Advanced Gas Cooling Study for the

Hospital at Davis-Monthan AFB, AZ

by

Michael A. Caponegro

William T. Brown III

Timothy W. Pedersen

Based on its experience with a cogeneration

project at Tyndall AFB, the Air Force Civil

Engineering Support Agency (AFCESA) tasked

the U.S. Army Construction Engineering

Research Laboratories (USACERL) to perform

an analysis to see if such a concept, or some

other cooling options, could be of economic

benefit at the Air Force medical facility at

Davis-Monthan AFB, AZ, where the cost of

purchased electrical power is relatively high

compared to that of natural gas.

USACERL researchers developed a cooling

load profile for the facility by reviewing plant

records and interviewing plant operators.

Boiler logs (daily and monthly) were consulted

to determine heating loads, and a spreadsheet

was developed to analyze nine options.

Savings and first costs were input into the Life

Cycle Cost in Design (LCCID) computer

program to determine simple paybacks and

savings-to-investment ratios for all options.

Based on the results of the investigation,

preferred options were recommended for

meeting the facility cooling load.

US Army Corps

of Engineers

Construction Engineering

Research Laboratories

USACERL Technical Report 99/24

January 1999

Approved for public release; distribution is unlimited.

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2 USACERL TR 99/24

Foreword

This study was conducted for the Air Force Civil Engineering Support Agency

(AFCESA) under Military Interdepartmental Purchase Request (MIPR) No.

N94-92, Work Unit WL4, “Evaluation and Application of Gas Cooling

Technologies.” The technical monitor was Rich Bauman, AFCESA.

The work was performed by the Utilities Division (UL-U) of the Utilities and

Industrial Operations Laboratory (UL), U.S. Army Construction Engineering

Research Laboratories (CERL). The CERL Principal Investigator was Timothy

W. Pedersen. Martin J. Savoie is Chief, CECER-UL-U, and Dr. John Bandy is

Operations Chief, CECER-UL. The responsible Technical Director was Gary W.

Schanche, CECER-TD. The CERL technical editor was William J. Wolfe,

Technical Information Team.

Dr. Michael J. O’Connor is Director of CERL.
USACERL TR-99/24 3

Contents

Foreword .........................................................................................................................................2

1 Introduction..............................................................................................................................7

Background.................................................................................................................... 7

Objectives...................................................................................................................... 7

Approach....................................................................................................................... 7

Scope.......................................................................................................................... 10

Mode of Technology Transfer........................................................................................ 11

Metric Conversion Factors............................................................................................ 11

2 Cooling Options.....................................................................................................................12

Status Quo................................................................................................................... 12

Two Hundred Fifty (250)-Ton Capacity Natural Gas Engine-Driven Chiller With

Heat Recovery (Option #1) .................................................................................... 12

Power Generation With Sufficient Waste Heat To Operate a Water Chilling Unit............ 13

Power Generation With Sufficient Waste Heat To Operate a Water Chilling Unit and

Satisfy Facility Thermal Requirements.................................................................... 15

3 Boiler Load and Heating Requirements..............................................................................17

Space Heating Requirements....................................................................................... 17

Direct Steam Requirements ......................................................................................... 17

Domestic Hot Water Heating Requirements.................................................................. 17

4 Heat Recovery........................................................................................................................19

Option #1..................................................................................................................... 19

Remaining Options (Heat Recovery from Engine-Generator Sets)................................ 19

5 Utility Rate Structures...........................................................................................................21

Electrical Rates............................................................................................................ 21

Natural Gas Rates ....................................................................................................... 22

6 Methodology for Analysis.....................................................................................................23

Option #2a................................................................................................................... 24

Option #2b................................................................................................................... 24

Option #2c (also applicable to Option #3a) ................................................................... 25
4 USACERL TR 99/24

Option #2d (also applicable to Option #3c) ................................................................... 25

Option #3b................................................................................................................... 25

Option #3d................................................................................................................... 25

First Costs ................................................................................................................... 25

Life Cycle Cost Analysis............................................................................................... 26

7 Results....................................................................................................................................27

8 Conclusions and Recommendations..................................................................................28

Appendix A: Notes Regarding Interviews and Discussions for Chiller Study at

Davis-Monthan AFB ..............................................................................................................30

Appendix B: Equipment Selections and Capitol Costs ..........................................................35

Appendix C: Recent Electric Bills for Davis-Monthan AFB ....................................................39

Appendix D: Spreadsheet Calculation Based on Option #2a.................................................53

Appendix E: Spreadsheet Calculation Based on Option #2b.................................................54

Appendix F: Spreadsheet Calculation Based on Options #2c and 3a...................................55

Appendix G: Spreadsheet Calculation Based on Options #2d and 3c..................................56

Appendix H: Spreadsheet Calculation Based on Option #3b.................................................57

Appendix I: Spreadsheet Calculation Based on Option #3d..................................................58

Appendix J: Construction Cost Estimates for Each Option...................................................59

Appendix K: Energy Cost Estimates for Each Option.............................................................69

Appendix L: Calculated Paybacks and Savings-to-Investment Ratio for Option 1............129

Appendix M: Calculated Paybacks and Savings-to-Investment Ratio for Option 2a.........130

Appendix N: Calculated Paybacks and Savings-to-Investment Ratio for Option 2b .........132

Appendix O: Calculated Paybacks and Savings-to-Investment Ratio for Option 2c.........134

Appendix P: Calculated Paybacks and Savings-to-Investment Ratio for Option 2d..........136

Appendix Q: Calculated Paybacks and Savings-to-Investment Ratio for Option 3a.........138

Appendix R: Calculated Paybacks and Savings-to-Investment Ratio for Option 3b .........140
USACERL TR-99/24 5

Appendix S: Calculated Paybacks and Savings-to-Investment Ratio for Option 3c..........142

Appendix T: Calculated Paybacks and Savings-to-Investment Ratio for Option 3d ..........144

USACERL TR-99/24 7

1 Introduction

Background

The Air Force Civil Engineering Support Agency (AFCESA) has been actively

involved with a cogeneration project at Tyndall AFB hospital. The project uses

an absorption chiller to satisfy the hospital’s base cooling load. The steam for

activating the absorption chiller is obtained from waste heat, which is derived

from an engine driving a generator to produce electrical power  which is also

used by the hospital. Based on this experience, AFCESA funded USACERL to

perform an analysis to see if such a concept, or some other cooling options, could

be of economic benefit at the Air Force medical facility at Davis-Monthan AFB,

AZ, where the cost of purchased electrical power is relatively high compared to

that of natural gas. USACERL researchers evaluated the case of power

generation providing sufficient waste heat to meet the facility base cooling load,

and also considered options under which sufficient waste heat could be derived

from power production so that a 250-ton absorption chiller could replace an

existing motor-driven centrifugal chiller of equal capacity. (The centrifugal

chiller uses a chlorofluorocarbon [CFC] refrigerant, R-11.) Heat produced as a

result of power generation can be used to satisfy facility thermal, as well as

cooling, loads.

Objectives

The objective of the study was to determine the approach that will minimize the

cost of meeting the cooling requirements of the medical facility at DavisMonthan AFB.

Approach

Cooling Load Profile

Considerable time was spent developing a cooling load profile for the facility.

This was done by meticulously reviewing plant records and discussing plant

operation with the operators (Appendix A). Where data appeared inconsistent or
8 USACERL TR 99/24

erroneous, or was missing, trends were examined and reasonable estimates

made for the actual cooling loads. Figures 1 and 2 show the results of the data

analysis.

Avg Total Chill Load vs Hrs per Ton Range at DavisMonthan AFB: May - October

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Figure 1. Cooling load estimate, May-October 1996.

Avg Total Chill Load vs Hrs per Ton Range at DavisMonthan AFB: November 1996 - April 1997

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Figure 2. Cooling load estimate, November 1996-April 1997.
USACERL TR-99/24 9

Boiler Load Profile

Boiler logs (daily and monthly) were consulted to determine heating loads. The

hospital cooling and heating plant was visited a number of times to obtain

information on the plant equipment, including water chillers, cooling towers,

boilers, pumps, and heat exchangers. It became obvious that the plant’s boilers

are grossly oversized for the load and, based on the pressure of the steam

produced (50 psig>15 psig), that the boilers require onsite plant operators.

Consequently, it became clear that waste heat from power generation could be

used not only to meet facility cooling loads through absorption water chilling, but

also to meet facility thermal loads, and in the process to possibly reduce

manpower requirements and increase utility cost savings.

Analysis

An EXCEL®

 spreadsheet was developed to analyze the numerous options that

were considered. The options considered were:

• (Option #1) Natural gas engine-driven chiller to replace existing 250-ton

motor-driven centrifugal chiller, with waste heat used to offset facility

thermal requirements

• (Option #2a) Natural gas-fired engine-generator set, waste heat used to

provide steam for single-effect absorption water chiller to meet facility base

cooling load (100 tons) with residual heat used for thermal requirement

• (Option #2b) Natural gas-fired engine-generator set, waste heat used to

provide steam for double-effect absorption water chiller to meet facility base

cooling load (100 tons), with residual heat used for thermal requirements

• (Option #2c) Natural gas-fired engine-generator set, waste heat used to

provide steam for single-effect absorption water chiller to replace existing

250-ton motor-driven centrifugal chiller, with residual heat used for thermal

requirements

• (Option #2d) Natural gas-fired engine-generator set, waste heat used to

provide steam for double-effect absorption water chiller to replace existing

250-ton motor-driven centrifugal chiller, with residual heat used for thermal

requirements

• (Option #3a) Natural gas-fired engine-generator set, waste heat used to

provide steam for single-effect absorption water chiller to meet facility base

cooling load (100 tons) with residual heat adequate to satisfy facility thermal

requirements (existing boilers as backup only)

• (Option #3b) Natural gas-fired engine-generator set, waste heat used to

provide steam for double-effect absorption water chiller to meet facility base

cooling load (100 tons) with residual heat adequate to satisfy facility thermal

requirements (existing boilers as backup only)
10 USACERL TR 99/24

• (Option #3c) Natural gas-fired engine-generator set, waste heat used to

provide steam for single-effect absorption water chiller to replace existing

250-ton motor-driven centrifugal chiller, with residual heat adequate to

satisfy facility thermal requirements (existing boilers as backup only)

• (Option #3d) Natural gas-fired engine-generator set, waste heat used to

provide steam for double-effect absorption water chiller to replace existing

250-ton motor-driven centrifugal chiller, with residual heat adequate to

satisfy facility thermal requirements (existing boilers as backup only).

In essence, Option #1 did not entail the use of an engine-generator set, only a

replacement of the existing 250-ton electric motor-driven centrifugal chiller with

a natural gas engine-driven chiller, waste heat from which would partially offset

facility thermal loads. Options #2a, 2b, 2c, and 2d entailed use of an enginegenerator set, with the waste heat providing sufficient energy to activate the

absorption chiller and also to meet a portion of the facility thermal load. Options

#3a, 3b, 3c, and 3d entailed use of an engine-generator set sized so that the

waste heat would not only be sufficient to activate the absorption water chiller,

but also to meet the entire thermal load of the facility. Note that, at one time,

another option was considered for analysis: use of a 250-ton capacity, directfired, double-effect, absorption chiller. This option was discarded prior to more

in-depth analysis because the coefficient-of-performance would be less than for

the engine-driven option, particularly when heat is recovered from the engine.

Once the spreadsheet calculated the operating cost savings for each option, the

savings and first costs were input into the Life Cycle Cost in Design (LCCID)

computer program to determine simple paybacks and savings-to-investment

ratios for all options. Based on the results of the investigation, recommendations

were made as to the preferred option for meeting the facility cooling load.

Scope

The scope of the project was to investigate feasible options for meeting the

facility’s cooling loads, with emphasis on using waste heat from electrical power

generation for absorption cooling. An ancillary benefit was that waste heat could

be used not only for absorption cooling, but also for partially or totally meeting

the medical facility thermal loads.
USACERL TR-99/24 11

Mode of Technology Transfer

This report documents the opportunities available and financial resources

required for reducing cooling and overall utility costs for the Davis-Monthan

AFB medical facility. USACERL would be amenable to developing a scope of

work for architect-engineer (A-E) services to design the installation of the

equipment for whatever option USAF management desires to pursue to reduce

the medical facility’s utility costs. Additionally, USACERL would be amenable to

reviewing the design and participating in technical oversight during construction, as well as monitoring equipment performance to verify estimated savings.

Additionally, the technologies considered here for possible application at the

medical facility at Davis-Monthan AFB have the potential to benefit other DOD

medical facilities. Consequently, it is recommended that this document be

circulated to the larger DOD medical community for its consideration in applying

the technologies at other sites.

Metric Conversion Factors

The following metric conversion factors are provided for standard units of

measure used throughout this report:

1 in. = 25.4 mm

1 lb = 0.453 kg

1 gal = 3.78 L

1 psi = 6.89 kPa

1 ton (refrigeration) = 3.516 kW

1 Btu = 1.055 kJ
12 USACERL TR 99/24

2 Cooling Options

Status Quo

At present, three electric motor-driven chillers in the Davis-Monthan AFB

cooling plant meet the cooling requirements of the medical facility: a York

centrifugal chiller nominally of 250-tons capacity, and two Dunham-Bush screw

machines of nominal 75-tons capacity each. Performance characteristics of the

York chiller were obtained for part load operation and for condenser water return

temperatures coincident with load as determined from analyzing cooling logs

provided by the base. An earlier analysis contained information as to the fullload performance of the screw machines. Part-load performance was estimated

using Figure 14 of Chapter 42, 1994 ASHRAE Refrigeration Handbook.

Two Hundred Fifty (250)-Ton Capacity Natural Gas Engine-Driven Chiller

With Heat Recovery (Option #1)

This option did not involve electrical power generation, but offered a potentially

economical approach for meeting the facility’s cooling loads. This hypothesis was

based on the fact that previous analyses indicated this technology should be

economically viable at other sites on the base. Under this option, the existing

250-ton capacity York motor-driven centrifugal chiller would be replaced by a

natural gas engine-driven chiller using HCFC-22. The engine would be capable

of delivering jacket water at temperatures varying between 183 and 201 °F,

depending on load, for heat exchange to produce water for space and domestic

hot water heating. Return jacket water temperature would be 180 °F. Chiller

performance took into account part load efficiencies and the return condenser

water temperatures coincident with load as determined from analyzing cooling

logs provided by the base.
USACERL TR-99/24 13

Power Generation With Sufficient Waste Heat To Operate a Water

Chilling Unit

Option #2a: One Hundred (100)-Ton Capacity Single-Effect Indirect-Fired

Absorption Chiller

Analysis of the hospital’s cooling loads indicated a year-round base load of 100

tons. Under this option, that base load would be met by a single-effect absorption chiller. The heat input would be provided by 15 psig steam produced from

heat as the byproduct of power generation from a Caterpillar G3512 (600 kW)

engine-generator set. Although the intent was to match, as far as possible, the

estimated amount of “waste” heat to the chiller heat input required, some

residual waste heat will result, which will be used to satisfy part of the facility’s

thermal load. Chiller performance was based on the assumption that the chiller

would continuously provide 100 tons of cooling, but under variable condenser

water return temperatures (as determined from logs provided by the base).

Under this option (and for all [four] options involving a new base-loaded 100-ton

capacity absorption chiller), the existing 250-ton capacity centrifugal chiller

would not be removed. Replacing the existing chiller with only a 100-ton

capacity absorption chiller would leave the plant short of capacity. (The data

indicates there are periods when the total load on the plant exceeds 250 tons.)

For this option and the next, the analysis is based on the assumption that,

beyond 100 tons, screw machines will operate until the plant load reaches

approximately 175 tons, at which point the operating screw machine will shut off

and the 250-ton capacity centrifugal chiller will come on. The new 100-ton

capacity absorption chiller would be located in the vicinity of the enginegenerator set and heat recovery equipment.

Option #2b: One Hundred (100)-Ton Capacity Double-Effect IndirectFired Absorption Chiller

As stated above, analysis of the hospital’s cooling loads indicated a year-round

base load of 100 tons. Under this option, that base load would be met by a

double-effect absorption chiller; the engine-generator set is a Caterpillar G-3516

(820 kW). The double-effect absorption chiller is about 50 percent more efficient

than the single-effect unit. However, the double-effect requires a steam input at

higher temperature – at the temperature of 115 psig versus the 15 psig of the

single-effect unit. Also, the first cost of the double-effect unit is higher than that

of the single-effect chiller. The performance at reduced condenser water temperatures was assumed to be the same as that of the single-effect unit. Under this

option, the existing 250-ton capacity centrifugal chiller would not be removed.

Replacing the existing chiller with only a 100-ton capacity absorption chiller
14 USACERL TR 99/24

would leave the plant short of capacity. (The data indicates there are periods

when the total load on the plant exceeds 250 tons.) The analysis is based on the

assumption that, beyond 100 tons, screw machines will operate until the plant

load reaches approximately 175 tons, at which point the operating screw

machine will shut off and the 250-ton capacity centrifugal chiller will come on.

The new 100-ton capacity absorption chiller would be located in the vicinity of

the engine-generator set and heat recovery equipment.

Option #2c: Two Hundred Fifty (250)-Ton Capacity Single-Effect IndirectFired Absorption Chiller

Under this option, two 820 kW Caterpillar G-3516s would be selected so that the

waste heat matches the heat input requirement for the chiller as closely as

possible. All residual heat over what the chiller requires will be used to at least

partially meet the facility’s thermal requirements (also like the two preceding

options). However, the new indirect-fired absorption chiller under this option

would be able to produce 250 tons of cooling, matching the capacity of the

existing centrifugal chiller. Under this option (and for all [four] options involving

a new 250-ton capacity absorption chiller), the existing centrifugal chiller will be

physically replaced by the new absorption unit. Chiller performance characteristics were based not only on return condenser water temperature, but also on

load since the intent is for the absorption chiller to meet all cooling loads up to

the initial 250 tons. Above that threshold, one or both of the existing screw

machines would operate.

Option #2d: Two Hundred Fifty (250)-Ton Capacity Double-Effect

Indirect-Fired Absorption Chiller

For this option, the engine-generator set (three 820 kW Caterpillar G-3516s)

would be selected so that its waste heat matches the heat input requirement for

the chiller as closely as possible. Any residual heat over what the chiller

requires will be used to at least partially meet the facility’s thermal requirements. However, the new double-effect indirect-fired absorption chiller under

this option would be able to produce 250 tons of cooling, matching the capacity of

the existing centrifugal chiller. Under this option, the existing centrifugal chiller

will be physically replaced by the new double-effect indirect-fired absorption

unit. Chiller performance characteristics were based not only on return

condenser water temperature, but also on load since the intent is for the

absorption chiller to meet all cooling loads up to the initial 250 tons. Above that

threshold, one or both of the existing screw machines would operate. This option

is similar in all respects to that immediately preceding it except that a more
USACERL TR-99/24 15

efficient double-effect absorption chiller would be installed, requiring 115 psig

steam instead of 15 psig.

Power Generation With Sufficient Waste Heat To Operate a Water

Chilling Unit and Satisfy Facility Thermal Requirements

Option #3a

This option is identical to Option #2a, except the engine-generator capacity is

sized to meet the thermal requirements of the facility in addition to the energy

requirements of the chiller. Under this option, that base load would be met by a

single-effect indirect-fired absorption chiller. The heat input would be provided

by 15 psig steam produced from heat as the byproduct of power generation from

two Caterpillar G3516 (820 kW) engine-generator sets. The intent was to match

the estimated amount of “waste” heat to the chiller heat input required and

satisfy the facility’s thermal load. Chiller performance was based on the

assumption that the chiller would continuously provide 100 tons of cooling, but

under variable condenser water return temperatures (as determined from logs

provided by the base). Under this option, the existing 250-ton capacity

centrifugal chiller would not be removed. Replacing the existing chiller with

only a 100-ton capacity absorption chiller would leave the plant short of capacity.

For this option, the analysis is based on the assumption that, beyond 100 tons,

screw machines will operate until the plant load reaches approximately 175 tons,

at which point the operating screw machine will shut off and the 250-ton

capacity centrifugal chiller will come on. The new 100-ton capacity single-effect

indirect-fired absorption chiller would be located in the vicinity of the enginegenerator set and heat recovery equipment.

Option #3b

This option is identical to Option #2b, except the engine-generator capacity is

sized to meet the thermal requirements of the facility in addition to the energy

requirements of the chiller. Analysis of the hospital’s cooling loads indicated a

year-round base load of 100 tons. Under this option, that base load would be met

by a 100 ton, double-effect, indirect-fired absorption chiller; the engine-generator

sets are four Caterpillar G-3516s (820 kW). The double-effect absorption chiller

is about 50 percent more efficient than the single-effect unit. However, the

double-effect requires a steam input at higher temperature – at the temperature

of 115 psig versus the 15 psig of the single-effect unit. Also, the first cost of the

double-effect unit is higher than that of the single-effect chiller. The performance at reduced condenser water temperatures was assumed to be the same as
16 USACERL TR 99/24

that of the single-effect unit. Under this option, the existing 250-ton capacity

centrifugal chiller would not be removed. Replacing the existing chiller with

only a 100-ton capacity absorption chiller would leave the plant short of capacity.

The analysis is based on the assumption that, beyond 100 tons, screw machines

will operate until the plant load reaches approximately 175 tons, at which point

the operating screw machine will shut off and the 250-ton capacity centrifugal

chiller will come on. The new 100-ton capacity absorption chiller would be

located in the vicinity of the engine-generator set and heat recovery equipment.

Option #3c

This option is identical to Option #2c, except the engine-generator capacity is

sized to meet the thermal requirements of the facility in addition to the energy

requirements of the chiller. Under this option, three 820 kW Caterpillar G-3516s

would be selected so that the waste heat matches the heat input requirement for

the chiller and will meet the thermal requirements of the facility. The new

single-effect indirect-fired absorption chiller under this option would be able to

produce 250 tons of cooling, matching the capacity of the existing centrifugal

chiller. Under this option, the existing centrifugal chiller will be physically

replaced by the new absorption unit. Chiller performance characteristics were

based not only on return condenser water temperature, but also on load since the

intent is for the absorption chiller to meet all cooling loads up to the initial 250

tons. Above that threshold, one or both of the existing screw machines would

operate.

Option #3d

This option is identical to Option #2d, except the engine-generator capacity is

sized to meet the thermal requirements of the facility in addition to the energy

requirements of the chiller. For this option, the engine-generator set, six 820 kW

Caterpillar G-3516s, would be selected so that its waste heat matches the heat

input requirement for the chiller and meets the thermal requirements of the

facility. However, the new double-effect indirect-fired absorption chiller under

this option would be able to produce 250 tons of cooling, matching the capacity of

the existing centrifugal chiller. The existing centrifugal chiller will be physically

replaced by the new double-effect indirect-fired absorption unit. Chiller performance characteristics were based not only on return condenser water temperature,

but also on load since the intent is for the absorption chiller to meet all cooling

loads up to the initial 250 tons. Above that threshold, one or both of the existing

screw machines would operate. This option is similar in all respects to that

immediately preceding it except a more efficient double-effect absorption chiller

would be installed, requiring 115 psig steam instead of 15 psig.
USACERL TR-99/24 17

3 Boiler Load and Heating Requirements

The maximum hourly boiler load was found from the daily boiler logs to be 3,491

pounds per hour (#/hr) of steam at 0800 on 1 February 94. With the steam

produced at 50 psig, this equates approximately to 3,491 #/hr x 912 Btu/# = 3,184

MBH. The steam was used indirectly for space heating and domestic hot water

production, and directly for humidification, dining hall requirements, and

medical equipment sterilization.

Space Heating Requirements

Based on the time of day and year, the space heating requirement was probably

very close to that of the basis of design. Schedules on the design drawings were

used to calculate design space heating loads, as follows: (13,400 + 4,570) gal/hr x

hr/60 min x 500 x (150 - 130) °F = 2,995 MBH.

Direct Steam Requirements

Previous analysis estimated that direct steam usage constitutes some 5 percent

of the boiler output. On that basis, the direct steam used was about 0.05 x 3,184

MBH = 159 MBH. Requirements for direct steam usage will be substantially

reduced as the dining portion of the hospital will be eliminated. Further, local

sterilizers are now being used in some instances instead of imported steam from

the central heat plant. Clearly, local humidifiers are also readily available that

can be used for humidification, without use of imported steam.

Domestic Hot Water Heating Requirements

The remainder of the boiler output is attributed to domestic hot water

production, or:

3,184 MBH - 2,995 MBH - 159 MBH = 30 MBH
18 USACERL TR 99/24

This figure is in line with an estimate found in an earlier analysis, but is small

compared to the domestic hot water heating capacity determined from the

schedule on the design drawings, which is:

640 gal/hr x 62.4 #/cu ft/7.48 gal/cu ft x 1 Btu/#- °F x 80 °F = 427 MBH

It may well be that the domestic hot water load was grossly overestimated,

similar to the required boiler capacity, or there may have actually been, at one

time, that much load. Mr. Domako of the Base Civil Engineering (BCE) staff has

indicated that he anticipates domestic hot water load will decrease in the future

as the hospital is converted to an outpatient facility.

The maximum thermal load for the purposes of this analysis will be considered

to be the sum of the space heating and domestic hot water load, above, or 3,025

MBH. The direct steam requirements will not be provided by way of waste heat.

Those requirements should be met by continuing the trend toward local

sterilization and installation of grid (or other type) humidifiers at the air

handling units. This will permit the plant to be unmanned. The thermal space

and domestic hot water heating loads will still be met as they are already

satisfied by 15 psig steam from a pressure reducing valve station from the

central heat plant boilers. The thermal energy requirements will be determined

from the monthly boiler logs for Summer and for Winter (Table 1), and will be

compared against the Btus of waste heat energy generated for those seasons to

see if there will be an overall surplus or shortfall of energy.

Table 1. Identification of energy requirements from monthly boiler logs for 1995.

Summer (May - Oct): Energy Requirements (# of Steam)

May 1,551,000

June 1,163,100

July 902,500

August 703,600

September 841,800

October

*

1,200,800

Summer Total = 6,362,800 (x 912 Btu/# = 5,802.874 Mbtu)

Winter (Nov - Apr):

November 1,200,800

December 1,559,800

January 1,622,700

February 1,334,200

March 1,369,200

April 1,766,200

Winter Total = 8,852,900 = (x 912 Btu/# = 8,073.845 Mbtu)

* Indicates data that was averaged using September and December data
USACERL TR-99/24 19

4 Heat Recovery

Heat recovery is a feature of all options considered except (of course) the base

option.

Option #1

Under this option, heat is potentially recoverable from both the engine and the

exhaust. Due to the fact there would be light load conditions experienced during

the year, USACERL was advised that heat should be extracted from the engine

only. Extracting heat at low load will lower the temperature of the exhaust gas

to the point where some condensation will occur with resulting corrosion.

Consequently, only heat recovery from the engine was considered.

Remaining Options (Heat Recovery from Engine-Generator Sets)

Remaining options considered heat recovery from the engine and/or the exhaust,

depending on whether high (115 psig) or low (15 psig) pressure steam was

required (i.e., depending on whether a double or single-effect absorption chiller

was under consideration). Low load that would promote corrosion is not a

problem – the engine-generator sets, when operating, would be running at full

load, generating the maximum amount of electricity possible. As pointed out

earlier in the discussion regarding options, the amount of heat recovery

considered was either that necessary to operate the absorption chiller at full

load, with any excess used to offset facility thermal requirements, or was that

required to operate the absorption chiller at full load and to meet the facility

thermal load as well. The analysis does not allow more heat energy to be

recovered than required. This limitation is imposed seasonally (Winter,

Summer) and thus is somewhat broad. For cases where equipment is sized to

produce waste heat to operate the chiller and meet the facility thermal load, the

seasonal excess of energy available over required is sufficiently large that short

duration thermal requirements should still be met for the vast majority of the

time. The excess heat would be “dumped” to the generously sized existing

cooling tower that currently cools the condenser water for the existing 250-ton

capacity motor-driven centrifugal chiller. USACERL acknowledges and appreci-
20 USACERL TR 99/24

ates the assistance of Mr. Warner Bauer of Engineering Controls, Inc., St. Louis,

MO, in selecting the engine-generator models and quantities, and heat recovery

equipment that would meet the performance criteria under each option

considered. Capital costs for the equipment were also provided by Engineering

Controls. The equipment selections and capital costs as provided by Engineering

Controls, Inc. appear in Appendix B. Note that Waukesha and Caterpillar

selections were made so that sole source procurement would not be required and

to ensure that performance should be comparable.
USACERL TR-99/24 21

5 Utility Rate Structures

Electrical Rates

Appendix C contains recent monthly electric bills for Davis-Monthan AFB for a

year (with the exception of September, for which interpolated data was used).

Using the electric bills, the rates were determined for use in the spreadsheet.

The basic demand charge of $10.28/billable kW (bkW) is applicable for the entire

year. The demand charge is apparently subject to 5 percent Arizona state sales

tax, applied to 92 percent of the total (demand plus energy charges) due to a

hospital exemption. Power factor adjustment and the Arizona Corporation

Commission Assessment were not considered as individually they are well

within the “noise” level of the total monthly electric charge and their difference

(the former is typically a credit, the latter a debit) is even more so. Consequently, the basic demand cost was figured as:

$10.28/bkW x bkW = demand cost (DC)

upon which the sales tax is levied, subject to the allowable exemption, or:

DC = $10.28 x bkW + $10.28 x bkW x 0.92 x 0.05

so that the actual demand cost would be:

DC = $10.28 x bkW x (1 + 0.92 x 0.05) = $10.75 x bkW.

The electrical energy rate is subject to the same levy. The basic Summer rate is

$0.047457/kWh and the basic Winter rate is $0.045084/kWh. Adjusted for the

same levy as applied to the demand charge, the rates become, respectively:

1.046 x $0.047457/kWh = $0.0496/kWh

and

1.046 x $0.045084/kWh = $0.0472/kWh.
22 USACERL TR 99/24

Additionally, the electrical rate schedule includes a 0.667 ratchet applied to the

peak KW demand experienced over the previous 11 months. The contract with

Tucson Electric Power Company includes a minimum monthly buy of 3,000 kW.

None of the options regarding power generation will penetrate this floor, based

on the data in Appendix C.

Natural Gas Rates

Information received from Mr. Weleck of the BCE staff indicated the gas rates

are now $2.75/MBtu in Summer and $3.90 in Winter.
USACERL TR-99/24 23

6 Methodology for Analysis

Based on the cooling load profile, hours at various loads were determined. The

spreadsheet then modeled how these loads would be met, either using the

existing cooling equipment or the equipment described above under the various

options considered. Note that the hours at the various loads do not total the

entire hours of the year (8,760), although there is apparently a requirement for

year-round cooling. This simplification was introduced since, once a load over

250 tons is experienced, the equipment that will operate to meet that additional

load will be the same under any of the options considered. However, for options

involving onsite electrical power generation, all hours of the year were

considered, except for the estimated periods of time when the equipment would

be inoperative for maintenance (95 and 98 percent availability on average in

Summer and Winter, respectively). The hours of operation are divided between

Summer (May through October, inclusive) and Winter (November through April)

due to the variation in utility rates between the two seasons. The enginegenerator sets have been derated to account for altitude (Tucson’s elevation is

2,654 feet above sea level) and outdoor temperature.

Maintenance costs for the Caterpillar G3516 were based on a previous analysis

by Empire Power Systems, Phoenix, AZ. This included all parts and labor for oil

changes, makeup oil, scheduled preventive maintenance, overhauls, unscheduled

stoppages due to out-of-tolerance conditions, etc. The maintenance required for

the G3512 was assumed to be essentially equal to that of the G3516. An

interruption for over 15 minutes in the monthly operation of a given generator

will render demand savings from that generator moot for the month (although

savings in billable demand may still be possible where operation has reduced

peak and the month is one in which billable demand would exceed actual

demand). This would be the case regardless of the estimated overall Summer 95

percent or Winter 98 percent availability rates. If units must be down, clearly

the preference is to take them down during periods of months when demand is

relatively low, keeping the units in service during months when peak demands

are typically experienced. Preference should be given to pulling operationally

interruptive maintenance during months when billable demand typically exceeds

actual demand. It is, of course, recognized that this isn’t always possible. The

operational assumptions made in the spreadsheet are based on operating the

equipment according to the recommendations above, but allowing for the
24 USACERL TR 99/24

possibility that unscheduled events will occur. Operating scenarios were

developed for all options based on the practices recommended above and are

indicated in the following.

Option #2a

With only one Caterpillar G3512 engine-generator set, it was assumed that there

would be totally uninterrupted service for 3 of the 6 summer months. It is

assumed that, of the 3 months, due diligence has been taken to ensure uninterrupted operation for 2 of the 3 months with the highest actual demand, but the

unit went down for the month with the third-highest demand. For Winter, it is

assumed that there will be uninterrupted service for 3 months, and interrupted

service for 3 months. (Actually, it really does not matter from a demand

reduction viewpoint whether the engine-generator does or does not operate

during months in which the minimum billable amount is determined by the

ratchet; i.e., November to February, inclusive.) Appendix D indicates the

situation, incorporating the data from Appendix E. Table 2 lists the projected

demand reductions by month.

For input to the spreadsheet, there would be 3 months in Summer when the

demand reduction would be 555 kW, and for Winter, there would be 4 months for

which the reduction would be 370 kW and 1 month for which the reduction

would be 555 kW.

Option #2b

This option is considered identical to Option

#2a from an operational standpoint. However, the power production is greater for the

Caterpillar G3516 engine-generator that

would be installed under this option.

Appendix E shows the results. Note again

that, in Winter, for the 4 months when the

ratchet is in effect, it does not matter from a

demand reduction perspective whether any

unit does or does not operate. This pattern

is characteristic for all the options involving

onsite power production.

Table 2. Projected demand

reductions, by month.

Jul 555 kW

Aug 555 kW

Sep 0 kW

Oct 555 kW

Nov 370 kW (= 12,543 - 12,173)

Dec 370 kW

Jan 370 kW

Feb 370 kW

Mar 0 kW

Apr 555 kW

May 0 kW

Jun 0 kW
USACERL TR-99/24 25

Option #2c (also applicable to Option #3a)

Under this option, it is assumed that in Summer, one Caterpillar G3516 unit will

be available to achieve demand reductions for 3 months and two such units will

be available to achieve reductions for the remaining 3 months. It is assumed

that Winter operation will replicate Summer. Appendix F shows operation for

the year. Since two Caterpillar G3516 engine-generators are being considered

for Option #3a, the same results apply for that option.

Option #2d (also applicable to Option #3c)

This option involves three Caterpillar G3516 engine-generator sets. It is

assumed that in Summer, all three will be available for 2 months and two will be

continuously available for 4 months. In Winter, the same assumption is made.

Appendix G shows the results. The same results also apply to Option #3c.

Option #3b

This option involves four Caterpillar G3516 engine-generator sets. It is assumed

that in Summer all four will be available for 2 months and three will be available

for the remaining 4 months. In Winter, the same availability is assumed.

Appendix H shows the results.

Option #3d

Six Caterpillar G3516 engine-generator sets were considered for installation

under this option. For operation in Summer, it is assumed that all six units will

operate for 2 months, five units will operate continuously for 2 months, and four

units will be maintained in continuous operation for 2 months. Winter operation

will be assumed to be identical. Appendix I shows the results.

First Costs

Appendix J contains the construction cost estimates for each option. The cost

estimates for the heat recovery equipment and associated engine-generator sets
26 USACERL TR 99/24

were those provided by Engineering Controls, Inc., as previously discussed. All

other costs were based on Means Mechanical Cost Data 1997.

The cost estimates do not include the construction of an enclosure for equipment

located exterior to the central energy plant building. Estimating the cost of such

a structure would be difficult since the architectural requirements vary for each

base. However, it does include the cost of a concrete pad on which to install the

equipment.

Life Cycle Cost Analysis

The life cycle cost analysis for each option was calculated using Life Cycle Cost

In Design (LCCID) software.* The life cycle cost analysis accounts for the

construction, overhead, and design costs associated with each option. The sum of

these values is the total investment. The economic life is taken over a 20-year

period and accounts for all scheduled maintenance activities as detailed by the

manufacturer. No service contracts were considered as part of this study.

 

* Linda K. Lawrie, Technical Report (TR) E-85/07/ADA162522, Development and Use of the Life Cycle Cost in

Design Computer Program (LCCID) (U.S. Army Construction Engineering Research Laboratories [USACERL],

November 1985).
USACERL TR-99/24 27

7 Results

Appendix K shows the EXCEL® spreadsheet that contains the raw energy data.

Appendixes L to T and Table 3 contain calculated payback and savings-toinvestment ratio for each option. The table below summarizes the economic

results. These results form the basis for the recommendations in the next paragraph. This report does not include potential savings that may be achievable

under Options #3a, 3b, 3c, and 3d by having an unmanned plant. Under these

options, there would be initial first cost incurred due to installation of humidification units at the air handling units and use of sterilizers where the energy

input for sterilization would be at the point of use. Estimating overall savings

through removing the plant manning requirement was beyond the scope of a

cooling study. However, in addition to the considerable utility savings identified

for Options #3a through 3d, inclusive, there would likely be considerable savings

from eliminating the requirement for a manned plant.

Table 3. Calculated payback and savings-to-investment ratios for options.

Option Payback (years) SIR Total Investment Recommendation

3a 1.01 9.29 $269,507 implement

3b 1.21 6.61 $536,817 implement

3c 1.49 5.83 $538,392

3d 1.43 5.44 $934,974

2c 1.65 5.96 $476,529

2d 1.75 4.96 $639,087

2b 2.51 2.77 $235,412

2a 2.87 2.32 $196,252

1 9.35 1.32 $290,974 do not implement
28 USACERL TR 99/24

8 Conclusions and Recommendations

The medical facility at Davis-Monthan AFB can realize considerable utility cost

savings by implementing any of several options analyzed in this study. It is

likely such savings can be replicated at other DOD medical facilities where there

are year-round air conditioning requirements, large thermal energy requirements, and utility rates where the unit cost of purchased electricity is high

compared to that of natural gas.

Based on these results, this study recommends the projects be prioritized for

implementation, from most to least highly recommended, as follows:

1. Option 3a: Two natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for a 100 ton single-effect

indirect-fired absorption water chiller to meet facility base cooling load (100

tons) with residual heat adequate to satisfy facility thermal requirements

(existing boilers as backup only). This option is recommended for

implementation.

2. Option 3b: Four natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for a 100 ton double-effect

indirect-fired absorption water chiller to meet facility base cooling load (100

tons) with residual heat adequate to satisfy facility thermal requirements

(existing boilers as backup only). This option is recommended for

implementation.

3. Option 3c: Three natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for 250 ton single-effect

indirect-fired absorption water chiller to replace existing 250-ton motordriven centrifugal chiller, with residual heat adequate to satisfy facility

thermal requirements (existing boilers as backup only).

4. Option 3d: Six natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for a 250 ton double-effect

indirect-fired absorption water chiller to replace existing 250-ton motordriven centrifugal chiller, with residual heat adequate to satisfy facility

thermal requirements (existing boilers as backup only).
USACERL TR-99/24 29

5. Option 2c: Two natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for a 250 ton single-effect

indirect-fired absorption water chiller to replace existing 250-ton motordriven centrifugal chiller, with residual heat used for thermal requirements.

6. Option 2d: Three natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator sets, waste heat used to provide steam for a 250 ton double-effect

indirect-fired absorption water chiller to replace existing 250-ton motordriven centrifugal chiller, with residual heat used for thermal requirements.

7. Option 2b: One natural gas-fired Caterpillar G-3516 (820 kW) enginegenerator set, waste heat used to provide steam for a 100 ton double-effect

indirect-fired absorption water chiller to meet facility base cooling load (100

tons) with residual heat used for thermal requirements.

8. Option 2a: One natural gas-fired Caterpillar G-3512 (600 kW) enginegenerator set, waste heat used to provide steam for a 100 ton single-effect

indirect-fired absorption water chiller to meet facility base cooling load (100

tons) with residual heat used for thermal requirement.

9. Option 1: A 250 ton natural gas engine-driven chiller to replace existing 250-

ton motor-driven centrifugal chiller, with waste heat used to offset facility

thermal requirements. Note that this option is not recommended for

implementation.
30 USACERL TR 99/24

Appendix A: Notes Regarding Interviews

and Discussions for Chiller

Study at Davis-Monthan AFB

SSgt Rinn, TSgt Farmer, Central Plant Operators –

A. As of 1 Apr 97, the foregoing operators have been on temporary

assignment pending award of a contract for private sector O&M for

the hospital, including the central plant. The operators provided

chilled water logs for the previous year (to be returned to Steve

Weleck). They also furnished monthly boiler logs for the months (Jan

– Jun 97, logs to be returned to Weleck) and referred us to Lt.

Doolittle for the balance of the previous year’s monthly boiler logs.

Lt. Doolittle furnished CERL with monthly logs from Jan 94 – Sep

95. In an attempt to determine peak plant thermal load, CERL went

back to boiler log data for Feb 94 (records to be returned to Weleck).

B. Upon initial arrival, CERL was appraised that a cogeneration study

had already been completed, Dec 95, with design drawings based on

the study results also provided. The study and drawings were loaned

to CERL for review, and CERL will return same to Weleck. While

meeting with Weleck, CERL learned that two significant projects are

planned for the hospital, a 6,000 SF addition and a follow-on 30,000

SF addition (both projects discussed in greater detail below).

Additionally, Weleck furnished a document “FY88 MCP ECIP Facility

Energy Improvements” for CERL’s perusal to see if it might contain

helpful information. Mr. Weleck also provided utility rate schedules

and sample billings.

C. SSgt Rinn and TSgt Farmer retrieved plant drawings on file for

CERL’s review, particularly drawings containing schedules for space

heating and domestic hot water equipment. Inquiry verified there is

no separate metering of steam usage – some is used for space heating,

some for domestic hot water production, and the remainder is direct

steam usage. Therefore, the schedule sheets were used with other
USACERL TR-99/24 31

input to determine the relative uses for the steam produced. Of prime

concern was the amount of steam used directly for various applications (dining facility, humidification, and medical sterilizers). The

requirement for high pressure steam (> 15 psig [the plant operates at

50 psig]) drives the requirement for 24-hour manning of the plant.

D. Lt. Chicotah, facility manager at the hospital, was contacted by phone

in an attempt to find out about future projects planned for the

hospital. She Faxed a Preliminary Statement of Work for design of a

FY00 30,000 SF addition (Ambulatory Health Care Center) to the

existing medical facility. This is in addition to the 6,000 SF Aerospace

Medicine Clinic programmed for FY98. Neither this document nor the

DD Form 1391 or the Requirements and Management Plan (the latter

two provided by SMSgt Mortenson) provided insight as to the

mechanical equipment that is anticipated for use in heating and

cooling either the planned 6,000 SF addition or the 30,000 SF addition. In a final attempt to get this information, CERL called Horace

Hopper of AFCEE. The information Hopper currently has basically

leaves the issue of the mechanical equipment to be used for the facility

additions at the discretion of the designer. At this time, per Mr.

Hopper, the designer has not been selected (contrary to information

provided by Lt. Chicotah who indicated an A-E contract is to be

awarded by the end of July 97). Numerous references were made to a

Capt Reinhardt in San Francisco as the prime source of information

regarding future plans for the hospital. Attempts to reach Reinhardt

to date have been unsuccessful; however, CERL’s plan is to use his

information to resolve any conflicting or missing information. Mr.

Ken Domako indicated he would attempt to resolve the issue of future

requirements for direct steam use. He also indicated his estimate that

domestic hot water usage at this time has been reduced significantly

from what was the original basis of design, and that future

requirements will likely be only about half that of the original basis of

design. This is due to removal of the dining facility and elimination of

showers for patients. Mr. Domako stated that the two planned

hospital projects will be undertaken.
32 USACERL TR 99/24

Approach

A. Contact Capt Reinhardt regarding future hospital requirements.

B. Compute heating loads (process steam, space heating, and domestic

hot water).

C. Plot cooling load profiles.

D. Consider the following options:

1. gas fired dual-effect absorption unit

2. gas engine-driven chiller

3. cogen system made up of a generator and indirect fired absorption

unit

E. Analyze data and produce report.

Determination of Heating Loads

A. The existing boilers in the hospital central plant are greatly oversized. They are products of Nebraska Boiler, each rated at 7.5 million

British Thermal Units per hour (MBH) with a mass flow of 7,000

pounds per hour (#/hr) of 50 pounds per square inch gauge (psig)

saturated steam. Examination of the boiler logs available indicated

that the maximum boiler load experienced over the last 5 years (on 4

Feb 94) was 3,500 #/hr, which translates into a heating load of

3,500 #/hr x 7,500,000 Btu/7,000 #/hr = 3,750,000 Btu/hr

This indicates a peak load of only 25 percent of the existing plant

boiler capacity (3.75 MBH/[2 x 7.5 MBH]). Most of the time, the load

is significantly less. The load will decrease even more due to the

factors described in the following paragraphs.

B. Domestic Hot Water Loads

Mr. Domako indicated that hospital care is going to be limited

basically to outpatient care, including outpatient surgery. Showers

for patients will be significantly reduced compared to that anticipated when the plant was constructed. Mr. Domako’s estimate of the

reduction is 50 percent. There are currently two domestic hot water

generators in the plant, the original design intent being that either
USACERL TR-99/24 33

one could provide 100 percent redundancy. The schedule on the

design drawings indicates the generators are capable of heating 640

gal of water from 60 to 120 °F in 1 hour. The design also provided for

what appears to be a booster heater to heat the water initially from

60 to 90 °F, with the 90 °F water then heated to 120 °F by the hot

water generators. Since the heating from the booster actually

supplants (although it also accelerates) the heating that would otherwise be required by the domestic hot water generators (increasing the

domestic hot water temperature from 60 to 90 °F), only the full

capacity of the hot water generators need be calculated, which is

640 gal/hour x 8.34 lb/gal x 1 Btu/lb °F x (120-60) °F

= 320,256 Btu/hr

Assuming a 50 percent reduction in load, the estimated domestic hot

water heating requirement would be 320,256 Btu/hr/2 = 160,128

Btu/hr.

C. Space Preheating, Heating, and Reheating Loads

Drawings that contained schedules indicating the required capacities

for preheat, heating, and reheat coils were reviewed. Rather than

add these all up and then assume some diversity factor, the schedule

for the converters was checked. Based on those schedules, the design

heating water requirement was determined from

Converter #1: 500 x 13,400 gal/hr/60 min/hr x (150-128) °F

= 2,456,667 Btu/hr

where operators indicated that the temperature of the supply hot

water is 150 °F and the return is typically the 128 °F indicated.

Converter #2: 500 x 4,570 gal/hr/60 min/hr x (150-128) °F

= 837,333 Btu/hr

Since both converters operate simultaneously, the capacities are

summed to produce a joint capacity of (2,456,667 + 837,333) Btu/hr =

3,294,500 Btu/hr.
34 USACERL TR 99/24

D. Process Steam Loads

Boiler plant steam is used directly for a number of purposes/

applications: sterilization, dining hall requirements, and humidification. Unfortunately, this steam (nor the domestic hot water or

heating water used for space conditioning) has been metered.

Therefore, the quantity of steam used directly (as opposed to heat

exchange within the plant to produce domestic hot water and heating

water for space conditioning) was calculated by subtracting the

quantities in subparagraphs b) and c) from the peak steam load

identified in subparagraph a). The quantity was calculated as:

3,750,000 Btu/hr - 160,171 Btu/hr - 3,294,500 Btu/hr = 295,329 Btu/hr

Based on discussions with Mr. Domako and TSgt Mortenson, the

dining hall will be eliminated and the space used for an alternative

function. This will eliminate a portion of the present direct steam

usage. Additionally, discussion with plant operators indicated that in

a number of instances, steam from the plant is not being used for

sterilization. Rather, portable units are being used for sterilization.

Mr. Domako expects use of this type of sterilization to be expanded.

He indicated he will check with medical personnel to try to ascertain

future steam requirements.
USACERL TR-99/24 35

Appendix B: Equipment Selections and

Capitol Costs
36 USACERL TR 99/24

38 USACERL TR 99/24
USACERL TR-99/24 39

Appendix C: Recent Electric Bills for

Davis-Monthan AFB
40 USACERL TR 99/24
USACERL TR-99/24 41
42 USACERL TR 99/24
USACERL TR-99/24 43
44 USACERL TR 99/24
USACERL TR-99/24 45
46 USACERL TR 99/24
USACERL TR-99/24 47
48 USACERL TR 99/24
USACERL TR-99/24 49
50 USACERL TR 99/24
USACERL TR-99/24 51
52 USACERL TR 99/24
USACERL TR-99/24 53

Appendix D: Spreadsheet Calculation

Based on Option #2a

Historic With Engine Generator

Operating 3 of 6 Months (Summer)

Operating 3 of 6 Months (Winter)

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 +JUL 98 (S) 18,104 18,104

AUG 96(S) 18,805 18,805 +AUG 98 (S) 18,250 18,250

*SEP 96(S) 17,876 17,876 ++SEP 98 (S) 17,876 17,876

OCT 96 (S) 16,947 16,947 +OCT 98 (S) 16,392 16,392

NOV 96(W) 12,543 11,606 ++NOV 98 (W) 12,173 11,606

DEC 96(W) 12,543 10,787 +DEC 98 (W) 12,173 10,232

JAN 97 (W) 12,543 11,141 ++JAN 99 (W) 12,173 11,141

FEB 97 (W) 12,543 10,696 +FEB 99 (W) 12,173 10,141

MAR 97(W) 12,613 12,613 ++MAR 99 (W) 12,613 12,613

APR 97 (W) 14,142 14,142 +APR 99 (W) 13,587 13,587

MAY 97 (S) 17,026 17,026 ++MAY 99 (S) 17,026 17,026

JUN 97 (S) 18,099 18,099 ++JUN 99 (S) 18,099 18,099

SAVINGS RECAP FOR SEASON

JUL 555 kW Summer:

AUG 555 kW 3 months @ 555 kW reduction each

SEP 0 kW 3 months @ 0 kW reduction each

OCT 555 kW Winter:

NOV 370 kW 4 months @ 370 kW reduction each

DEC 370 kW 1 month @ 555 kW reduction each

JAN 370 kW 1 month @ 0 kW reduction each

FEB 370 kW

MAR 0 kW

APR 555 kW

MAY 0 kW

JUN 0 kW

“*” indicates data that has been averaged between the month preceding and that following.

“+” symbol indicates a month in which the engine-generator operated continuously,

“++” indicates a month when it did not.

(S) denotes a Summer month, while (W) denotes a Winter month.
54 USACERL TR 99/24

Appendix E: Spreadsheet Calculation

Based on Option #2b

Historic With Engine Generator

Operating 3 of 6 Months (Summer)

Operating 3 of 6 Months (Winter)

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 +JUL 98 (S) 17,900 17,900

AUG 96(S) 18,805 18,805 +AUG 98 (S) 18,046 18,046

*SEP 96(S) 17,876 17,876 ++SEP 98 (S) 17,876 17,876

OCT 96 (S) 16,947 16,947 +OCT 98 (S) 16,188 16,188

NOV 96(W) 12,543 11,606 ++NOV 98 (W) 12,037 11,606

DEC 96(W) 12,543 10,787 +DEC 98 (W) 12,037 10,028

JAN 97 (W) 12,543 11,141 ++JAN 99 (W) 12,037 11,141

FEB 97 (W) 12,543 10,696 +FEB 99 (W) 12,037 9,937

MAR 97(W) 12,613 12,613 ++MAR 99 (W) 12,613 12,613

APR 97 (W) 14,142 14,142 +APR 99 (W) 13,383 13,383

MAY 97 (S) 17,026 17,026 ++MAY 99 (S) 17,026 17,026

JUN 97 (S) 18,099 18,099 ++JUN 99 (S) 18,099 18,099

SAVINGS RECAP FOR SEASON

JUL 759 kW Summer:

AUG 759 kW 3 months @ 759 kW reduction each

SEP 0 kW 3 months @ 0 kW reduction each

OCT 759 kW Winter:

NOV 506 kW 4 months @ 506 kW reduction each

DEC 506 kW 1 month @ 759 kW reduction each

JAN 506 kW 1 month @ 0 kW reduction each

FEB 506 kW

MAR 0 kW

APR 759 kW

MAY 0 kW

JUN 0 kW

“*” indicates data that has been averaged between the month preceding and that following.

 “+” symbol indicates a month in which the engine-generator operated continuously,

“++” indicates a month when it did not.

(S) denotes a Summer month,

(W) denotes a Winter month.

( )-number within = #units operating continuously for that month
USACERL TR-99/24 55

Appendix F: Spreadsheet Calculation

Based on Options #2c and

3a

Historic With Engine Generator

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 JUL 98 (S) 17,141 17,141 (2)

AUG 96(S) 18,805 18,805 AUG 98 (S) 17,287 17,287 (2)

*SEP 96(S) 17,876 17,876 SEP 98 (S) 17,117 17,117 (1)

OCT 96 (S) 16,947 16,947 OCT 98 (S) 15,429 15,429 (2)

NOV 96(W) 12,543 11,606 NOV 98 (W) 11,530 10,847 (1)

DEC 96(W) 12,543 10,787 DEC 98 (W) 11,530 9,269 (2)

JAN 97 (W) 12,543 11,141 JAN 99 (W) 11,530 10,382 (1)

FEB 97 (W) 12,543 10,696 FEB 99 (W) 11,530 9,178 (2)

MAR 97(W) 12,613 12,613 MAR 99 (W) 11,854 11,854 (1)

APR 97 (W) 14,142 14,142 APR 99 (W) 12,624 12,624 (2)

MAY 97 (S) 17,026 17,026 MAY 99 (S) 16,267 16,267 (1)

JUN 97 (S) 18,099 18,099 JUN 99 (S) 17,340 17,340 (1)

SAVINGS RECAP FOR SEASON

JUL 1,518 kW Summer:

AUG 1,518 kW 3 months @ 1,518 kW reduction each

SEP 759 kW 3 months @ 759 kW reduction each

OCT 1,518 kW Winter:

NOV 1,013 kW 4 months @ 1,013 kW reduction each

DEC 1,013 kW 1 month @ 759 kW reduction each

JAN 1,013 kW 1 month @ 1,518 kW reduction each

FEB 1,013 kW

MAR 759 kW

APR 1,518 kW

MAY 759 kW

JUN 759 kW

“*” indicates data that’s been averaged between the month preceding and that following.

(S) denotes a Summer month

(W) denotes a Winter month

( )-number within = #units operating continuously for that month
56 USACERL TR 99/24

Appendix G: Spreadsheet Calculation

Based on Options #2d and

3c

Historic With Engine Generator

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 JUL 98 (S) 16,382 16,382 (3)

AUG 96(S) 18,805 18,805 AUG 98 (S) 16,528 16,528 (3)

*SEP 96(S) 17,876 17,876 SEP 98 (S) 16,358 16,358 (2)

OCT 96 (S) 16,947 16,947 OCT 98 (S) 15,429 15,429 (2)

NOV 96(W) 12,543 11,606 NOV 98 (W) 11,024 9,329 (3)

DEC 96(W) 12,543 10,787 DEC 98 (W) 11,024 9,269 (2)

JAN 97 (W) 12,543 11,141 JAN 99 (W) 11,024 9,623 (2)

FEB 97 (W) 12,543 10,696 FEB 99 (W) 11,024 9,178 (2)

MAR 97(W) 12,613 12,613 MAR 99 (W) 11,095 11,095 (2)

APR 97 (W) 14,142 14,142 APR 99 (W) 11,865 11,865 (3)

MAY 97 (S) 17,026 17,026 MAY 99 (S) 15,508 15,508 (2)

JUN 97 (S) 18,099 18,099 JUN 99 (S) 16,581 16,581 (2)

SAVINGS RECAP FOR SEASON

JUL 2,277 kW Summer:

AUG 2,277 kW 4 months @ 1,518 kW reduction each

SEP 1,518 kW 2 months @ 2,277 kW reduction each

OCT 1,518 kW Winter:

NOV 1,519 kW 4 months @ 1,519 kW reduction each

DEC 1,519 kW 1 month @ 2,277 kW reduction each

JAN 1,519 kW 1 month @ 1,518 kW reduction each

FEB 1,519 kW

MAR 1,518 kW

APR 2,277 kW

MAY 1,518 kW

JUN 1,518 kW

“*” indicates data that has been averaged between the month preceding and that following.

(S) denotes a Summer month

(W) denotes a Winter month

( )-number within = #units operating continuously for that month
USACERL TR-99/24 57

Appendix H: Spreadsheet Calculation

Based on Option #3b

Historic With Engine Generator

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 JUL 98 (S) 15,623 15,623 (4)

AUG 96(S) 18,805 18,805 AUG 98 (S) 15,769 15,769 (4)

*SEP 96(S) 17,876 17,876 SEP 98 (S) 15,599 15,599 (3)

OCT 96 (S) 16,947 16,947 OCT 98 (S) 14,670 14,670 (3)

NOV 96(W) 12,543 11,606 NOV 98 (W) 10,518 8,570 (4)

DEC 96(W) 12,543 10,787 DEC 98 (W) 10,518 8,510 (3)

JAN 97 (W) 12,543 11,141 JAN 99 (W) 10,518 8,864 (3)

FEB 97 (W) 12,543 10,696 FEB 99 (W) 10,518 8,419 (3)

MAR 97(W) 12,613 12,613 MAR 99 (W) 10,518 10,336 (3)

APR 97 (W) 14,142 14,142 APR 99 (W) 11, 106 11,106 (4)

MAY 97 (S) 17,026 17,026 MAY 99 (S) 14,749 14,749 (3)

JUN 97 (S) 18,099 18,099 JUN 99 (S) 15,822 15,822 (3)

SAVINGS RECAP FOR SEASON

JUL 3,036 kW Summer:

AUG 3,036 kW 4 months @ 2,277 kW reduction each

SEP 2,277 kW 2 months @ 3,036 kW reduction each

OCT 2,277 kW Winter:

NOV 2,025 kW 4 months @ 2,025 kW reduction each

DEC 2,025 kW 1 month @ 2,095 kW reduction each

JAN 2,025 kW 1 month @ 3,036 kW reduction each

FEB 2,025 kW

MAR 2,095 kW

APR 3,036 kW

MAY 2,277 kW

JUN 2,277 kW

“*” indicates data that’s been averaged between the month preceding and that following.

(S) denotes a Summer month

(W) denotes a Winter month

( )-number within = #units operating continuously for that month
58 USACERL TR 99/24

Appendix I: Spreadsheet Calculation

Based on Option #3d

Historic With Engine Generator

Month Billing

Demand

Actual

Demand

Month Billing

Demand

Actual

Demand

JUL 96 (S) 18,659 18,659 JUL 98 (S) 14,105 14,105 (6)

AUG 96(S) 18,805 18,805 AUG 98 (S) 14,251 14,251 (6)

*SEP 96(S) 17,876 17,876 SEP 98 (S) 14,081 14,081 (5)

OCT 96 (S) 16,947 16,947 OCT 98 (S) 13,911 13,911 (4)

NOV 96(W) 12,543 11,606 NOV 98 (W) 9,505 7,052 (6)

DEC 96(W) 12,543 10,787 DEC 98 (W) 9,505 6,992 (5)

JAN 97 (W) 12,543 11,141 JAN 99 (W) 9,505 8,105 (4)

FEB 97 (W) 12,543 10,696 FEB 99 (W) 9,505 6,901 (5)

MAR 97(W) 12,613 12,613 MAR 99 (W) 9,577 9,577 (4)

APR 97 (W) 14,142 14,142 APR 99 (W) 9,588 9,588 (6)

MAY 97 (S) 17,026 17,026 MAY 99 (S) 13,990 13,990 (4)

JUN 97 (S) 18,099 18,099 JUN 99 (S) 14,304 14,304 (5)

SAVINGS RECAP FOR SEASON

JUL 4,554 kW Summer:

AUG 4,554 kW 2 months @ 4,554 kW reduction each

SEP 3,795 kW 2 months @ 3,795 kW reduction each

OCT 3,036 kW 2 months @ 3,036 kW reduction each

NOV 4,554 kW Winter:

DEC 3,795 kW 4 months @ 3,038 kW reduction each

JAN 3,036 kW 1 month @ 4,554 kW reduction each

FEB 3,795 kW 1 month @ 3,036 kW reduction each

MAR 3,036 kW

APR 4,554 kW

MAY 3,036 kW

JUN 3,795 kW

“*” indicates data that has been averaged between the month preceding and that following.

(S) denotes a Summer month

(W) denotes a Winter month

( )-number within = #units operating continuously for that month.
USACERL TR-99/24 59

Appendix J: Construction Cost Estimates

for Each Option
60 USACERL TR 99/24
USACERL TR-99/24 61
62 USACERL TR 99/24
USACERL TR-99/24 63
64 USACERL TR 99/24
USACERL TR-99/24 65
66 USACERL TR 99/24
USACERL TR-99/24 67
68 USACERL TR 99/24
USACERL TR-99/24 69

Appendix K: Energy Cost Estimates for

Each Option
70 USACERL TR 99/24
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72 USACERL TR 99/24
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74 USACERL TR 99/24
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76 USACERL TR 99/24
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78 USACERL TR 99/24
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80 USACERL TR 99/24
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82 USACERL TR 99/24
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84 USACERL TR 99/24
USACERL TR-99/24 85
86 USACERL TR 99/24
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88 USACERL TR 99/24
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90 USACERL TR 99/24
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92 USACERL TR 99/24
USACERL TR-99/24 93
94 USACERL TR 99/24
USACERL TR-99/24 95
96 USACERL TR 99/24
USACERL TR-99/24 97
98 USACERL TR 99/24
USACERL TR-99/24 99
100 USACERL TR 99/24
USACERL TR-99/24 101
102 USACERL TR 99/24
USACERL TR-99/24 103
104 USACERL TR 99/24
USACERL TR-99/24 105
106 USACERL TR 99/24
USACERL TR-99/24 107
108 USACERL TR 99/24
USACERL TR-99/24 109
110 USACERL TR 99/24
USACERL TR-99/24 111
112 USACERL TR 99/24
USACERL TR-99/24 113
114 USACERL TR 99/24
USACERL TR-99/24 115
116 USACERL TR 99/24
USACERL TR-99/24 117
118 USACERL TR 99/24
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120 USACERL TR 99/24
USACERL TR-99/24 121
122 USACERL TR 99/24
USACERL TR-99/24 123
124 USACERL TR 99/24
USACERL TR-99/24 125
126 USACERL TR 99/24
USACERL TR-99/24 127
128 USACERL TR 99/24
USACERL TR-99/24 129

Appendix L: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 1

Life Cycle Cost Analysis Study: Option #1

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #1

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $260,963

 B. SIOH $14,353

 C. Design Cost $15,658

 D. Total Cost (1A+1B+1C) $290,974

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $290,974

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 792|Mwatt-| $36,441| 14.47| $527,296|

|Elec. Deman| | | | | $13,377| 13.47| $180,188|

|Natural Gas| $3.4|/Mbtus| -5,502|Mbtus | -$18,706| 17.32| -$323,993|

|TOTAL | | | -2,799|Mbtus | $31,111| | $383,491|

===========================================================================

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|ANNUAL TOTAL | $0| | | $0|

|ONE TIME TOTAL | $0| | | $0|

|TOTAL | $0| | | $0|

=============================================================

4. First Year Dollar Savings $31,111

5. Simple Payback Period (Years) 9.35

6. Total Net Discounted Savings $383,491

7. Savings to Investment Ratio 1.32

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 5.55%
130 USACERL TR 99/24

Appendix M: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 2a

Life Cycle Cost Analysis Study: Option #2a

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2a

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $176,011

 B. SIOH $9,681

 C. Design Cost $10,561

 D. Total Cost (1A+1B+1C) $196,252

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $196,252

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 5,361|Mwatt-| $246,590| 14.47| $3,568,160|

|Elec. Deman| | | | | $45,670| 13.47| $615,175|

|Natural Gas| $3.4|/Mbtus| -45,660|Mbtus | -$155,244| 17.32|-$2,688,826|

|TOTAL | | | -27,369|Mbtus | $137,016| | $1,494,509|

===========================================================================
USACERL TR-99/24 131

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint | -$50,991|Annual | 13.47| -$686,849|

|ANNUAL TOTAL | -$50,991| | | -$686,849|

|Maintenance | -$16,934| 2| .92| -$15,626|

|Maintenance | -$15,797| 3| .89| -$14,003|

|Maintenance | -$55,950| 4| .85| -$47,643|

|Maintenance | -$15,458| 5| .82| -$12,644|

|Maintenance | -$16,724| 6| .79| -$13,141|

|Maintenance | -$55,542| 7| .75| -$41,924|

|Maintenance | -$17,998| 8| .73| -$13,050|

|Maintenance | -$18,115| 9| .7| -$12,618|

|Maintenance | -$56,639| 10| .67| -$37,897|

|Maintenance | -$16,586| 11| .64| -$10,661|

|Maintenance | -$18,184| 12| .62| -$11,227|

|Maintenance | -$54,056| 13| .59| -$32,062|

|Maintenance | -$18,527| 15| .55| -$10,140|

|Maintenance | -$72,476| 16| .53| -$38,105|

|Maintenance | -$19,212| 18| .49| -$9,321|

|Maintenance | -$16,250| 19| .47| -$7,573|

|Maintenance | -$55,120| 20| .45| -$24,677|

|ONE TIME TOTAL |-$539,568| | | -$352,314|

|TOTAL |-$590,559| | | -$1,039,163|

Life Cycle Cost Analysis Study: DAVMON2.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2a

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $59,047

5. Simple Payback Period (Years) 2.87

6. Total Net Discounted Savings $455,346

7. Savings to Investment Ratio 2.32

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 8.57%
132 USACERL TR 99/24

Appendix N: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 2b

Life Cycle Cost Analysis Study: Option #2b

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2b

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $211,132

 B. SIOH $11,612

 C. Design Cost $12,668

 D. Total Cost (1A+1B+1C) $235,412

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $235,412

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 7,188|Mwatt-| $330,671| 14.47| $4,784,803|

|Elec. Deman| | | | | $46,664| 13.47| $628,564|

|Natural Gas| $3.4|/Mbtus| -63,192|Mbtus | -$214,852| 17.32|-$3,721,231|

|TOTAL | | | -38,664|Mbtus | $162,483| | $1,692,136|

===========================================================================
USACERL TR-99/24 133

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint | -$50,991|Annual | 13.47| -$686,849|

|ANNUAL TOTAL | -$50,991| | | -$686,849|

|Maintenance | -$16,934| 2| .92| -$15,626|

|Maintenance | -$15,797| 3| .89| -$14,003|

|Maintenance | -$55,950| 4| .85| -$47,643|

|Maintenance | -$15,458| 5| .82| -$12,644|

|Maintenance | -$16,724| 6| .79| -$13,141|

|Maintenance | -$55,542| 7| .75| -$41,924|

|Maintenance | -$17,998| 8| .73| -$13,050|

|Maintenance | -$18,115| 9| .7| -$12,618|

|Maintenance | -$56,639| 10| .67| -$37,897|

|Maintenance | -$16,586| 11| .64| -$10,661|

|Maintenance | -$18,184| 12| .62| -$11,227|

|Maintenance | -$54,056| 13| .59| -$32,062|

|Maintenance | -$18,527| 15| .55| -$10,140|

|Maintenance | -$72,476| 16| .53| -$38,105|

|Maintenance | -$19,212| 18| .49| -$9,321|

|Maintenance | -$16,250| 19| .47| -$7,573|

|Maintenance | -$55,120| 20| .45| -$24,677|

|ONE TIME TOTAL |-$539,568| | | -$352,314|

|TOTAL |-$590,559| | | -$1,039,163|

Life Cycle Cost Analysis Study: DAVMON3.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2b

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $84,513

5. Simple Payback Period (Years) 2.51

6. Total Net Discounted Savings $652,973

7. Savings to Investment Ratio 2.77

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 9.55%
134 USACERL TR 99/24

Appendix O: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 2c

Life Cycle Cost Analysis Study: Option #2c

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2c

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $427,380

 B. SIOH $23,506

 C. Design Cost $25,643

 D. Total Cost (1A+1B+1C) $476,529

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $476,529

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 14,289|Mwatt-| $657,281| 14.47| $9,510,858|

|Elec. Deman| | | | | $154,883| 13.47| $2,086,274|

|Natural Gas| $3.4|/Mbtus|-113,421|Mbtus | -$385,633| 17.32|-$6,679,160|

|TOTAL | | | -64,666|Mbtus | $426,531| | $4,917,973|

===========================================================================
USACERL TR-99/24 135

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$101,982|Annual | 13.47| -$1,373,698|

|ANNUAL TOTAL |-$101,982| | | -$1,373,698|

|Maintenance | -$33,868| 2| .92| -$31,253|

|Maintenance | -$31,594| 3| .89| -$28,006|

|Maintenance |-$111,900| 4| .85| -$95,286|

|Maintenance | -$30,916| 5| .82| -$25,289|

|Maintenance | -$33,448| 6| .79| -$26,282|

|Maintenance |-$111,084| 7| .75| -$83,849|

|Maintenance | -$35,996| 8| .73| -$26,100|

|Maintenance | -$36,230| 9| .7| -$25,235|

|Maintenance |-$113,278| 10| .67| -$75,795|

|Maintenance | -$33,172| 11| .64| -$21,321|

|Maintenance | -$36,368| 12| .62| -$22,455|

|Maintenance |-$108,112| 13| .59| -$64,123|

|Maintenance | -$37,054| 15| .55| -$20,280|

|Maintenance |-$144,952| 16| .53| -$76,210|

|Maintenance | -$38,424| 18| .49| -$18,642|

|Maintenance | -$32,500| 19| .47| -$15,147|

|Maintenance |-$110,240| 20| .45| -$49,354|

|ONE TIME TOTAL |-$1,079,1| | | -$704,628|

|TOTAL |-$1,181,1| | | -$2,078,325|

Life Cycle Cost Analysis Study: DAVMON4.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2c

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $270,593

5. Simple Payback Period (Years) 1.65

6. Total Net Discounted Savings $2,839,647

7. Savings to Investment Ratio 5.96

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 13.82%
136 USACERL TR 99/24

Appendix P: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 2d

Life Cycle Cost Analysis Study: Option #2d

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2d

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $573,172

 B. SIOH $31,524

 C. Design Cost $34,390

 D. Total Cost (1A+1B+1C) $639,087

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $639,087

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 20,546|Mwatt-| $945,136| 14.47|$13,676,120|

|Elec. Deman| | | | | $232,056| 13.47| $3,125,795|

|Natural Gas| $3.4|/Mbtus|-178,587|Mbtus | -$607,197| 17.32|-$10,516,65|

|TOTAL | | |-108,480|Mbtus | $569,995| | $6,285,267|

===========================================================================
USACERL TR-99/24 137

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$152,973|Annual | 13.47| -$2,060,546|

|ANNUAL TOTAL |-$152,973| | | -$2,060,546|

|Maintenance | -$50,802| 2| .92| -$46,879|

|Maintenance | -$47,391| 3| .89| -$42,009|

|Maintenance |-$167,840| 4| .85| -$142,920|

|Maintenance | -$46,374| 5| .82| -$37,933|

|Maintenance | -$50,172| 6| .79| -$39,424|

|Maintenance |-$166,626| 7| .75| -$125,773|

|Maintenance | -$53,994| 8| .73| -$39,151|

|Maintenance | -$54,345| 9| .7| -$37,853|

|Maintenance |-$169,917| 10| .67| -$113,692|

|Maintenance | -$49,758| 11| .64| -$31,982|

|Maintenance | -$54,552| 12| .62| -$33,682|

|Maintenance |-$162,168| 13| .59| -$96,185|

|Maintenance | -$55,581| 15| .55| -$30,420|

|Maintenance |-$217,428| 16| .53| -$114,315|

|Maintenance | -$57,636| 18| .49| -$27,963|

|Maintenance | -$48,750| 19| .47| -$22,720|

|Maintenance |-$165,360| 20| .45| -$74,031|

|ONE TIME TOTAL |-$1,618,6| | | -$1,056,933|

|TOTAL |-$1,771,6| | | -$3,117,479|

Life Cycle Cost Analysis Study: DAVMON5.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #2d

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $336,088

5. Simple Payback Period (Years) 1.75

6. Total Net Discounted Savings $3,167,788

7. Savings to Investment Ratio 4.96

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 12.77%
138 USACERL TR 99/24

Appendix Q: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 3a

Life Cycle Cost Analysis Study: Option #3a

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3a

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $241,710

 B. SIOH $13,294

 C. Design Cost $14,503

 D. Total Cost (1A+1B+1C) $269,507

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $269,507

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 13,937|Mwatt-| $641,091| 14.47| $9,276,586|

|Elec. Deman| | | | | $147,375| 13.47| $1,985,141|

|Natural Gas| $3.4|/Mbtus|-113,421|Mbtus | -$385,632| 17.32|-$6,679,142|

|TOTAL | | | -65,867|Mbtus | $402,834| | $4,582,585|

===========================================================================
USACERL TR-99/24 139

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$101,982|Annual | 13.47| -$1,373,698|

|ANNUAL TOTAL |-$101,982| | | -$1,373,698|

|Maintenance | -$33,868| 2| .92| -$31,253|

|Maintenance | -$31,594| 3| .89| -$28,006|

|Maintenance |-$111,900| 4| .85| -$95,286|

|Maintenance | -$30,916| 5| .82| -$25,289|

|Maintenance | -$33,448| 6| .79| -$26,282|

|Maintenance |-$111,084| 7| .75| -$83,849|

|Maintenance | -$35,996| 8| .73| -$26,100|

|Maintenance | -$36,230| 9| .7| -$25,235|

|Maintenance |-$113,278| 10| .67| -$75,795|

|Maintenance | -$33,172| 11| .64| -$21,321|

|Maintenance | -$36,368| 12| .62| -$22,455|

|Maintenance |-$108,112| 13| .59| -$64,123|

|Maintenance | -$37,054| 15| .55| -$20,280|

|Maintenance |-$144,952| 16| .53| -$76,210|

|Maintenance | -$38,424| 18| .49| -$18,642|

|Maintenance | -$32,500| 19| .47| -$15,147|

|Maintenance |-$110,240| 20| .45| -$49,354|

|ONE TIME TOTAL |-$1,079,1| | | -$704,628|

|TOTAL |-$1,181,1| | | -$2,078,325|

Life Cycle Cost Analysis Study: DAVMON6.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3a

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $246,895

5. Simple Payback Period (Years) 1.01

6. Total Net Discounted Savings $2,504,260

7. Savings to Investment Ratio 9.29

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 16.37%
140 USACERL TR 99/24

Appendix R: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 3b

Life Cycle Cost Analysis Study: Option #3b

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3b

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $481,450

 B. SIOH $26,480

 C. Design Cost $28,887

 D. Total Cost (1A+1B+1C) $536,817

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $536,817

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 26,943|Mwatt-|$1,239,367| 14.47|$17,933,640|

|Elec. Deman| | | | | $310,453| 13.47| $4,181,802|

|Natural Gas| $3.4|/Mbtus|-244,743|Mbtus | -$832,128| 17.32|-$14,412,45|

|TOTAL | | |-152,811|Mbtus | $717,692| | $7,702,992|

===========================================================================
USACERL TR-99/24 141

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$203,964|Annual | 13.47| -$2,747,395|

|ANNUAL TOTAL |-$203,964| | | -$2,747,395|

|Maintenance | -$67,736| 2| .92| -$62,505|

|Maintenance | -$63,188| 3| .89| -$56,012|

|Maintenance |-$223,800| 4| .85| -$190,571|

|Maintenance | -$61,832| 5| .82| -$50,578|

|Maintenance | -$66,896| 6| .79| -$52,565|

|Maintenance |-$222,168| 7| .75| -$167,697|

|Maintenance | -$71,992| 8| .73| -$52,201|

|Maintenance | -$72,460| 9| .7| -$50,471|

|Maintenance |-$226,556| 10| .67| -$151,589|

|Maintenance | -$66,344| 11| .64| -$42,643|

|Maintenance | -$72,736| 12| .62| -$44,910|

|Maintenance |-$216,224| 13| .59| -$128,246|

|Maintenance | -$74,108| 15| .55| -$40,561|

|Maintenance |-$289,904| 16| .53| -$152,420|

|Maintenance | -$76,848| 18| .49| -$37,284|

|Maintenance | -$65,000| 19| .47| -$30,294|

|Maintenance |-$220,480| 20| .45| -$98,709|

|ONE TIME TOTAL |-$2,158,2| | | -$1,409,255|

|TOTAL |-$2,362,2| | | -$4,156,651|

Life Cycle Cost Analysis Study: DAVMON7.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3b

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $405,815

5. Simple Payback Period (Years) 1.21

6. Total Net Discounted Savings $3,546,342

7. Savings to Investment Ratio 6.61

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 14.41%
142 USACERL TR 99/24

Appendix S: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 3c

Life Cycle Cost Analysis Study: Option #3c

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3c

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $482,863

 B. SIOH $26,557

 C. Design Cost $28,972

 D. Total Cost (1A+1B+1C) $538,392

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $538,392

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 20,546|Mwatt-| $945,136| 14.47|$13,676,120|

|Elec. Deman| | | | | $232,056| 13.47| $3,125,795|

|Natural Gas| $3.4|/Mbtus|-179,077|Mbtus | -$608,863| 17.32|-$10,545,51|

|TOTAL | | |-108,970|Mbtus | $568,329| | $6,256,406|

===========================================================================
USACERL TR-99/24 143

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$152,973|Annual | 13.47| -$2,060,546|

|ANNUAL TOTAL |-$152,973| | | -$2,060,546|

|Maintenance | -$50,802| 2| .92| -$46,879|

|Maintenance | -$47,391| 3| .89| -$42,009|

|Maintenance |-$167,850| 4| .85| -$142,928|

|Maintenance | -$46,374| 5| .82| -$37,933|

|Maintenance | -$50,172| 6| .79| -$39,424|

|Maintenance |-$166,626| 7| .75| -$125,773|

|Maintenance | -$53,994| 8| .73| -$39,151|

|Maintenance | -$54,345| 9| .7| -$37,853|

|Maintenance |-$169,917| 10| .67| -$113,692|

|Maintenance | -$49,758| 11| .64| -$31,982|

|Maintenance | -$54,552| 12| .62| -$33,682|

|Maintenance |-$162,168| 13| .59| -$96,185|

|Maintenance | -$55,581| 15| .55| -$30,420|

|Maintenance |-$217,428| 16| .53| -$114,315|

|Maintenance | -$57,636| 18| .49| -$27,963|

|Maintenance | -$48,750| 19| .47| -$22,720|

|Maintenance |-$165,360| 20| .45| -$74,031|

|ONE TIME TOTAL |-$1,618,7| | | -$1,056,941|

|TOTAL |-$1,771,6| | | -$3,117,488|

Life Cycle Cost Analysis Study: DAVMON8.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3c

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $334,421

5. Simple Payback Period (Years) 1.49

6. Total Net Discounted Savings $3,138,918

7. Savings to Investment Ratio 5.83

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 13.69%
144 USACERL TR 99/24

Appendix T: Calculated Paybacks and

Savings-to-Investment Ratio

for Option 3d

Life Cycle Cost Analysis Study: Option #3d

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3d

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

 ECIP Summary Report

1. Investment

 A. Construction Cost $838,542

 B. SIOH $46,120

 C. Design Cost $50,313

 D. Total Cost (1A+1B+1C) $934,974

 E. Salvage Value of Existing Equip. $0

 F. Public Utility Company Rebate $0

 G. Total Investment (1D-1E-1F) $934,974

2. Energy Savings (+) / Costs (-)

Date of NISTIR 85-3273-X used for Discount Factors Oct 1995

===========================================================================

| Fuel |Price |Price | Usage |Usage | Annual |Discount|Discounted |

| | |Units |Savings |Units | Savings | Factor | Savings |

|===========|======|======|========|======|==========|========|===========|

|Electricity| $46.|/Mwatt| 40,791|Mwatt-|$1,876,397| 14.47|$27,151,460|

|Elec. Deman| | | | | $468,780| 13.47| $6,314,467|

|Natural Gas| $3.4|/Mbtus|-376,046|Mbtus |-$1,278,55| 17.32|-$22,144,57|

|TOTAL | | |-236,860|Mbtus |$1,066,622| |$11,321,360|

===========================================================================
USACERL TR-99/24 145

3. Non Energy Savings (+) / Costs (-)

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

|Baseline Maint |-$305,946|Annual | 13.47| -$4,121,093|

|ANNUAL TOTAL |-$305,946| | | -$4,121,093|

|Maintenance |-$101,604| 2| .92| -$93,758|

|Maintenance | -$94,782| 3| .89| -$84,018|

|Maintenance |-$335,700| 4| .85| -$285,857|

|Maintenance | -$92,748| 5| .82| -$75,867|

|Maintenance |-$100,344| 6| .79| -$78,847|

|Maintenance |-$333,252| 7| .75| -$251,546|

|Maintenance |-$107,988| 8| .73| -$78,301|

|Maintenance |-$108,690| 9| .7| -$75,706|

|Maintenance |-$339,834| 10| .67| -$227,384|

|Maintenance | -$99,516| 11| .64| -$63,964|

|Maintenance |-$109,104| 12| .62| -$67,365|

|Maintenance |-$324,336| 13| .59| -$192,369|

|Maintenance |-$111,162| 15| .55| -$60,841|

|Maintenance |-$434,856| 16| .53| -$228,630|

|Maintenance |-$115,272| 18| .49| -$55,926|

|Maintenance | -$97,500| 19| .47| -$45,440|

|Maintenance |-$330,720| 20| .45| -$148,063|

|ONE TIME TOTAL |-$3,237,4| | | -$2,113,883|

|TOTAL |-$3,543,3| | | -$6,234,975|

Life Cycle Cost Analysis Study: DAVMON9.LC

Energy Conservation Investment Program (ECIP) LCCID FY96

Installation & Location: Davis-Monthan AFB

Region data: ARIZONA Census Region: 4

Project NO. & Title: 250-Ton Chiller Replacement

Fiscal Year: 97 Discrete Portion: Option #3d

Analysis Date: 10/01/97 Economic Life: 20 years

Prepared by: William T Brown III

=============================================================

| Item |Savings/ | Year |Discount | Discounted |

| | Cost | | Factor |Savings/Cost|

|==================|=========|=======|=========|============|

=============================================================

4. First Year Dollar Savings $598,806

5. Simple Payback Period (Years) 1.43

6. Total Net Discounted Savings $5,086,382

7. Savings to Investment Ratio 5.44

 If < 1, Project does not qualify

8. Adjusted Internal Rate of Return 13.3%