1,108) (1,124) (1,180) (1,281)

(955) (955) (955) (955) (955) 0 0 0 0 0 0 0 0 0 0

756 759 762 811 912 1,523 1,546 1,569 1,592 1,615 1,638 1,662 1,686 1,770 1,921


13,874

756 759 762 811 912 1,523 1,546 1,569 1,592 1,615 1,638 1,662 1,686 1,770 15,795

221 205 191 188 196 303 284 267 251 236 222 208 195 190 1,570

(3,680) (3,475) (3,284) (3,096) (2,901) (2,598) (2,314) (2,046) (1,795) (1,560) (1,338) (1,130) (935) (745) 825



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(1) Solar Taurus 60

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 107 109 112 115 118 121 124 127 130 133 137 140 144 147 151 155

j Insurance 53 55 56 57 59 60 62 63 65 67 68 70 72 74 75 77


l Other

m Total Cost 3,782 3,884 3,988 4,095 4,205 4,318 4,433 4,552 4,674 4,834 4,833 4,962 5,096 5,232 5,373


a Energy 2,143 2,197 2,252 2,308 2,366 2,425 2,485 2,547 2,611 2,676 2,743 2,812 2,882 2,954 3,028 3,104

b Avoided Distribution 918 941 965 989 1,014 1,039 1,065 1,092 1,119 1,147 1,176 1,205 1,235 1,266 1,298 1,330


d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 3,254 3,335 3,418 3,504 3,591 3,681 3,773 3,868 3,964 4,063 4,165 4,269 4,376 4,485 4,597


a Principal 145 153 160 168 177 185 195 204 215 225 237 248 261 274 288

b Interest 240 233 225 217 209 200 191 181 171 160 149 137 125 112 98


4 Taxes ($1,000's)



c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (1,640) (1,653) (1,666) (1,680) (1,694) (1,708) (1,722) (1,737) (1,752) (1,803) (1,688) (1,702) (1,716) (1,730) (1,745)

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0




c Debt Service (385) (385) (385) (385) (385) (385) (385) (385) (385) (385) (385) (385) (385) (385) (385)

d Cash after Taxes & Debt (914) (934) (955) (977) (999) (1,022) (1,046) (1,070) (1,096) (1,157) (1,053) (1,079) (1,105) (1,133) (1,161)

6 Debt Coverage Ratio < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0 < 0



b Equity 4,804

c Residual

d Cash after Taxes & Debt (3,736) (914) (934) (955) (977) (999) (1,022) (1,046) (1,070) (1,096) (1,157) (1,053) (1,079) (1,105) (1,133) (1,161)

e NPV (3,736) (846) (801) (758) (718) (680) (644) (610) (578) (548) (536) (452) (428) (406) (386) (366)

f Cum NPV (13,845) (4,583) (5,384) (6,142) (6,859) (7,539) (8,183) (8,793) (9,371) (9,919) (10,455) (10,907) (11,335) (11,742) (12,127) (12,493)

g IRR #DIV/0!



Study Year

Calendar Year

(1) Solar Taurus 60

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

3,488 3,586 3,686 3,788 3,894 3,880 3,988 4,100 4,214 4,332 4,453 4,577 4,705 4,836 4,971

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

158 162 167 171 175 179 184 188 193 198 203 208 213 218 224

79 81 83 85 87 90 92 94 97 99 101 104 107 109 112

0 0 0 0 0 168 0 0 0 0 0 0 0 0 0

5,517 5,665 5,817 5,973 6,133 6,343 6,341 6,511 6,686 6,865 7,050 7,239 7,433 7,632 7,837

3,181 3,261 3,342 3,426 3,512 3,599 3,689 3,782 3,876 3,973 4,072 4,174 4,279 4,386 4,495

1,363 1,398 1,432 1,468 1,505 1,543 1,581 1,621 1,661 1,703 1,745 1,789 1,834 1,880 1,927

167 172 176 180 185 189 194 199 204 209 214 220 225 231 237

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

4,712 4,830 4,951 5,075 5,201 5,332 5,465 5,601 5,741 5,885 6,032 6,183 6,337 6,496 6,658

302 317 333 350 367 0 0 0 0 0 0 0 0 0 0

83 68 52 36 18 0 0 0 0 0 0 0 0 0 0

385 385 385 385 385 0 0 0 0 0 0 0 0 0 0

(805) (835) (866) (898) (932) (1,012) (876) (910) (945) (980) (1,018) (1,056) (1,095) (1,136) (1,179)

(83) (68) (52) (36) (18) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

(1,760) (1,775) (1,790) (1,806) (1,822) (1,012) (876) (910) (945) (980) (1,018) (1,056) (1,095) (1,136) (1,179)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

(805) (835) (866) (898) (932) (1,012) (876) (910) (945) (980) (1,018) (1,056) (1,095) (1,136) (1,179)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

(385) (385) (385) (385) (385) 0 0 0 0 0 0 0 0 0 0

(1,190) (1,220) (1,252) (1,284) (1,317) (1,012) (876) (910) (945) (980) (1,018) (1,056) (1,095) (1,136) (1,179)

< 0 < 0 < 0 < 0 < 0 NA NA NA NA NA NA NA NA NA NA

5,598

(1,190) (1,220) (1,252) (1,284) (1,317) (1,012) (876) (910) (945) (980) (1,018) (1,056) (1,095) (1,136) 4,419

(347) (330) (313) (297) (283) (201) (161) (155) (149) (143) (138) (132) (127) (122) 439

(12,841) (13,170) (13,484) (13,781) (14,064) (14,265) (14,426) (14,581) (14,730) (14,873) (15,011) (15,143) (15,270) (15,392) (14,952)



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(3) Solar Taurus 60

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 229 235 241 247 253 259 266 273 279 286 294 301 308 316 324 332

j Insurance 115 118 120 123 127 130 133 136 140 143 147 150 154 158 162 166


l Other

m Total Cost 9,915 10,193 10,479 10,773 11,075 11,386 11,705 11,837 12,044 12,382 12,730 13,087 13,454 13,831 14,219


a Energy 7,481 7,668 7,860 8,056 8,258 8,464 8,676 8,893 9,115 9,343 9,577 9,816 10,061 10,313 10,571 10,835



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 11,301 11,584 11,874 12,170 12,475 12,787 13,106 13,434 13,770 14,114 14,467 14,829 15,199 15,579 15,969


a Principal 312 328 344 361 379 398 418 439 461 484 508 534 560 588 618

b Interest 516 500 484 467 449 430 410 389 367 344 320 294 268 240 210


4 Taxes ($1,000's)



c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (1) 19 39 59 79 100 120 337 488 517 546 576 606 637 668

e Fed & State Taxes 0 8 16 24 32 40 48 135 195 207 218 230 242 255 267



b Fed & State Income Tax 0 (8) (16) (24) (32) (40) (48) (135) (195) (207) (218) (230) (242) (255) (267)

c Debt Service (828) (828) (828) (828) (828) (828) (828) (828) (828) (828) (828) (828) (828) (828) (828)





b Equity 10,319

c Residual


e NPV (8,026) 517 476 437 401 367 336 307 343 352 323 296 271 248 226 206

f Cum NPV 1,218 (7,508) (7,032) (6,595) (6,194) (5,826) (5,491) (5,184) (4,841) (4,490) (4,167) (3,870) (3,599) (3,351) (3,124) (2,918)

g IRR 9%



Study Year

Calendar Year

(3) Solar Taurus 60

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

12,316 12,271 12,623 12,985 13,357 13,740 14,133 14,538 14,954 15,381 15,325 15,765 16,217 16,681 17,159

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

340 349 358 367 376 385 395 405 415 425 436 447 458 469 481

170 174 179 183 188 193 197 202 207 213 218 223 229 235 240

0 152 0 0 0 0 0 0 0 0 190 0 0 0 0

14,618 14,782 15,041 15,463 15,898 16,344 16,802 17,274 17,758 18,256 18,461 18,784 19,312 19,854 20,411

11,106 11,384 11,668 11,960 12,259 12,565 12,879 13,201 13,531 13,870 14,216 14,572 14,936 15,310 15,692

4,760 4,879 5,001 5,126 5,254 5,385 5,520 5,658 5,799 5,944 6,093 6,245 6,401 6,561 6,725

502 515 528 541 555 568 583 597 612 627 643 659 676 693 710

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

16,368 16,777 17,197 17,626 18,067 18,519 18,982 19,456 19,943 20,441 20,952 21,476 22,013 22,563 23,127

649 681 715 751 789 0 0 0 0 0 0 0 0 0 0

179 147 113 77 39 0 0 0 0 0 0 0 0 0 0

828 828 828 828 828 0 0 0 0 0 0 0 0 0 0

1,750 1,995 2,155 2,163 2,170 2,175 2,179 2,183 2,185 2,186 2,491 2,692 2,701 2,709 2,716

(179) (147) (113) (77) (39) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

699 977 1,171 1,215 1,259 2,175 2,179 2,183 2,185 2,186 2,491 2,692 2,701 2,709 2,716

280 391 468 486 503 870 872 873 874 874 997 1,077 1,081 1,084 1,087

1,750 1,995 2,155 2,163 2,170 2,175 2,179 2,183 2,185 2,186 2,491 2,692 2,701 2,709 2,716

(280) (391) (468) (486) (503) (870) (872) (873) (874) (874) (997) (1,077) (1,081) (1,084) (1,087)

(828) (828) (828) (828) (828) 0 0 0 0 0 0 0 0 0 0

642 776 859 849 838 1,305 1,308 1,310 1,311 1,311 1,495 1,615 1,621 1,626 1,630


12,025

642 776 859 849 838 1,305 1,308 1,310 1,311 1,311 1,495 1,615 1,621 1,626 13,655

188 210 215 197 180 259 241 223 207 191 202 202 188 174 1,357

(2,731) (2,521) (2,306) (2,109) (1,929) (1,670) (1,430) (1,206) (1,000) (808) (606) (404) (216) (42) 1,315



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(1) Solar Taurus 70

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 126 129 132 135 139 142 146 149 153 157 161 165 169 173 178 182

j Insurance 63 64 66 68 69 71 73 75 77 78 80 82 85 87 89 91


l Other

m Total Cost 6,151 6,326 6,506 6,691 6,881 7,029 7,110 7,312 7,520 7,734 7,953 8,179 8,356 8,452 8,692


a Energy 4,606 4,721 4,839 4,960 5,084 5,211 5,341 5,475 5,612 5,752 5,896 6,043 6,194 6,349 6,508 6,671



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 6,904 7,077 7,254 7,435 7,621 7,812 8,007 8,207 8,412 8,622 8,838 9,059 9,285 9,518 9,756


a Principal 171 180 189 198 208 218 229 241 253 265 279 293 307 323 339

b Interest 283 274 265 256 246 236 225 213 201 188 175 161 147 131 115


4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt 753 751 748 744 740 782 897 895 892 889 885 880 930 1,066 1,064


c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (401) (395) (389) (383) (377) (325) (199) (190) (180) (171) (162) (153) (88) 63 77

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 0 0 0 25 31


a Cash, Pre‐Tax, Pre‐Debt 753 751 748 744 740 782 897 895 892 889 885 880 930 1,066 1,064

b Fed & State Income Tax 0 0 0 0 0 0 0 0 0 0 0 0 0 (25) (31)

c Debt Service (454) (454) (454) (454) (454) (454) (454) (454) (454) (454) (454) (454) (454) (454) (454)





b Equity 5,656

c Residual


e NPV (4,399) 277 254 233 214 195 207 258 238 219 202 185 169 175 200 183

f Cum NPV 1,209 (4,122) (3,868) (3,634) (3,421) (3,225) (3,019) (2,760) (2,522) (2,303) (2,101) (1,916) (1,747) (1,572) (1,372) (1,189)

g IRR 10%



Study Year

Calendar Year

(1) Solar Taurus 70

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

6,868 7,070 7,278 7,492 7,483 7,704 7,931 8,164 8,404 8,652 8,906 8,895 9,157 9,427 9,705

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

187 191 196 201 206 211 216 222 227 233 239 245 251 257 264

93 96 98 100 103 106 108 111 114 117 119 122 125 129 132

0 0 0 0 164 0 0 0 0 0 0 195 0 0 0

8,939 9,193 9,454 9,722 9,932 10,046 10,332 10,625 10,927 11,238 11,557 11,806 11,942 12,281 12,630

6,837 7,008 7,184 7,363 7,547 7,736 7,929 8,128 8,331 8,539 8,753 8,971 9,196 9,426 9,661

2,930 3,004 3,079 3,156 3,235 3,315 3,398 3,483 3,570 3,660 3,751 3,845 3,941 4,040 4,141

232 237 243 249 256 262 269 275 282 289 296 304 311 319 327

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

9,999 10,249 10,506 10,768 11,038 11,313 11,596 11,886 12,183 12,488 12,800 13,120 13,448 13,784 14,129

356 373 392 412 432 0 0 0 0 0 0 0 0 0 0

98 80 62 42 22 0 0 0 0 0 0 0 0 0 0

454 454 454 454 454 0 0 0 0 0 0 0 0 0 0

1,061 1,057 1,052 1,046 1,105 1,267 1,264 1,261 1,256 1,250 1,244 1,314 1,506 1,503 1,499

(98) (80) (62) (42) (22) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

91 105 119 133 212 1,267 1,264 1,261 1,256 1,250 1,244 1,314 1,506 1,503 1,499

36 42 47 53 85 507 506 504 502 500 497 525 602 601 599

1,061 1,057 1,052 1,046 1,105 1,267 1,264 1,261 1,256 1,250 1,244 1,314 1,506 1,503 1,499

(36) (42) (47) (53) (85) (507) (506) (504) (502) (500) (497) (525) (602) (601) (599)

(454) (454) (454) (454) (454) 0 0 0 0 0 0 0 0 0 0

570 561 551 539 567 760 759 756 754 750 746 788 904 902 899


6,591

570 561 551 539 567 760 759 756 754 750 746 788 904 902 7,490

167 152 138 125 122 151 140 129 119 110 101 99 105 97 744

(1,023) (871) (734) (609) (487) (336) (196) (68) 51 161 262 360 465 562 1,306



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

(2) Solar Taurus 70

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 206 211 216 222 227 233 239 245 251 257 264 270 277 284 291 298

j Insurance 103 106 108 111 114 117 119 122 126 129 132 135 139 142 146 149


l Other

m Total Cost 7,159 7,355 7,556 7,763 7,975 8,193 8,417 8,647 8,884 9,027 9,143 9,393 9,650 9,914 10,185


a Energy 5,483 5,620 5,761 5,905 6,052 6,204 6,359 6,518 6,681 6,848 7,019 7,194 7,374 7,559 7,748 7,941



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 8,349 8,558 8,771 8,991 9,216 9,446 9,682 9,924 10,172 10,427 10,687 10,954 11,228 11,509 11,797


a Principal 280 294 309 325 341 358 376 395 414 435 457 480 504 529 555

b Interest 464 450 435 419 403 386 368 349 330 309 287 264 240 215 189


4 Taxes ($1,000's)



c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (145) (118) (91) (63) (34) (5) 25 56 88 219 386 426 466 508 551

e Fed & State Taxes 0 0 0 0 0 0 10 22 35 88 154 170 187 203 220



b Fed & State Income Tax 0 0 0 0 0 0 (10) (22) (35) (88) (154) (170) (187) (203) (220)

c Debt Service (744) (744) (744) (744) (744) (744) (744) (744) (744) (744) (744) (744) (744) (744) (744)





b Equity 9,271

c Residual


e NPV (7,211) 413 394 374 356 338 321 298 276 255 263 277 257 238 221 204

f Cum NPV 869 (6,797) (6,404) (6,030) (5,674) (5,336) (5,015) (4,717) (4,441) (4,186) (3,923) (3,645) (3,388) (3,150) (2,930) (2,726)

g IRR 9%



Study Year

Calendar Year

(2) Solar Taurus 70

Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

8,214 8,444 8,680 8,923 9,173 9,131 9,387 9,650 9,921 10,199 10,484 10,778 11,079 11,389 11,708

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

306 313 321 329 338 346 355 364 373 382 391 401 411 422 432

153 157 161 165 169 173 177 182 186 191 196 201 206 211 216

0 0 0 0 0 168 0 0 0 0 0 0 0 0 0

10,464 10,750 11,044 11,346 11,656 11,844 11,996 12,324 12,661 13,008 13,364 13,729 14,105 14,491 14,887

8,140 8,343 8,552 8,766 8,985 9,210 9,440 9,676 9,918 10,166 10,420 10,680 10,947 11,221 11,501

3,489 3,576 3,665 3,757 3,851 3,947 4,046 4,147 4,250 4,357 4,466 4,577 4,692 4,809 4,929

463 475 487 499 511 524 537 551 564 578 593 608 623 638 654

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

12,092 12,394 12,704 13,021 13,347 13,680 14,023 14,373 14,732 15,101 15,478 15,865 16,262 16,668 17,085

583 612 643 675 708 0 0 0 0 0 0 0 0 0 0

161 132 101 69 35 0 0 0 0 0 0 0 0 0 0

744 744 744 744 744 0 0 0 0 0 0 0 0 0 0

1,628 1,644 1,660 1,675 1,691 1,836 2,027 2,049 2,071 2,093 2,114 2,136 2,157 2,178 2,198

(161) (132) (101) (69) (35) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

595 640 687 735 784 1,836 2,027 2,049 2,071 2,093 2,114 2,136 2,157 2,178 2,198

238 256 275 294 314 735 811 820 828 837 846 854 863 871 879

1,628 1,644 1,660 1,675 1,691 1,836 2,027 2,049 2,071 2,093 2,114 2,136 2,157 2,178 2,198

(238) (256) (275) (294) (314) (735) (811) (820) (828) (837) (846) (854) (863) (871) (879)

(744) (744) (744) (744) (744) 0 0 0 0 0 0 0 0 0 0

646 644 641 638 633 1,102 1,216 1,229 1,243 1,256 1,269 1,281 1,294 1,307 1,319


10,803

646 644 641 638 633 1,102 1,216 1,229 1,243 1,256 1,269 1,281 1,294 1,307 12,122

188 174 160 148 136 219 224 209 196 183 172 160 150 140 1,205

(2,537) (2,363) (2,203) (2,055) (1,919) (1,700) (1,477) (1,267) (1,071) (888) (716) (556) (406) (266) 939



Study Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calendar Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M 889 912 935 958 982 1,006 1,032 1,057 1,084 1,111 1,139 1,167 1,196 1,226 1,257 1,288

c Variable O&M 317 325 333 341 350 359 367 377 386 396 406 416 426 437 448 459




g Other Fuel


i Property Taxes 162 166 170 174 178 183 187 192 197 202 207 212 217 223 228 234

j Insurance 81 83 85 87 89 91 94 96 98 101 103 106 109 111 114 117


l Other

m Total Cost 5,768 5,924 6,083 6,247 6,415 6,588 6,765 6,947 7,167 7,326 7,487 7,554 7,758 7,967 8,181


a Energy 4,303 4,411 4,521 4,634 4,750 4,869 4,990 5,115 5,243 5,374 5,508 5,646 5,787 5,932 6,080 6,232



d Credits/RECs 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

e Steam 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

f Fuel Sales 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

g Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

h Total Revenues 6,616 6,781 6,951 7,125 7,303 7,485 7,672 7,864 8,061 8,262 8,469 8,681 8,898 9,120 9,348


a Principal 220 231 242 255 267 281 295 309 325 341 358 376 395 415 435

b Interest 363 352 341 329 316 303 289 274 259 242 225 207 189 169 148


4 Taxes ($1,000's)

a Cash, Pre‐Tax, Pre‐Debt 848 858 868 878 888 897 907 917 894 936 982 1,127 1,140 1,154 1,167


c Depreciation (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871) (871)

d Taxable Income (387) (366) (345) (323) (300) (277) (253) (229) (236) (177) (115) 48 80 113 147

e Fed & State Taxes 0 0 0 0 0 0 0 0 0 0 0 19 32 45 59


a Cash, Pre‐Tax, Pre‐Debt 848 858 868 878 888 897 907 917 894 936 982 1,127 1,140 1,154 1,167

b Fed & State Income Tax 0 0 0 0 0 0 0 0 0 0 0 (19) (32) (45) (59)

c Debt Service (583) (583) (583) (583) (583) (583) (583) (583) (583) (583) (583) (583) (583) (583) (583)





b Equity 7,270

c Residual


e NPV (5,654) 245 235 226 216 207 198 189 180 155 163 171 208 193 179 165

f Cum NPV 27 (5,409) (5,174) (4,948) (4,732) (4,525) (4,327) (4,138) (3,958) (3,803) (3,639) (3,468) (3,260) (3,067) (2,888) (2,723)

g IRR 8%



Study Year

Calendar Year


Simple Cycle

No Item

1 Costs ($1,000's)


b Fixed O&M

c Variable O&M




g Other Fuel

h Transportation

i Property Taxes

j Insurance

k Major Maintenance

l Other

m Total Cost


a Energy



d Credits/RECs

e Steam

f Fuel Sales

g Other

h Total Revenues

3 Debt Service

a Principal

b Interest


4 Taxes ($1,000's)


b Interest Payment

c Depreciation

d Taxable Income

e Fed & State Taxes




c Debt Service





b Equity

c Residual


e NPV

f Cum NPV

g IRR

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

1,320 1,353 1,387 1,422 1,458 1,494 1,531 1,570 1,609 1,649 1,690 1,733 1,776 1,820 1,866

470 482 494 507 519 532 546 559 573 587 602 617 633 648 665

6,251 6,423 6,600 6,782 6,969 7,161 7,359 7,337 7,539 7,747 7,961 8,181 8,407 8,639 8,877

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

240 246 252 258 265 271 278 285 292 300 307 315 323 331 339

120 123 126 129 132 136 139 143 146 150 153 157 161 165 169

0 0 0 0 0 0 0 176 0 0 0 0 0 0 0

8,401 8,628 8,860 9,098 9,343 9,595 9,853 10,069 10,160 10,433 10,714 11,003 11,299 11,603 11,916

6,388 6,548 6,711 6,879 7,051 7,228 7,408 7,593 7,783 7,978 8,177 8,382 8,591 8,806 9,026

2,738 2,806 2,876 2,948 3,022 3,098 3,175 3,254 3,336 3,419 3,505 3,592 3,682 3,774 3,868

456 467 479 491 503 516 529 542 556 570 584 598 613 629 644

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

9,582 9,821 10,067 10,319 10,577 10,841 11,112 11,390 11,675 11,966 12,266 12,572 12,887 13,209 13,539

457 480 504 529 556 0 0 0 0 0 0 0 0 0 0

126 103 79 54 28 0 0 0 0 0 0 0 0 0 0

583 583 583 583 583 0 0 0 0 0 0 0 0 0 0

1,180 1,194 1,207 1,220 1,233 1,246 1,259 1,320 1,515 1,533 1,551 1,569 1,588 1,605 1,623

(126) (103) (79) (54) (28) 0 0 0 0 0 0 0 0 0 0

(871) (871) (871) (871) (871) 0 0 0 0 0 0 0 0 0 0

183 219 256 295 334 1,246 1,259 1,320 1,515 1,533 1,551 1,569 1,588 1,605 1,623

73 88 102 118 134 499 504 528 606 613 621 628 635 642 649

1,180 1,194 1,207 1,220 1,233 1,246 1,259 1,320 1,515 1,533 1,551 1,569 1,588 1,605 1,623

(73) (88) (102) (118) (134) (499) (504) (528) (606) (613) (621) (628) (635) (642) (649)

(583) (583) (583) (583) (583) 0 0 0 0 0 0 0 0 0 0

524 523 521 519 516 748 756 792 909 920 931 942 953 963 974


8,471

524 523 521 519 516 748 756 792 909 920 931 942 953 963 9,445

153 141 130 120 111 149 139 135 143 134 126 118 110 103 939

(2,570) (2,429) (2,298) (2,178) (2,067) (1,919) (1,780) (1,645) (1,501) (1,367) (1,241) (1,123) (1,013) (910) 29


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