Industrial Assessment Report
For
Dixon Recreation Center
Oregon State University
Corvallis, OR 97331
INDUSTRIAL ASSESSMENT CENTER
OREGON STATE UNIVERSITY
INDUSTRIAL ASSESSMENT CENTER
Sponsored by
The OSU Student Sustainability Initiative
Facilitated by
Samuel Walker
Assessment Report No. 2000
November 15, 2007
Joseph F. Junker, Assistant IAC Director
________________________________
Samuel Walker, Lead Analyst
________________________________
Assessment Participants
Blair Hasler
Alan Heninger
Wayne Johnson
Yuming Qui
Paul Stelson
Samuel Walker
Dr. George Wheeler
IAC Director
Batcheller Hall 341
Corvallis, OR
97331-2405
(541) 737-2515
Energy and Waste Analyst
Lighting Analyst
Energy and Productivity Analyst
Refrigeration Analyst
Energy Analyst
Lead Energy Analyst
Joseph F. Junker
Assistant Director
Batcheller Hall 344
Corvallis, OR
97331-2405
(541) 737-5034
PREFACE
The work described in this report is a service of the Oregon State University Industrial
Assessment Center (IAC). The project is funded by the OSU Student Sustainability Initiative.
The primary objective of the IAC is to identify and evaluate opportunities for energy
conservation, waste minimization, and productivity improvements through visits to industrial
sites. Data is gathered during a one-day site visit and assessment recommendations (ARs) are
identified. Some ARs may require additional engineering design and capital investment. When
engineering services are not available in-house, we recommend that a consulting engineering
firm be engaged to provide design assistance as needed. In addition, since the site visits by IAC
personnel are brief, they are necessarily limited in scope and a consulting engineering firm could
be more thorough.
We believe this report to be a reasonably accurate representation of energy use, waste
generation, and production practices, and opportunities in your plant. However, because of the
limited scope of our visit, the U.S. Department of Energy, Rutgers University, and the Oregon
State University Industrial Assessment Center cannot guarantee the accuracy, completeness, or
usefulness of the information contained in this report, nor assume any liability for damages
resulting from the use of any information, equipment, method or process disclosed in this report.
Pollution prevention recommendations are not intended to deal with the issue of compliance with
applicable environmental regulations. Questions regarding compliance should be addressed to
either a reputable consulting engineering firm experienced with environmental regulations or to
the appropriate regulatory agency. Clients are encouraged to develop positive working
relationships with regulators so that compliance issues can be addressed and resolved.
The assumptions and equations used to arrive at energy, waste, productivity, and cost savings for
the recommended ARs are given in the report. We believe the assumptions to be conservative. If
you do not agree with our assumptions you may make your own estimates of energy, waste,
productivity, and cost savings.
Please feel welcome to contact the IAC if you would like to discuss the content of this report or
if you have another question about energy use or pollution prevention. The IAC staff that visited
your plant and prepared this report is listed on the preceding page.
TABLE OF CONTENTS
1.
Introduction....................................................................................................................... 1
2.
Executive Summary .......................................................................................................... 2
3.
Assessment Recommendations ......................................................................................... 5
AR No. 1.
Natatorium Airflow ................................................................................ 5
Paul Stelson
AR No. 2.
Templifier Heat Pump .......................................................................... 20
Yuming Qui
AR No. 3.
Solar Water Heating ............................................................................. 29
Samuel Walker
AR No. 4.
Towel Monitoring ................................................................................ 37
Paul Stelson
AR No. 5.
Tennis Pavilion Lighting ...................................................................... 41
Alan Heninger
AR No. 6.
Day-Lighting ........................................................................................ 46
Alan Heninger
AR No. 7.
Racquetball Lighting ............................................................................ 52
Alan Heninger
AR No. 8.
Reduce Discharge Pressure .................................................................. 57
Yuming Qui
APPENDIX
A. Utilities ........................................................................................................................... 65
A.1. Energy Definitions .................................................................................................. 65
A.2. Energy Conversions ................................................................................................ 69
A.3. Energy Accounting ................................................................................................. 71
B. Lighting........................................................................................................................... 79
B.1. Lighting Definitions ................................................................................................ 79
Tennis Pavilion Worksheet ..................................................................................... 85
Day-Lighting Worksheet ........................................................................................ 86
C. Refrigeration ................................................................................................................... 95
C.1. Refrigeration Worksheet Definitions ...................................................................... 95
1. INTRODUCTION
This report describes how energy is used in your plant and includes our recommendations on
cost effective steps you can take to reduce your energy and waste costs and increase
productivity. The contents are based on our visit to your plant. The report is divided into three
major sections and three appendices:
1. Introduction. The purpose, contents and organization of the report are described.
2. Executive Summary. This section includes a summary of our recommendations, including
Assessment Recommendation Summary and Savings Summary tables. Additionally, electric
energy and steam use are summarized in the Existing Energy Use Summary table.
3. Assessment Recommendations. This section contains our Assessment Recommendations
(ARs). It includes any data collected during the audit, detailed calculations highlighting the
current and proposed systems, assumptions we use to estimate savings, our estimate of the
implementation cost, cost savings available upon implementation, and the simple payback
associated with implementation. Energy Trust of Oregon and/or Oregon Department of
Energy incentives reduce implementation costs when applicable. Some recommendations
will require a significant investment to implement, while others will cost little or nothing. We
have grouped our recommendations by category and then ranked them by cost savings.
Appendix A: Utilities. Your utility bills and energy use by process are summarized and plotted
in detail. Due to the changes in rate schedules and adjustments our calculations are an
approximation and may not be exactly consistent with your bills. Your water/sewage bills are
also included.
Appendix B: Lighting. The number and type of lighting fixtures are recorded for each area.
This appendix also includes the Lighting Worksheet Definitions, which describe the symbols and
terminology used in our lighting calculations. The lighting power and annual energy use for
each plant area are summarized in the Lighting Inventory worksheet.
Appendix C: Refrigeration. This appendix includes the Refrigeration Worksheet Definitions,
which describes the accompanying Refrigeration Energy Savings worksheet(s). The worksheet
uses bin weather data to model the refrigeration compressor’s operating conditions.
1
2. EXECUTIVE SUMMARY
This section includes a summary of our recommendations, including Assessment
Recommendation Summary and Savings Summary tables. Additionally, electric energy and
steam use are summarized in the Existing Energy Use Summary table.
Recommendation Summary. The following is a brief explanation of each recommendation
made in this report. If all eight recommendations are implemented, the total cost savings will be
$162,300 and will pay for costs in 1.0 year.
AR No. 1 - Natatorium Airflow: Install variable frequency drives (VFDs) on AHU1 (Air
Handling Unit) and RF1 (Return Fan) and allow your natatorium control system to reduce air
flow to meet, but not overcompensate for zone relative humidity requirements. This will reduce
electrical and steam energy usage considerably for the natatorium.
AR No. 2 - Templifier Heat Pump: Install a Templifier Heat Pump on the chiller suction water
loop to heat shower (or laundry) water to 110°F. Energy savings come from reduced chiller load
and recovered heat. This will save 21% of your steam cost, and lower chiller compressor energy
costs by 33%.
AR No. 3 - Solar Water Heating: Install solar thermal collectors on the roof of your facility to
reduce existing steam pool-heating requirements. This will reduce pool energy consumption by
approximately 30%.
AR No. 4 - Towel Monitoring: Monitor towel usage from the equipment checkout desk and
assess a fee for all towels not returned by the end of each day. The number of towels removed
from the facility should decrease, and fees will pay for at least the replacement of lost towels.
AR No. 5 - Tennis Pavilion Lighting: Replace metal halide fixtures in the Tennis Pavilion with
six-lamp T5 high output (HO) fixtures, including integrated motion sensors. This will allow
lights to be turned on only when the tennis courts are being used, reducing lighting operating
costs by 70% in that area.
AR No. 6 - Day-Lighting: Install photo sensors near windows, skylights and in the Recreation
Center to reduce localized light operating hours during daylight hours. This will reduce lighting
energy costs by over 30%.
AR No. 7 - Racquetball Lighting: Replace T12 ballasts and lamps with T8 ballasts and lamps
in the racquetball and squash courts. This will reduce energy use in these areas and help you
simplify your lighting inventory, as these are some of the last areas still utilizing T12 lamps.
AR No. 8 - Reduce Discharge Pressure: Analyze the scale composition and apply chemical
descaling on your roof condenser to reduce the approach temperature (between refrigerant and
ambient air) from 28°F to 20°F. This will reduce the load on your chiller system compressors,
lowering compressor energy costs by 7%.
2
Assessment Recommendation Summary
Energy
AR#
6
Description
(10 Btu)
Electrical
Cost
Implementation
Payback
Energy (kWh)
Savings
Cost*
(years)
1,2
1
Natatorium Airflow
4,312
217,700
$71,900
$8,800
2
Templifier Heat Pump
4,052
20,800
$59,200
$80,500 2
1.4
2
3.1
3
Solar Water Heating
1,293
-
$18,600
$58,300
4
Towel Monitoring
-
-
$4,200
$40
5
6
7
Tennis Pavilion Lighting
-
Day-Lighting
67,200
-
Racquetball Lighting
15,400
-
8
Reduce Discharge Pressure
Totals
9,657
$4,040
$1,300
0.1
0.0
$7,000
1,2
1.7
$1,800
1,2
1.4
1,2
4.4
9,300
$540
$2,400
56,800
387,200
$2,600
$162,300
$2,600
$161,440
1.0
1.0
* Implementation Cost represents final costs after applicable incentives, as noted
1
This final cost is reduced by Energy Trust of Oregon Incentives. Note that such incentives are available for
electrical energy efficiency measures because OSU pays the associated public purpose charge on electrical
bills. OSU does not pay the NW Natural public purpose charge; therefore, Energy Trust incentives are not
available for natural gas saving measures.
2
This final cost is reduced by an Oregon Department of Energy Business Energy Tax Credit. As a public
entity your facility cannot take the full incentive for efficiency and renewable energy projects. Instead, you
may take advantage of a “pass-through” option, which allows you to transfer the tax credit to a pass-through
partner in exchange for a lump sum cash payment, after applying other incentives.
Savings Summary. Total cost savings are summarized by energy cost savings. % Use
Reduction is energy cost savings divided by the total annual respective (steam, electrical) energy
costs from the Existing Energy Use Summary table below. Savings % is cost savings for each
category (steam or electrical) divided by total energy cost savings. Cost savings associated with
the Towel Monitoring AR are not included in the Savings Summary table.
Savings Summary
Source
Steam Energy
Electrical Energy
Totals
Qty.
Units
9,657 106 Btu
387,215 kWh
Cost
% Use
Savings
Reduction
Savings %
53.9%
14.8%
88.92%
11.08%
100.0%
$139,061
$17,328
$156,400
Energy Use Summary. We use your utility bills to determine annual energy use for all fuels.
From these bills we summarize annual energy consumption at your plant in the following table.
3
Existing Annual Energy Use Summary
Source
Steam Energy
Electric Energy
Totals
Qty.
Units 106Btu
15,169,400 lbs
Use %
Cost
Cost %
17,900
66.7%
$257,880
68.8%
8,929
33.3%
$117,186
31.2%
26,800
100.0%
$375,100
100.0%
2,618,460 kWh
Energy costs and calculated savings are based on the incremental cost of each energy source.
The incremental rate is the energy charge first affected by an energy use reduction and is taken
from your utility rate schedules. For example, electrical use and savings include energy (kWh),
demand (kW), reactive power charges (KVARh or power factor), and other fees such as basic
charges, transformer rental, and taxes. The fuel costs we used can be found in the Energy
Accounting Summary in Appendix A.
4
3. ASSESSMENT RECOMMENDATIONS
AR No. 1
Natatorium Airflow
Recommended Action
Install variable frequency drives (VFDs) on AHU1 (Air Handling Unit) and RF1 (Return Fan)
and allow your natatorium control system to reduce airflow to meet, but not overcompensate for
zone relative humidity needs. This will reduce electrical and steam energy usage dramatically for
the natatorium.
Energy
(106 Btu)
Assessment Recommendation Summary
Electrical
Cost
Implementation Payback
Energy (kWh) Savings
Cost
(years)
4,312
217,700
$71,900
$15,800
0.2
Estimated Incentive Summary
ETO
BETC2
Net
Net Payback
Incentive
Tax Credit
Cost
(years)
$4,000
$3,000
$8,800
0.1
1
1
2
Energy Trust of Oregon Incentive
Oregon Department of Energy Business Energy Tax Credit
Background
The natatorium control system is designed to control air exchanges using dampers that maintain
a set point maximum of 50% relative humidity (RH) as monitored by space and ceiling mounted
humidity sensors. During occupied hours the minimum damper set point is 25% open
(approximately 10,000 cfm), which allows for adequate air exchanges. The system can also
monitor space temperature and modulate a heating coil valve to maintain an 84°F set point.
Ideally, the current system should control dampers and heating coil valves to meet the two set
points, but it does not currently operate in this way. The dampers are manually set to full open
due to facility personnel’s preference. This debilitates the control system and is a very expensive
control solution. Installing two VFD’s and enabling the system to control the natatorium airflow
will result in large energy and dollar savings. Note that in order to satisfy the energy balance we
developed for your facility we must assume the natatorium air system already has a heat
recovery system incorporated (included in the analysis below).
Data Collected Summary
During our site visit we collected the following information.
•
OR2000
Air handling system operation: 24/7 or 8,760 annual operating hours
5
•
•
•
•
Max air handling system airflow: 40,000 cfm
Total air handling system electrical demand at operating point: 28.1 kW
Steam cost: $0.017 per pound of steam
Electrical energy cost: $0.045/kWh
We also collected information from the control system’s monitoring screen, summarized in the
following table.
Control Screen Values
Outside
Zone
Outside
Zone
1st Visit
Air
Air
2nd Visit
Air
Air
o
o
Temp ( F)
89
88
Temp ( F)
78
82
% RH
25.4
30
RH
50
44
Humidity Ratio
0.0075
0.0085 Humidity Ratio 0.01025 0.011
Air gained 0.001 lbs water/lb air
Air gained 0.00075 lbs water/lb air
Note: Average water gained is 0.000875 lbs water/lb air
Savings Analysis
The first step in this analysis is setting a benchmark of current operating conditions and costs.
The current electrical energy cost to operate the two 40 hp air handling units is calculated as:
EC
=
=
=
=
Existing Electrical Energy Cost to Operate Fan Motors
EP x OH x IC
28.1 kW x 8,760 hrs/yr x $0.045/kWh
$11,100/yr
EP
=
=
Existing Power for Both 40 hp Motors
28.1 kW
OH
=
=
Operating Hours
8,760 hrs/yr
IC
=
=
Incremental Energy Cost (kWh)
$0.045/kWh
Where,
To calculate the cost of heating incoming outside air to 84°F with steam is more complicated and
requires more information. Local organizations have been recording temperature data for many
years in the Pacific Northwest. Using averaged information in recorded bin data we are better
able to represent weather conditions year round. Bin data display a bin, which is a range of
temperatures, and how many corresponding hours a year the region is at that temperature. Mean
Coincident Wet Bulb (MCWB) is the temperature that a wet thermometer would cool to at a
given temperature and can be used to determine the typical relative humidity.
OR2000
6
The Humidity Ratio is a measure of how many pounds of water a pound of dry air can carry
before it becomes fully saturated. Using the dry bulb temperature, the corresponding MCWB
temperature and a psychometric chart we obtain Relative Humidity and Humidity Ratio values.
A table showing the necessary bin data can be seen at the end of this recommendation. Using the
tabulated data and several of the properties of air we determine how much energy is needed to
heat incoming air to 84°F. For the example calculation we look at the bin with the average
temperature of 67°F. Using a psychometric chart and the bin values for the average bin
temperature, the MCWB temperature, and the final temperature of 84°F, we find the change in
specific enthalpy or how many Btu’s per pound are needed to increase the temperature.
The mass flow rate of the air is calculated as:
MFAir
=
=
=
=
Mass Flow Rate of Air for Bin 67°F
VF ÷ SV x 60 mins/hr
40,000 cfm ÷ 13.35 ft3/lb x 60 mins/hr
179,800 lbs/hr
VF
=
=
Full Volumetric Flow
40,000 cfm
SV67
=
=
Specific Volume of Air at 67°F
13.35 ft3/lb
Where,
Energy required to heat the air can be calculated as:
BT67
Where,
AH67
ΔSE67
Where,
SE84
SE67
OR2000
=
=
=
=
Btu Required for Bin 67°F
AH67 x ΔSE x MFAir
525 hrs x 4.5 Btu/lb x 179,775 lbs/hr
425 x 106 Btu
=
=
Annual Hours for Bin 67°F
525 hrs
=
=
=
=
Change In Specific Enthalpy for Bin 67°F
SE84 – SE67
29.5 Btu/lb – 25.0 Btu/lb
4.5 Btu/lb
=
=
Specific Enthalpy for 84°F at the MCWB
29.5 Btu/lb
=
=
Specific Enthalpy for 67°F at the MCWB
25.0 Btu/lb
7
Completing all bins as in the above example yields the total energy required to heat outside air to
the zone temperature of 84°F. The following table summarizes required energy for each bin
temperature.
Bin Avg.
Temp (°F)
2
7
12
17
22
27
32
37
42
47
52
57
62
67
72
77
Total
Annual
Hours
1
2
7
24
52
123
441
798
1,180
1,388
1,406
1,119
772
525
359
249
Btu Calculation Totals
Temp
Change In Specific
Change (°F)
Enthalpy
82
20.0
77
20.0
72
20.0
67
20.0
62
18.0
57
13.0
52
12.0
47
11.0
42
10.0
37
9.0
32
5.5
27
6.0
22
5.5
17
4.5
12
3.0
7
2.0
Specfic Volume
(Ft3/lb)
11.70
11.82
11.95
12.08
12.21
12.33
12.45
12.58
12.71
12.84
12.97
13.09
13.23
13.35
13.48
13.61
Next, we calculate the cost to heat incoming air using the above tabulated values.
HEC
=
=
=
=
Heating Energy Cost
THE x IC
12,841 x 106 Btu/yr x $14.40 per 106 Btu
$185,000/yr
=
=
Total Heating Energy (from Btu table above)
12,841 x 106 Btu/yr
IC
=
=
=
=
Incremental Energy Cost (Btu)
SC ÷ HF60 x 1,000,000 Btu/106 Btu
$0.0170/lb ÷ 1,180 Btu/lb x 1,000,000 Btu/106 Btu
$14.40/106 Btu
SC
=
=
Steam Cost
$0.0170/lb
Where,
THE
Where,
OR2000
8
MMBTU
4
8
28
95
148
311
1,062
1,751
2,229
2,336
2,081
1,334
770
425
192
66
12,841
HF60
=
=
Latent Heat of Steam at 60 psi
1,180 Btu/lb
After performing an energy balance analysis on the steam system we determined the calculated
$185,000 natatorium heating cost is too high in comparison to actual steam costs. The most
conservative approach (invoked here) assumes the natatorium air system incorporates a heat
recovery heat exchanger that reduces the cost of space heating. Information pertaining to the heat
exchanger could not be obtained during visits to the facility. We estimate the heat exchanger
contribution based on an energy balance of purchased steam and modeled steam use for different
applications, including heating requirements for shower and pool water (see calculation below).
We do not have steam space heating requirements for the remainder of Dixon; therefore, we
assume space heating consumes one third of the remaining unaccounted energy. The energy
balance is calculated as:
RSC
=
=
=
=
Remaining Steam Cost
TS -WH – PH
$258,000/yr - $83,000/yr - $54,000/yr
$121,000/yr
TS
=
=
Total Steam Cost (from utility bills)
$258,000/yr
WH
=
=
=
=
Shower Water Heating Cost (from Templifier Heat Pump AR)
0.66 x 106 Btu/hr x 8,760 hrs/yr x IC
0.66 x 106 Btu/hr x 8,760 hrs/yr x $14.40/106 Btu
$83,000/yr
PH
=
=
Pool Heating Cost (from RETScreen analysis in Solar Water Heating AR)
$54,000/yr
Where,
With $121,000 left in unaccounted steam bills we assume that approximately 1/3 of the
remaining steam cost contributes to facility space heating in the remainder of the facility. An
estimate of steam usage for natatorium air heating is estimated as:
SC
=
=
=
=
Steam Cost for Natatorium Space Heating
RSC – SH
$121,000/yr - $41,000/yr
$80,000/yr
SH
=
=
=
=
Space Heating Estimation (for remainder of facility)
RSC x 1/3
$121,000 x 1/3
$40,000/yr
Where,
OR2000
9
Using this estimate of $80,000 of actual natatorium space heating steam cost we estimate the
total value of energy recovered by the heat exchanger is close to $105,000, calculated as:
XS
=
=
=
=
Heat Exchanger Savings
HEC – SC
$185,000/yr - $80,000/yr
$105,000/yr
Using these assumed values for actual Steam Cost and Heat Exchanger Savings, along with the
BTU calculations and psychometric table we are able to develop an approximate heat recovery
approach temperature and resulting preheat temperature for air after it has passed through the
heat exchanger. A preheat temperature of 67°F yielded a steam cost of $82,800 (close to our
estimated cost with preheated air as noted above).
Using bin 57°F for the example calculation as follows:
SB57
Where,
XB57
=
=
=
=
Steam Btu for Bin 57°F
BT57 – XB57
1,334 x 106 Btu– 616 x 106 Btu
718 x 106 Btu
=
=
Exchanger Btu for Bin 57°F
616 x 106 Btu
The following table summarizes total energy, exchanger savings, and steam energy for each bin.
OR2000
10
Bin Avg.
Temp (°F)
2
7
12
17
22
27
32
37
42
47
52
57
62
67
72
77
Total
Existing Condition Summary
Total
Heat Exchanger
MMBTU
MMBTU
4
3
8
6
28
22
95
76
148
102
311
227
1,062
637
1,751
1,142
2,229
1,449
2,336
1,298
2,081
1,301
1,334
616
770
210
425
0
192
0
66
0
12,841
7,090
Steam
MMBTU
1
2
6
19
46
84
425
609
780
1,038
780
718
560
425
192
66
5,750
The cost to heat incoming outside air can be calculated as:
HC
=
=
=
=
Heating Cost
HE x IC
5,750 x 106 Btu x $14.40/106 Btu
$82,800/yr
HE
=
=
Heating Energy (from Btu table above)
5,750 x 106 Btu/yr
Where,
Total current costs can be calculated as:
CC
=
=
=
=
Current Cost
EC + HC
$11,100/yr + $82,800/yr
$93,900/yr
Our next step requires us to determine to what degree the air flow through the Natatorium can be
reduced without exceeding the target relative humidity. A key component of this analysis is
balancing the flow of water from the evaporating surfaces of the pools to the water being carried
in the air that is leaving the building. The first step in this analysis is to find out how much water
is being evaporated from the pools. To find this evaporative flow we use information collected
OR2000
11
from the computer control system readout screen. First we find the humidity ratio at the control
system set points of 84°F and 50% RH. Using the psychometric chart the value is found to be
0.0125 pounds of water per pound of air.
Using the average humidity ratio difference from the Control Screen Values table (above) we
find the mass flow rate of water from the pools as follows:
MFW
=
=
=
=
Mass Flow Rate of Water from Pool Surfaces
MFAir84 x AW
2,905 lbs air/min x 0.000875 lbs water/lb air
2.55 lbs water/min
=
=
=
=
Mass Flow Rate Air at 84°F
VF ÷ SV
40,000 cfm ÷ 13.77 ft3/lb
2,905 lbs/min
VF
=
=
Full Volumetric Flow Rate
40,000 cfm
SV84
=
=
Specific Volume of Air at 84°F
13.77 ft3/lb
AW
=
=
=
Absorbed Water
0.000875 lbs water per lb air
The average change in absolute humidity of air through the natatorium
observed on two visits to the facility.
Where,
MFAir84
Where,
With the mass flow rate of water, which we assume to be constant, we can use the bin data along
with the set point values to obtain needed airflow to meet the constant mass flow rate of water.
(This is a simplifying assumption. In reality evaporating water will vary with RH in the
natatorium. We develop our evaporation estimate for dryer conditions, which results in a
conservative model. Less evaporation would allow you to reduce air flow even more without
experiencing excess humidity).
Once again we use bin 67°F as our calculation example.
AF67
OR2000
=
=
=
=
Airflow for Bin 67°F
(MFW x SV67) ÷ HR84 – HR67
(2.55 lbs water/min x 13.35 ft3/lb air) ÷ 0.004 lbs water/ lb air
8,500 cfm
12
Where,
HR84
HR67
=
=
Humidity Ratio for 84°F
0.0125 lbs water per lb air
=
=
Humidity Ratio for Bin 67°F
0.0085 lbs water per lb air
Next, we address the requirement voiced by facility personnel that the natatorium needs a
minimum 10,000 cfm of airflow during operating hours regardless of the evaporating water. To
better understand flow requirements, please refer to the table at the end of this recommendation.
On days when the outside air must be heated, the needed airflow to balance the flow of water is
less than the 10,000 cfm, required during operating hours. The entries labeled <5 are values that
have a negligible effect on the calculation. The humidity ratios and desired flows for these
temperature ranges are very small. Since 10,000 cfm is required, we use this value in our savings
calculations. Once again we use the change in specific enthalpy to allow us to calculate the
amount of energy needed to heat the air to zone temperature.
Proposed Btu’s required to raise bin 57°F to 84°F at 10,000 cfm are calculated as:
PB57
=
=
=
=
Proposed Btu Requirements for Bin 57°F
10,000 cfm ÷ SV57 x 60 mins/hr x AH57 x ΔSE57
10,000 cfm ÷ 13.09 ft3/lb x 60 mins/hr x 1,119 hrs x 6.5 Btu/lb
333.4 x 106 Btu
Proposed heat exchanger savings are calculated as:
PX57
=
=
=
=
Proposed Heat Exchanger Energy for bin 57°F
10,000 cfm ÷ SV57 x 60 mins/hr x AH57 x ΔSE57-67
10,000 cfm ÷ 13.09 ft3/lb x 60 mins/hr x 1,119 hrs x 3 Btu/lb
153.9 x 106 Btu
Using the proposed total Btu and heat exchanger energy we can find the steam energy as follows:
PS57
=
=
=
=
Proposed Steam Energy for bin 57°F
PB57 - PX57
333.4 x 106 Btu - 153.9 x 106 Btu
179.5 x 106 Btu
Proposed conditions for each bin are tabulated in the table below.
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13
Bin Avg.
Temp
2
7
12
17
22
27
32
37
42
47
52
57
62
67
72
77
Total
Proposed Condition Summary
Total
Heat Exchanger
Steam
MMBTU
MMBTU
MMBTU
1
1
<5
2
2
<5
7
6
<5
24
19
<5
37
26
11
78
57
21
266
159
106
438
285
152
557
362
195
584
324
260
520
325
195
333
154
180
193
53
140
106
0
106
48
0
48
16
0
16
3,210
1,773
1,438
The proposed heating cost can now be calculated as:
PHC
Where,
PHE
=
=
=
=
Proposed Heating Cost
PHE x IC
1,438 x 106 Btu x $14.40/106 Btu
$20,700/yr
=
=
Proposed Heating Energy (total of proposed Btu calculations)
1,438 x 106 Btu
To calculate the proposed electrical cost of operating the air handling units we use a formula for
fans retrofitted with VFDs. We assume the air handling units run at the minimum required
airflow year round. Electrical savings result from reduced fan energy associated with reduced
flow needs. Utilizing a power-capacity relationship for fans, which relies on a cubic law we find
the proposed power. The equation assumes a 10% overhead due to the required VFD equipment.
The formula for the power-capacity relationship is:
PP
OR2000
=
=
=
=
Proposed Power
FLP x (.1 + %C3)
28.1 kW x (.1 + .253)
3.25 kW
14
Where,
LP
=
=
Loaded Power
28.1 kW
%C
=
=
% Capacity
25 %
Now that we have the proposed power we can find the proposed electrical energy and
corresponding cost.
PC
=
=
=
=
Proposed Electrical Cost
PE x IC
28,470 kWh x $0.045/kWh
$1,300/yr
PE
=
=
=
=
Proposed Electrical Usage
PP x OH
3.25 kW x 8,760 hrs/yr
28,500 kWh/yr
Where,
Fan electrical savings associated with reduced fan operation cost can be calculated as:
ECS
=
=
=
=
Fan Electrical Cost Savings
EC – PC
$11,100/yr - $1,300/yr
$9,800/yr
Heating Savings can be calculated as:
HS
=
=
=
=
Heating Savings
HC – PHC
$82,800/yr - $20,700/yr
$62,100/yr
Total Savings result from both Electrical and Heating Savings.
TS
=
=
=
=
Total Savings
ECS + HS
$9,800 + $62,100/yr
$71,900/yr
Electrical and Steam Energy Savings are summarized in the table below.
OR2000
15
Source
Steam Energy
Electrical Energy
Total
Savings Summary
Quantity Units
$/Unit
6
4,312
10 Btu
$14.40
217,700 kWh
$0.045
Savings
$62,110
$9,800
$71,900
*Note: Steam Energy savings are possible without the VSDs (and virtually no implementation
cost) by allowing the system to use the dampers to adjust air flow.
It is worth noting that even on humid outdoor days, outside air introduced to the pool area has a
significantly lower RH once heated to room temperature. The following table summarizes the
final RH of typical outside air in your area after it has been heated to 84°F.
Bin Avg.
Temp (°F)
2
7
12
17
22
27
32
37
42
47
52
57
62
67
72
77
MCWB
(°F)
2
7
11
16
21
27
32
36
41
45
49
53
56
58
60
62
Bin Data
Outside Relative
Humidity
NA
NA
NA
NA
90%
100%
100%
90%
90%
90%
57%
78%
70%
60%
50%
45%
Relative Humidity
After Heating
<10%
<10%
<10%
<10%
10%
11%
17%
20%
23%
24%
22%
35%
35%
33%
35%
35%
Cost Analysis
The implementation cost includes the purchase and installation of two 40 hp VFD’s for AHU1
and RF1. We recommend you install the drives during one of the facilities planned down times.
Implementation Summary
Source
Quantity Cost per Unit
40 hp VFD (Installed)
2
$7,900
Savings will pay for implementation in approximately 0.2 years.
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16
Total Cost
$15,800
Incentive Analysis
Energy Trust of Oregon custom cash incentives are available to help pay for implementation
costs associated with (electrical) energy efficient projects. Custom incentives will pay up to 25%
of project costs, not exceeding $0.12 per kWh saved.
ETO
=
=
=
=
=
Energy Trust of Oregon Cash Incentive
Minimum of
ES x $0.12/kWh
Minimum of
217,700 kWh x $0.12/kWh
Minimum of
$26,000
$4,000
ES
=
=
=
=
Electrical Savings
(EP - PP) x 8,760 hrs/yr
(28.1 kW - 3.25 kW) x 8,760 hrs/yr
217,700 kWh
TC
=
=
Total Implementation Cost
$15,800
or
or
or
0.25 x TC
0.25 x $15,800
$4,000
Where,
You may also be eligible for the Oregon Business Energy Tax Credit (BETC). As a public entity
your facility cannot take the full incentive for retrofit projects (35% of the project costs). Instead,
you may take advantage of a “pass-through” option, which allows you to transfer the 35% tax
credit to a pass-through partner in exchange for a lump sum cash payment, equal to 25.5% of
project costs, after applying other incentives. The BETC can reduce implementation costs as
follows:
BETC
=
=
=
=
Business Energy Tax Credit
(TC - ETO) x 0.255
($15,800 - $4,000) x 0.255
$3,000
The following table summarizes incentives and net costs.
Incentive Summary
Description
Pre-incentive Cost
Energy Trust Incentives
Business Energy Tax Credit
Total After Incentives
Cost
$15,800
($4,000)
($3,000)
$8,800
After incentives, savings will pay for implementation in 0.1 years.
OR2000
17
Note
The Energy Trust and Oregon Department of Energy require written agreement prior to project
implementation.
When presenting this project for incentives present only the VFD analysis. The natatorium
damper adjustment is not eligible for incentives.
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18
Bin Data
Bin Avg.
Temp
(F)
MCWB
(F)
Outside
Relative
Humidity
2
2
7
Current
Steam
MMBTU
Needed
Flow
(ACFM)
Proposed
MMBTU
at 10,000
CFM
Hours
Humidity
Ratio
Specific
Volume
Ft3/lb
NA
1
NA
11.70
20.0
4
1
NA
1
0
7
NA
2
NA
11.82
20.0
8
2
NA
2
0
12
11
NA
7
NA
11.95
20.0
28
6
NA
7
1
17
16
NA
24
NA
12.08
20.0
95
19
NA
24
5
22
21
90%
52
0.0020
12.21
14.5
148
46
2,957
37
11
27
27
100%
123
0.0030
12.33
13.0
311
84
3,301
78
21
32
32
100%
441
0.0040
12.45
12.5
1,062
425
3,726
266
106
37
36
90%
798
0.0043
12.58
11.5
1,751
609
3,877
438
152
42
41
90%
1180
0.0053
12.71
10.0
2,229
780
4,457
557
195
47
45
90%
1388
0.0055
12.84
9.0
2,336
1,038
4,663
584
260
52
49
57%
1406
0.0065
12.97
8.0
2,081
780
5,497
520
195
57
53
78%
1119
0.0078
13.09
6.5
1,334
718
7,007
333
180
62
56
70%
772
0.0083
13.23
5.5
770
560
7,915
193
140
67
58
60%
525
0.0085
13.35
4.5
425
425
8,488
106
106
72
60
50%
359
0.0085
13.48
3.0
192
192
8,568
48
48
77
62
45%
249
0.0085
13.61
1.5
66
66
8,650
16
16
3210
1438
Total
Change In
Specific
Enthalpy
Current
MMBTU
12,841
5,750
*Note that the actual moisture in local outside air is lower during colder hours (even if the outdoor relative humidity may appear higher).
OR2000
19
Proposed
Steam
MMBTU
AR No. 2
Templifier Heat Pump
Recommended Action
Install a Templifier Heat Pump (heat recovery system) on the chilled water loop to heat shower
(or laundry) water to 110°F. Energy savings come from reduced chiller load and recovered heat.
This will save 21% of your steam cost, and lower chiller compressor energy costs by 33%.
Assessment Recommendation Summary
Electrical
Cost Implementation
Energy (kWh)
Savings
Cost
Energy
(106Btu)
4,052
20,800
$59,200
Payback
(years)
$108,000
1.8
Estimated Incentive Summary
BETC1
Net
Net Payback
Tax Credit
Cost
(years)
$27,500
$80,500
1.4
1
Oregon Department of Energy Business Energy Tax Credit
Background
Your chiller runs year round, pulling heat
out of the air inside Dixon and discharging
it into the atmosphere. Meanwhile the
steam heater provides heat for the showers,
laundry, and swimming pools. A large
portion of this heating requirement can be
replaced with recovered chiller discharge
energy.
Templifiers are heat pumps that can
recover low-grade heat and convert it into
high-grade heat. They can be added to
existing chiller systems. Templifiers have a
minimal impact on chilled water plant
operation. Their primary purpose is to heat
water more economically than steam
heaters. A secondary benefit is pre-cooling
of chilled water entering the chiller, reducing
cooling load.
Figure 1: Templifier Heat Pump
Photo courtesy of McQuay
Please note, we do not endorse specific vendors.
The heat recovery unit is installed in the hot line of the Templifier’s refrigerant circuit. The hot
vapor flows through a heat exchanger. The city water absorbs the heat from the vapor, and then
OR2000
20
is heated to 110°F. This provides highly efficient water heating with a cost of $2.87 per million
Btu. The same one million Btu costs around $14.40 using your current steam heater and around
$12.90 with an electric resistance heater (COP = 1, see definition below). Note that this
relationship is not typical. Electric heating costs are usually greater than gas.
Chilled Water Loop
City
Water
@50oF
Supplementary
Steam
Heater
44oF
Water
Tank
o
110 F
50oF
47oF
Figure 2: Heat Recovery Chiller Piping Schematic
Data Collected Summary
During our site visit, we obtained part load performance specifications for your 150 ton chiller
(exit water temperature is 44oF with an ambient temperature of 95oF). We knew little about your
annual chiller load profile; therefore, we made assumptions based on local weather bin data and
the measured scenario, as summarized in the following table.
Chiller Part Load Performance and Load Profile
Load Percentage* Capacity (ton) Power (kW) Percentage**
100%
139.7
176.7
10%
75%
104.7
113.3
25%
50%
69.8
66.5
25%
25%
34.9
28.9
40%
Average
COP
2.8
3.3
3.7
4.3
3.8
* Represents the load percentage of the whole chiller capacity including both compressors
** Operation time percentage of annual hours (8,760 hours)
From the Water Utility spreadsheet (Appendix A), we obtain the following information:
•
Average sewage use is: 1,192 Tgal/month, i.e. 1,655 gal/hr. Installation of a hot water
storage tank (explained later in this AR) allows for this simplification.
The Coefficient of Performance (COP) is defined as the useful energy output divided by electric
energy input, all expressed in the same units of measure. The Templifier’s COP is very
OR2000
21
dependant on the supply and final hot water temperature. The source city water is estimated at
50°F, and water exiting the Templifier is estimated at 110°F. We estimate possible savings with
the following assumptions:
•
•
Templifier COP heating : 4.5 (from the attached performance data of a brand name
Templifier)
Shower water is 80% of the facility water use (1,655 gal/hr), i.e. 1,320 gal/hr
Savings Analysis
Energy savings come from reduced chiller cooling load and recovered chiller heat. Energy
savings are calculated below.
Average chiller capacity is calculated as:
CC
=
=
=
=
Average Chiller Capacity
CP1 x RP1 + CP2 x RP2 + CP3 x RP3 + CP4 x RP4
139.7 ton x 10% + 104.7 ton x 25% + 69.8 ton x 25% + 34.9 ton x 40%
71.6 ton
CP1
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
Chiller Chilling at 100% Capacity
139.7 ton
Chiller Chilling at 75% Capacity
104.7 ton
Chiller Chilling at 50% Capacity
69.8 ton
Chiller Chilling at 25% Capacity
34.9 ton
Annual Running Percentage at 100% Capacity
10%
Annual Running Percentage at 75% Capacity
25%
Annual Running Percentage at 50% Capacity
25%
Annual Running Percentage at 25% Capacity
40%
Where,
CP2
CP3
CP4
RP1
RP2
RP3
RP4
Average chiller capacity is a good estimate of the energy available in the chiller glycol loop,
which can be recovered by the Templifier. We can determine how much energy is available for
Templifier output, calculated as:
ET
=
=
=
=
Energy Available in Templifier Output
CC x TP ÷ (TP – 1) x CF
71.6 ton x 4.5 ÷ (4.5 - 1) x 12,000 Btu/hr/ton
1.10 x 106 Btu/hr
OR2000
22
Where,
TP
=
=
Templifier Coefficient of Performance Heating
4.5
CF
=
=
Conversion Factor
12,000 Btu/hr/ton
Now we determine the amount of energy needed to heat all shower water to 110°F.
EN
=
=
=
=
Energy Needed per Hour to Heat Shower Water
(h110 – h50) x AW x WW
(78.02 Btu/lb – 18.07 Btu/lb) x 1,320 gal/hr x 8.35 lb/gal
0.66 x 106 Btu/hr
h110
=
=
Enthalpy of water at 110°F
78.02 Btu/lb
h50
=
=
Enthalpy of water at 50°F
18.07 Btu/lb
AW
=
=
Average Shower Water Flow to Be Heated
1,320 gal/hr
WW
=
=
Specific Weight of Water
8.35 lb/gal
Where,
Energy Available in Templifier Output is larger than the Energy Needed per Hour to Heat
Shower Water. The available energy is sufficient for the potential heating requirement. We use
the actual water heat requirement for our calculation. Even though average heat available is
larger than the average water requirement, the smallest heat available during cold days can be
less than the average water requirement. In that case, additional steam heating is required. We
assume 70% of the shower water can be heated by the Templifier and 30% by steam. The
average required Templifier heating capacity is calculated as:
AT
=
=
=
=
Average Templifier Heating Capacity
EN x 70%
0.66 x 106 Btu/hr x 70%
0.46 x 106 Btu/hr
The Templifier input demand can be calculated as:
EI
=
=
=
=
Average Templifier Electrical Input
AT ÷ TP
0.46 x 106 Btu/hr ÷ 4.5
102,800 Btu/hr
OR2000
23
The Templifier’s secondary benefit is pre-cooling the chilled water entering the chiller, reducing
cooling load. Average chiller input demand savings can be calculated as:
CI
=
=
=
=
Average Chiller Input Demand Savings
AT x (TP – 1) ÷ (TP x CO)
0.46 x 106 Btu/hr x (4.5 – 1) ÷ (4.5 x 3.8)
94,700 Btu/hr
CO
=
=
Existing Chiller Part Load COP
3.8
Where,
Thus the net input energy increase from this implementation can be calculated as:
II
=
=
=
=
Increased Input Energy
EI – CI
102,800 Btu/hr – 94,700 Btu/hr
8,100 Btu/hr
Increased Input Energy Cost is calculated as:
CEI
=
=
=
=
Chiller Energy Cost Increase
II x F x OP x IE
8,100 Btu/hr x 1kWh/3,410 Btu x 8,760 hr/yr x $0.045/kWh
$900/yr
F
=
=
Conversion Factor
1 kWh/3,410 Btu
OP
=
=
Operation Hours
8,760 hr/yr
IE
=
=
Incremental Energy Cost
$0.045/kWh
Where,
Energy Savings are calculated as:
ES
=
=
=
=
Energy Savings
AT x OH
0.46 x 106 Btu/hr x 8,760 hr/yr
4,052 x 106 Btu/yr
Steam Cost Savings are calculated as:
OR2000
24
SC
=
=
=
=
Steam Cost Savings
ES x IC
4,052 x 106 Btu/yr x $14.40/106 Btu
$58,300/yr
IC
=
=
=
=
Incremental Energy Cost (Btu)
SC ÷ HF60 x 1,000,000 Btu/106 Btu
$0.0170/lb ÷ 1,180 Btu/lb x 1,000,000 Btu/106 Btu
$14.40/106 Btu
SC
=
=
Steam Cost
$0.0170/lb
HF60
=
=
Latent Heat of Steam at 60 psi
1,180 Btu/lb
Where,
Thus, final cost savings are calculated as:
CS
=
=
=
=
Cost Savings
SC – CEI
$58,300/yr - $900/yr
$57,400/yr
The cost savings equal 21.5% of total steam cost.
The following table summarizes savings found by reducing discharge pressure.
Energy Savings Summary
Source
Chiller Input
Templifier Input
Templifier Output
Savings
Qty
(243,400)
Unit
kWh
$0.045
($11,000)
264,200
4,052
kWh
10 Btu
$0.045
$14.40
$11,900
$58,300
$59,200
6
$/Unit
Cost
Cost Analysis
A vendor estimated the cost of a 140 ton Templifier at $95,000. You also need to install a 2,000
gallon insulated tank to store the hot water (See “Heat Recovery Chiller Piping Schematic”). The
cost is estimated at $5/gal, for a total tank cost of $6,000. Ducting may need to be added or
retrofitted. Ducting material and total installation labor cost is estimated at $3,000. The following
table summarizes implementation costs.
OR2000
25
Implementation Summary
Source
140 ton Templifier
2,000 gal water tank
Ducting and labor
Total
Total Cost
$95,000
$10,000
$3,000
$108,000
Cost savings will pay for implementation in 1.8 years.
Incentive Analysis
You may be eligible for the Oregon Business Energy Tax Credit (BETC). As a public entity your
facility cannot take the full incentive for retrofit projects (35% of the project costs). Instead, you
may take advantage of a “pass-through” option, which allows you to transfer the 35% tax credit
to a pass-through partner in exchange for a lump sum cash payment, equal to 25.5% of project
costs, after applying other incentives. The BETC can reduce implementation costs as follows:
BETC
=
=
=
=
Business Energy Tax Credit
TC x 0.255
$108,000 x 0.255
$27,500
=
=
Total Implementation Cost
$108,000
Where,
TC
The following table summarizes incentives and net costs.
Incentive Summary
Description
Pre-incentive Cost
Business Energy Tax Credit
Total After Incentives
Cost
$108,000
($27,500)
$80,500
After incentives, savings will pay for implementation in 1.4 years.
Notes
We know little about your chiller load profile, thus we cannot make a comprehensive calculation.
This calculation is based on the average load and some assumptions.
Typically a Templifier is installed on a chiller’s condenser water loop. However, as your
condenser is air-cooled, not water-cooled, this would not be possible without installing a new
OR2000
26
water-cooled condenser. We are recommending installation on the chilled water loop, after it has
gained heat from the cooling load.
The Oregon Department of Energy requires written agreement prior to project implementation.
Energy Trust of Oregon incentives are not available because your institution does not pay the
required NW Natural public purpose charge.
OR2000
27
OR2000
28
AR No. 3
Solar Water Heating
Recommended Action
Install solar thermal collectors on the roof of your facility to reduce existing steam pool-heating
requirements. This will reduce pool energy consumption by approximately 30%.
Assessment Recommendation Summary
Energy
Cost
Implementation Payback
106 Btu
1,293
Savings
$18,600
Cost
$87,700
(years)
4.7
Estimated Incentive Summary
BETC1
Net
Net Payback
Tax Credit
Cost
(years)
$29,400
$58,300
3.1
1
Oregon Department of Energy Business Energy Tax Credit
Background
Currently, your facility uses steam-water heat exchangers to heat hot water for two swimming
pools, locker room showers and one spa. The steam is generated off-site via a natural gas steam
boiler and delivered to your facility. You are charged a cost per pound of steam entering the
facility.
The US Department of Energy
states that the most cost effective
use of solar energy is solar pool
heating. Solar heating systems
incorporate the following: solar
collectors transfer sun energy to
the circulated pool water, pump,
filter, check valve and flow
control valve. Solar heating
systems are cost competitive with
other pool heating systems, but
require no ongoing fuel cost to
operate. What’s more, solar water
heating systems typically last
more than twenty years in
operation.
OR2000
Figure 1: Typical solar pool heating system. Image courtesy of the
US Department of Energy.
29
A solar pool heating system is designed to work with existing pool heating configurations. When
the sun shines and solar collector water temperatures exceed the pool water temperature, a valve
automatically diverts water from existing steam heat exchangers to the solar collectors.
Data Collected Summary
During our site visit, we collected the following natatorium general information:
•
•
•
•
•
•
•
•
•
Heat source: OSU Steam Plant
Steam cost: $0.017 per pound of steam (60 psi)
Average ambient (indoor) temperature: 85.5 ºF
Lap pool water temperature: 80.5 ºF
Lap pool surface area: 4,500 sq ft
Lap pool volume: 186,000 gal
Dive pool water temperature: 83.5 ºF
Dive pool surface area: 1,800 sq ft
Dive pool volume: 161,000 gal
Savings Analysis
Savings result by reducing the amount of steam required to heat pool water. A solar water
heating evaluation software tool, RETScreen International1 (RET stands for Renewable Energy
Technology) is used to determine your site’s solar potential, develop installation
recommendations and estimate system cost. Values obtained through the use of RETScreen are
incorporated in the analysis below and noted as such. Additionally, RETScreen worksheets are
included at the end of this recommendation. For simplification, both pools are combined in this
analysis. Pool water temperatures have been conservatively averaged (weighted by volume) and
pool surface areas are combined.
Energy savings are taken directly from the RETScreen analysis. Using historical National
Aeronautics and Space Administration (NASA) weather data for your geographic region and
swimming pool data specific to your facility, RETScreen estimates months of solar water heating
possible for your facility. The tool then estimates the energy offset potential by using solar
collectors based on collector efficiency and collector area. As a general industry rule, the solar
collector area usually equals the surface area of the heated pool. More collector capacity may be
added, increasing implementation costs and annual savings.
ES
=
=
Energy Savings
1,293 x 106 Btu/yr (RETScreen)
Energy cost savings are calculated by multiplying Energy Savings offset by solar energy by
Incremental Energy Cost (steam cost).
1
RETScreen International can be downloaded for no charge through the US Department of Energy – Energy
Efficiency and Renewable Energy website under solar water heating, or at www.retscreen.net/ .
OR2000
30
EC
=
=
=
=
Energy Cost Savings
ES x IC
1,293 x 106 Btu/yr x $14.40/106 Btu
$18,600/yr
IC
=
=
=
=
Incremental Energy Cost (Btu)
SC ÷ h60 x 1,000,000 Btu/106 Btu
$0.0170/lb ÷ 1,180 Btu/lb x 1,000,000 Btu/106 Btu
$14.40/106 Btu
SC
=
=
Steam Cost
$0.0170/lb
h60
=
=
Enthalpy of Steam at 60 psi
1,180 Btu/lb
Where,
Where,
Incidentally, RETScreen estimates the total annual pool heating demand at 3,760 x 106 Btu,
which results in annual pool heating costs of approximately $54,000 using the above calculated
Incremental Energy Cost.
Cost Analysis
RETScreen also estimates this recommendation’s implementation costs (before incentives),
summarized in the following table.
Implementation Summary
Source
Quantity Units
Solar Collector
588
m2
Piping Materials
70
m
Collector Support Structure
588
m2
Plumbing and Control
1 Project
Collector Installation
588
m2
Solar Loop Installation
70
m
Training
4 hours
Contingencies
10
%
Total
$/Unit
$60.00
$6.00
$50.00
$300
$20
$30
$60
$79,700
Cost
$35,280
$420
$29,400
$500
$11,760
$2,100
$240
$7,970
$87,700
Note the following with respect to the above tabulated values:
•
•
•
OR2000
RETScreen uses metric units:
1 m = 3.28 ft
1 m2 = 10.76 ft2
Collector area (588 m2) equals the combined pool surface area (6,300 ft2)
Collector Support Structure: This calculation assumes the collectors will be mounted
on a flat roof. Your facility has adequate flat roof space for collector installation.
31
•
•
•
•
•
Piping Materials refers to piping, pipe supports, fittings, insulation and jacket
Plumbing and Control refers to the interconnection plumbing between the solar loop,
pump, heat exchanger and pool.
Installation: Unit values assume that most of the collector installation can be
performed at a non-specialized hourly rate.
Training: Facility personnel will require a few hours of system training by a solar
water heating expert.
We assume no changes are required of the existing water pump system: i.e. the
existing heat exchanger pumps will serve the solar collector system and there is no
anticipated increase in pump energy.
Cost savings will pay for implementation in 4.7 years.
Incentive Analysis
You may be eligible for the Oregon Business Energy Tax Credit (BETC) if the project reduces
system energy use by at least 10% (as written, system energy use should be reduced by 30%). As
a public entity your facility cannot take the full incentive for renewable resource projects (50%
of project cost). Instead, you may take advantage of a “pass-through” option, which allows you
to transfer the 50% tax credit to a pass-through partner in exchange for a lump sum cash
payment, equal to 33.5% of project costs, after applying other incentives. (Renewable resource
tax credit details are still being finalized by the Oregon Department of Energy as of this writing).
The BETC will reduce implementation costs as follows:
BETC
=
=
=
=
Business Energy Tax Credit
TC x 0.335
$87,670 x 0.335
$29,400
=
=
Total Implementation Cost
$87,700
Where,
TC
The following table summarizes implementation costs before and after incentives.
Incentive Summary
Description
Pre-incentive Cost
Business Energy Tax Credit
Total after Incentives
Cost
$87,700
($29,400)
$58,300
After incentives, savings will pay for implementation in 3.1 years.
The Oregon Department of Energy also operates an Energy Loan Program to promote energy
conservation and renewable energy projects. Low interest rates (4.9-5.3%) would allow you to
OR2000
32
pay back the $58,300 implementation cost (plus interest) in 3.5 years, using associated energy
cost savings.
Notes
The Oregon Department of Energy requires written agreement prior to project implementation.
Energy Trust of Oregon incentives are not available because your institution does not pay the
required NW Natural public purpose charge.
Additional savings associated with adding greater collector capacity tends to balance the added
implementation costs and payback remains about the same.
We recommend you engage a solar water heating company to perform a professional feasibility
study of your facility. We do not include this cost in our payback analysis.
OR2000
33
RETScreen® Energy Model - Solar Water Heating Project
Site Conditions
Project name
Project location
Nearest location for weather data
Annual solar radiation (tilted surface)
Annual average temperature
Annual average wind speed
Desired load temperature
Hot water use
Number of months analysed
Energy demand for months analysed
System Characteristics
Application type
Base Case Water Heating System
Heating fuel type
Water heating system seasonal efficiency
Solar Collector
Collector type
Solar water heating collector manufacturer
Solar water heating collector model
Gross area of one collector
Aperture area of one collector
Fr (tau alpha) coefficient
Wind correction for Fr (tau alpha)
Fr UL coefficient
Wind correction for Fr UL
Temperature coefficient for Fr UL
Suggested number of collectors
Number of collectors
Total gross collector area
Storage
Ratio of storage capacity to coll. area
Storage capacity
Balance of System
Heat exchanger/antifreeze protection
Heat exchanger effectiveness
Suggested pipe diameter
Pipe diameter
Pumping power per collector area
Piping and solar tank losses
Losses due to snow and/or dirt
Horz. dist. from mech. room to collector
# of floors from mech. room to collector
Training & Support
Estimate
Dixon Rec. Center
Corvallis, Oregon
Eugene, OR
1.36
11.3
3.4
28
N/A
12.00
1,102.16
MWh/m²
°C
m/s
°C
L/d
month
MWh
Estimate
Swimming pool (indoor)
Notes/Range
See Online Manual
Complete SR&HL sheet
-20.0 to 30.0
Notes/Range
%
Natural gas - mmBtu
80%
-
See Technical Note 1
See Product Database
m²
Evacuated
ABC S.A.
model XYZ
4.00
4.00
0.85
0.000
11.56
0.00
0.00
147
147
588.0
L/m²
L
45.9
26,989
37.5 to 100.0
yes/no
%
mm
mm
W/m²
%
%
m
-
Yes
80%
31
38
0
1%
3%
20
3
m²
m²
s/m
(W/m²)/°C
(J/m³)/°C
(W/(m?°C)²)
Annual Energy Production (12.00 months analysed)
kW th
SWH system capacity
million Btu/h
Pumping energy (electricity)
MWh
Specific yield
kWh/m²
System efficiency
%
Solar fraction
%
Renewable energy delivered
MWh
million Btu
Estimate
412
1.404
0.00
645
47%
34%
379.00
1,293.21
50% to 190%
1.00 to 5.00
1.00 to 5.00
0.40 to 0.80
0.030 to 0.050
0.30 to 3.00
3.00 to 15.00
0.000 to 0.010
50% to 85%
8 to 25 or PVC 35 to 50
8 to 25 or PVC 35 to 50
3 to 22, or 0
1% to 10%
2% to 10%
5 to 20
0 to 20
Notes/Range
Complete Cost Analysis sheet
34
RETScreen® Solar Resource and Heating Load Calculation - Solar Water Heating Project
Site Latitude and Collector Orientation
Nearest location for weather data
Latitude of project location
Slope of solar collector
Azimuth of solar collector
°N
°
°
Estimate
Eugene, OR
44.1
0.0
0.0
Notes/Range
See Weather Database
-90.0 to 90.0
0.0 to 90.0
0.0 to 180.0
Monthly Inputs
(Note: 1. Cells in grey are not used for energy calculations; 2. Revisit this table to check that all required inputs are filled if you change system type
or solar collector type or pool type, or method for calculating cold water temperature).
Month
January
February
March
April
May
June
July
August
September
October
November
December
Fraction
Monthly
of
average
month daily radiation
used
on horizontal
surface
(0 - 1)
(kWh/m²/d)
1.00
1.27
1.00
1.97
1.00
3.14
1.00
4.39
1.00
5.55
1.00
6.21
1.00
6.73
1.00
5.83
1.00
4.42
1.00
2.70
1.00
1.42
1.00
1.05
Solar radiation (horizontal)
Solar radiation (tilted surface)
Average temperature
Average wind speed
Water Heating Load Calculation
Application type
System configuration
Building or load type
Building or load type
Number of units
Rate of occupancy
Estimated hot water use (at ~6
Hot water use
Desired water temperature
Days per week system is used
Type of pool
Pool area
Use of cover
Desired pool temperature
Makeup water ratio
Wind sheltering coefficient
Pool shading factor
Cold water temperature
Minimum
Maximum
Months SWH system in use
Energy demand for months analy
Monthly
average
temperature
(°C)
4.4
6.1
7.9
9.8
12.9
16.5
19.3
19.3
16.3
11.5
7.4
4.7
Monthly
average
relative
humidity
(%)
86.9
84.8
79.8
75.7
73.0
69.0
62.4
64.1
69.0
80.8
87.5
88.8
MWh/m²
MWh/m²
°C
m/s
Annual
1.36
1.36
11.3
3.4
Season of Use
1.36
1.36
11.3
3.4
%
L/d
L/d
°C
d
2
m
h/d
°C
%/wk
%
°C
°C
month
MWh
million Btu
Estimate
Swimming pool
With storage
Industrial
Industrial
N/A
12,000
60
7
Indoor
585
0
27.8
5%
Auto
8.9
14.1
12.00
1,102.16
3,760.57
Monthly
Monthly
average
average
daily radiation
wind speed
in plane of
solar collector
(m/s)
(kWh/m²/d)
3.5
1.27
3.5
1.97
3.7
3.14
3.5
4.39
3.4
5.55
3.4
6.21
3.6
6.73
3.4
5.83
3.4
4.42
3.0
2.70
3.4
1.42
3.5
1.05
Notes/Range
50% to 100%
1 to 7
20 to 1,000
0 to 24
22 to 35
5% to 10%
0.10 to 0.30
0% to 50%
1.0 to 10.0
5.0 to 15.0
Return to Energy Model sheet
35
RETScreen® Cost Analysis - Solar Water Heating Project
Type of project: Pre-feasibility
Initial Costs (Credits)
Feasibility Study
Site investigation
Preliminary design
Report preparation
Travel and accommodation
Other - Feasibility study
Sub-total :
Development
Permits and approvals
Project financing
Project management
Travel and accommodation
Other - Development
Sub-total :
Engineering
SWH system design
Structural design
Tenders and contracting
Construction supervision
Other - Engineering
Sub-total :
Energy Equipment
Solar collector
Solar storage tank
Solar loop piping materials
Circulating pump(s)
Heat exchanger
Transportation
Other - Energy equipment
Sub-total :
Balance of System
Collector support structure
Plumbing and control
Collector installation
Solar loop installation
Auxiliary equipment installation
Transportation
Other - Balance of system
Sub-total :
Miscellaneous
Training
Contingencies
Sub-total :
Initial Costs - Total
Annual Costs (Credits)
O&M
Property taxes/Insurance
O&M labour
Other - O&M
Contingencies
Sub-total :
Electricity
Annual Costs - Total
Periodic Costs (Credits)
Valves and fittings
Pool heat pump compressor
End of project life
Unit
Quantity
p-h
p-h
p-h
p-trip
Cost
2
0
0
0
0
p-h
p-h
p-h
p-trip
Cost
p-h
p-h
p-h
p-h
Cost
m²
L
m
W
kW
project
Cost
Credit
2
0
0
0
0
6
1
0
0
0
588.0
0
70
0
352.8
0
0
0
Currency:
Second currency:
Unit Cost
USD
USD
USD
USD
USD
40
-
USD
USD
USD
USD
USD
40
-
USD
USD
USD
USD
USD
40
40
-
USD
USD
USD
USD
USD
USD
USD
USD
60
6.00
-
USA
USA
Amount
USD
USD
USD
USD
USD
80
-
USD
-
USD
USD
USD
USD
USD
80
-
USD
-
USD
USD
USD
USD
USD
240
40
-
USD
-
588.0
1
588.0
70
1
1
0
USD
USD
USD
USD
USD
USD
USD
50
500
20
30.00
-
p-h
%
4
10%
USD
USD
60
79,699
USD
USD
240
7,970
USD
8,210
USD 87,668
Unit
Quantity
project
project
Cost
%
0
1
0
10%
USD
USD
USD
USD
15
15
USD
USD
USD
USD
15
2
kWh
0
USD
-
USD
USD
17
-
USD
17
Cost
Credit
Period
10 yr
10 yr
Unit Cost
Unit Cost
USD
USD
250
1,200
-
36
Amount
Amount
USD
250
USD (1,200)
USD
USD
-
-
-
-
-
-
-
-
-
-
-
-
0.0%
0.0%
40.7%
USD 29,400
USD
500
USD 11,760
USD 2,099
USD
USD
USD
USD 43,759
0.0%
USD 35,280
USD
USD
420
USD
USD
USD
USD
USD
USD 35,700
m²
project
m²
m
project
project
Cost
USD
Cost references:
None
USD
Rate: USD/USD
1.47730
Relative Costs Quantity Range Unit Cost Range
49.9%
9.4%
100.0%
Relative Costs Quantity Range Unit Cost Range
100.0%
0.0%
100.0%
-
-
-
-
Interval Range
-
Unit Cost Range
-
Go to GHG Analysis sheet
AR No. 4
Towel Monitoring
Recommended Action
Monitor towel usage from the equipment checkout desk and assess a fee for all towels not
returned by the end of each day. The number of towels removed from the facility should
decrease, and fees will pay for at least the replacement of lost towels.
Assessment Recommendation Summary
Cost
Implementation
Payback
Savings
Cost
(years)
$4,235
$42
0
Background
You currently offer a complimentary towel service to patrons of your facility. Unfortunately,
according to facility personnel, patrons are removing towels at an estimated rate of 50 percent
(420 towels) per school quarter. These missing towels must be replaced, leading to significant
ongoing replacement costs.
Data Collected Summary
During our site visit we collected the following information:
•
•
•
•
Full towel inventory: 70 dozen towels
Towels removed per quarter: 50 percent (35 dozen)
Towels needing replacement due to normal wear per quarter: 10 percent (7 dozen)
Towel cost: $28.50 per dozen
With only half of the original inventory left after towel removal, the seven dozen towels
discarded due to normal wear and tear actually represent 20 percent of the inventory at the end of
each term.
Savings Analysis
Savings result by reducing the number of towels removed by patrons, as follows:
CC
Where,
TRT
OR02000
=
=
=
=
Current Cost
(TRT + TWT) x CT x T
(35 + 7) dozen/term x $28.50/dozen x 4 terms/yr
$4,790/yr
=
=
Towels Removed per Term
35 dozen/term
37
TWT
=
=
Worn Towels per Term
7 dozen
CT
=
=
Cost of Towels
$28.50/dozen
T
=
=
Terms
4 terms/yr
Posting signs advising patrons of the new towel return policy, in addition to actually charging
patrons for unreturned towels should reduce the towel removal rate. We assume it will drop from
50 percent to an estimated 10 percent. (We recommend presenting the fee as an effort to use
student fees to support the Recreation Center more wisely).
PTR
=
=
=
=
Proposed Towels Removed per Term
I x 10%
70 dozen x 10%
7 dozen/term (336 towels annually)
=
=
Total Towel Inventory
70 dozen
Where,
I
This will increase the number of towels that are replaced due to wear and tear every term
because towels will remain in inventory longer. The total number of proposed towels discarded
due to wear and tear is estimated as:
PTW
=
=
=
=
Proposed Towels Worn per Term
PD x PR x I
20% x 90% x 70 dozen
12.6 dozen/term
PD
=
=
Percent of Towels Discarded Due to Wear and Tear
20%
PR
=
=
=
Percent Reduction After 10% Removal
100% - 10%
90%
Where,
The total proposed cost to replace towels is calculated as:
PTC
OR02000
=
=
=
=
Proposed Total Cost to Replace Towels
(PTR + PTW) x CT x T
(7 + 12.6) dozen/term x $28.5/dozen x 4 terms/yr
$2,235/year
38
Total savings are a function of the fee amount imposed per removed towel. Total savings can be
calculated as follows:
TS
Where,
FPT
=
=
=
=
Total Savings
CC – PTC – (FPT x PTR x T x 12/dozen)
$4,790 - $2,235 – (FPT x 7 dozen/term x 4 terms x 12/dozen)
$2,555 + (FPT x 336 towels per year)
=
Fee per Towel
The following table lists possible fee values and the associated annual savings. The chart gives a
graphical representation of fee amounts and the resulting savings.
Fee
Money From Fees
Annual Cost to Provide Towel service
Annual Savings
$2.40
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
$5.50
$806
$840
$1,008
$1,176
$1,344
$1,512
$1,680
$1,848
$1,428
$1,395
$1,227
$1,059
$891
$723
$555
$387
$3,361
$3,395
$3,563
$3,731
$3,899
$4,067
$4,235
$4,403
$6.00
$2,016
$219
$4,571
Note the $2.40 value on the table above, which is the actual cost to replace one towel. This is the
minimum fee amount we recommend imposing. It is also possible to use fee money to support
the administrative costs associated with replacing towels. For this recommendation we use the
$5.00 fee in our savings calculations.
OR02000
39
Existing
Proposed
Savings
Savings Summary
Worn
Removed Towel
Towels
Towels
Cost
336
1,680
$4,788
605
336
$2,234
(269)
1,344
$2,554
Fees
0
$1,680
$1,680
Total
Cost
$4,788
$554
$4,234
Cost Analysis
Implementation costs include updating the equipment desk checkout program and publicizing the
new fee program for unreturned towels. Updating the program should take no longer than
several minutes for experienced employees. We estimate one hour of technical support to
accommodate this transition. Also, a printed flier and/or sign at the check station advertising the
change may be required.
Implementation Summary
Source
Quantity Cost Total
Tech Support
1 hour
$30
$30
Flier design
10 hours
$10 $100
Flier Prints
20 prints $0.25
$5
Permanent Sign
1 print
$100 $100
Total
$235
Savings pay for implementation almost immediately.
OR02000
40
AR No. 5
Tennis Pavilion Lighting
Recommendation
Replace metal halide fixtures in the Tennis Pavilion with six-lamp T5 high output (HO) fixtures,
including integrated motion sensors. This will allow lights to only be turned on when the tennis
courts are being used, reducing lighting operating costs by 70% in that area.
Assessment Recommendation Summary
Electrical
Cost
Implementation Payback
Energy (kWh)
67,200
Savings
$4,040
Cost
$13,500
(years)
3.3
Estimated Incentive Summary
ETO
BETC2
Net
Net Payback
Incentive
Tax Credit
Cost
(years)
$3,400
$3,100
$7,000
1.8
1
1
2
Energy Trust of Oregon Incentive
Oregon Department of Energy Business Energy Tax Credit
Background
The Tennis Pavilion currently uses metal halides to meet most lighting needs. Though these high
intensity discharge (HID) lamps are a dependable, compact and powerful point light source, they
experience considerable efficacy deterioration after only 40% of service life. They also have
considerable startup and re-strike times, which is not suitable for motion sensor installation. This
leads to energy waste in spaces with low levels of activity, as lights remain on unnecessarily.
T5 fluorescent lamps offer several advantages over HID lamps, including: higher
efficiency/energy savings, less efficacy deterioration throughout their service life, better color
rendition, quicker startup and re-strike time, longer lamp life and more even light distribution
due to linear light sources. Because of quick re-strike time, fluorescent lights are ideal for
motion sensor installation. Some fluorescent fixtures come equipped with integrated motion
sensors, allowing even more accurate lighting control.
T5 high output fixtures with four or six lamps can replace most 400 watt HID lamps on a one for
one basis, limiting the number of fixtures that need to be installed and avoiding a cluttered look.
Data Collected Summary
During our assessment we identified forty-eight 400 watt metal halide fixtures in the Tennis
Pavilion.
OR2000
41
Based on conversations with facility personnel and from personal and anecdotal experience, we
estimate:
•
•
•
Current annual operating hours: 4,200 hours
Proposed annual operating hours: 1,400 hours
Electrical energy cost: $0.045/kWh
Savings Analysis
Savings come from the reduced power draw of the T5 fixtures, as well as a reduction of
operating hours. Power savings are calculated as the difference between current and proposed
conditions:
CP
=
=
=
=
Current Power Use
NF x FW
48 fixtures x 458 watts/fixture
22 kW
NF
=
=
Number of Fixtures
48 fixtures
FW
=
=
Fixture Input Wattage
458 watts/fixture
Where,
Proposed power use is calculated as:
PP
=
=
=
=
Proposed Power
NF x PW
48 fixtures x 370 watts/fixture
18 kW
PW
=
=
Proposed Input Wattage
370 watts/fixture
Where,
Energy savings associated with reduced operating hours are calculated as:
OR2000
CE
=
=
=
=
Current Energy Use
CP x CH
22 kW x 4,200 hrs/yr
92,400 kWh/yr
PE
=
=
=
=
Proposed Energy Use
PP x PH
18 kW x 1,400 hrs/yr
25,200 kWh/yr
42
Where,
CH
=
=
Current Operating Hours
4,200 hrs/yr
PH
=
=
Proposed Operating Hours
1,400 hrs/yr
Energy savings are calculated as:
ES
=
=
=
Energy Savings
92,400 kWh/yr – 25,200 kWh/yr
67,200 kWh/yr
Cost savings are calculated as:
CS
=
=
=
=
Annual Cost Savings
ES x IC
67,200 kWh/yr x $0.045/kWh
$3,000/yr
IC
=
=
Incremental Energy Cost
$0.045/kWh
Where,
Installing fluorescent fixtures with integrated motion sensors will also lead to a decrease in
fixture maintenance costs by extending the life of lamps and ballasts through reduced operating
hours. For the Tennis Pavilion, annual material and labor savings are $990 and $50 respectively,
totaling $1,040. Lighting worksheets at the end of the Lighting Appendix B are used to obtain
these savings. Savings are summarized in the table below.
Savings Summary
Source
Energy
Maintenance Labor
Maintenance Materials
Total
Quantity Units
67,200 kWh
Energy
(106 Btu)
230
230
Savings
$3,000
$50
$990
$4,000
Cost Analysis
Implementation costs for new fixtures consist of material and installation costs. We
conservatively estimate costs at one hour per fixture installation, and $50 per hour for a typical
electrician’s wage.
OR2000
43
Fixture costs are calculated as:
CF
=
=
=
=
Cost of Fixtures
NF × CF
48 fixtures × $231/fixture
$11,100
CF
= Cost per Fixture
= $231/fixture
Where,
Labor costs associated with installation are calculated as:
IC
=
=
=
=
Installation Cost
NF x IT x EW
48 fixtures x 1 hr/fixture x $50/hr
$2,400
IT
= Installation Time
= 1 hr/fixture
EW
= Electrician Wage
= $50/hr
Where,
Source
Implementation Summary
Quantity
Units
T5 High Output Fixtures with
Integrated Motion Sensors
Electrician Labor
Total
$/Unit
48 Fixtures
48
Hours
Cost
$231
$11,100
$50
$2,400
$13,500
Savings will pay for implementation in approximately 3.3 years.
Incentive Analysis
Energy Trust of Oregon custom cash incentives are available to help pay for lighting
implementation costs. Incentives will pay up to 25% of project costs, not exceeding $0.12 per
kWh saved.
ETO
OR2000
=
=
=
=
=
Energy Trust of Oregon Cash Incentive
Minimum of
ES x $0.12/kWh
Minimum of
67,200 kWh x $0.12/kWh
Minimum of
$8,100
$3,400
44
or
or
or
0.25 x TC
0.25 x $13,500
$3,400
Where,
TC
=
=
Total Implementation Cost
$13,500
You may also be eligible for the Oregon Business Energy Tax Credit (BETC) if a lighting
retrofit project is 25% more efficient than the existing system (as written, this recommendation
reduces localized energy consumption by 70%). As a public entity your facility cannot take the
full incentive for retrofit lighting projects (35% of the project costs). Instead, you may take
advantage of a “pass-through” option, which allows you to transfer the 35% tax credit to a passthrough partner in exchange for a lump sum cash payment, equal to 30.5% of project costs, after
applying other incentives. This rate is specific to retrofit projects with total costs of $20,000 or
less. For such projects, the tax credit may be applied over one year, rather than the standard five
years. The BETC will further reduce implementation costs as follows:
BETC
=
=
=
=
Business Energy Tax Credit
(TC – ETO) x 0.305
($13,500 – $3,400) x 0.305
$3,100
The following table summarizes incentives and net costs.
Incentive Summary
Description
Pre-incentive Cost
Energy Trust Incentives
Business Energy Tax Credit
Total After Incentives
Cost
$13,500
($3,400)
($3,100)
$7,000
After incentives, savings will pay for implementation in 1.8 years.
Notes
The Energy Trust of Oregon and the Oregon Department of Energy require written agreement
prior to project implementation.
OR2000
45
AR No. 6
Day-Lighting
Recommended Action
Install photo sensors near windows, skylights and in the Recreation Center to reduce localized
light operating hours during daylight hours. This will reduce lighting energy costs by over 30%.
Assessment Recommendation Summary
Electrical
Cost
Implementation Payback
Energy (kWh)
15,400
Savings
$1,300
Cost
$3,500
(years)
2.7
Estimated Incentive Summary
ETO
BETC2
Net
Net Payback
Incentive
Tax Credit
Cost
(years)
$875
$800
$1,800
1.4
1
1
2
Energy Trust of Oregon Incentive
Oregon Department of Energy Business Energy Tax Credit
Background
You currently have skylights and large windows installed throughout your facility. This is a
good practice as it allows a large amount of natural light, which most people prefer over artificial
light, and reduces the need for artificial lights. However, many lights around windows and
skylights remain on when daylight provides more than enough light to meet localized lighting
needs.
Photo sensors monitor light levels and can be used in lighting control systems to turn lights on
and off depending on the amount of light being obtained from other sources. Installing photo
sensors in areas where natural light is prevalent allows artificial lights to be turned off.
Data Collected Summary
During our site visit, we collected the following lighting inventory with respect to lights near
windows and skylights:
OR2000
46
Area
Stevens Natatorium
West Lobby
West Vestibule Entrance
Main West Hallway
East Vestibule Entrance
East Lobby
East Entrance
2nd Story West Hallway
2nd Story West Hallway
Lighting Inventory
Fixture
Number Watts/Fixture Hours
4 ft T8 Electric Ballast
45
34
5,600
2 Lamp CFL
15
84
5,600
42 watt CFL
4
42
5,600
42 watt CFL
17
42
5,600
42 watt CFL
4
42
5,600
42 watt CFL
6
42
5,600
42 watt CFL
5
42
5,600
42 watt CFL
30
42
5,600
4 ft T8 Electric Ballast
10
34
5,600
We make the following assumptions in our calculations:
•
Lights around skylights and windows can be turned off during the best 2,600 annual
hours of sunlight. This is a conservative estimate, as there are over 4,000 annual sunlight
hours.
New photo sensors can be wired into the existing lighting control system for minimal
cost.
•
Savings Analysis
Energy savings are calculated as the associated cost difference between current and proposed
conditions. Stevens Natatorium is taken as an example. Current power consumption is
calculated as:
CP
=
=
=
=
Current Power
CF × CW
45 fixtures × 34 watts/fixture
1.53 kW
CF
=
=
Current Number of Four Foot T8 Fixtures
45 fixtures
CW
=
=
Current Fixture Input Wattage
34 watts/fixture
Where,
Energy savings due to reduced operating hours are calculated as:
ES
OR2000
=
=
=
=
Energy Savings
CP × (CH – PH)
1.53 kW × (5,600 hrs/yr – 3,000 hrs/yr)
4,000 kWh/yr
47
Where,
CH
=
=
Current Operating Hours
5,600 hrs/yr
PH
=
=
Proposed Operating Hours
3,000 hrs/yr
Cost savings are calculated as:
CS
=
=
=
=
Cost Savings
ES x EC
4,000 kWh/yr × $0.045/kWh
$180/yr
EC
=
=
Incremental Energy Cost
$0.045 /kWh
Where,
Implementation of this recommendation will also decrease material and labor costs associated
with the replacement of lamps and ballasts. As estimated in the Lighting Inventory spreadsheet
in the Lighting Appendix (Appendix B) at the end of this report, annual lighting material and
maintenance labor savings total approximately $70 and $50 respectively. Therefore, total
maintenance savings sum to approximately $120 per year for Stevens Natatorium.
Savings for all locations are summarized in the following table. For a breakdown of savings from
individual areas, see the lighting worksheet at the end of the Lighting Appendix B.
Savings Summary
Energy
Source
Energy
Maintenance Labor
Maintenance Materials
Total
Quantity Units
15,350 kWh
(106 Btu)
50
50
Savings
$680
$130
$510
$1,300
Cost Analysis
Implementation costs for photo sensors include materials and installation. Labor costs are
conservatively estimated at two hours per sensor installation with a typical electrician’s wage of
$50 per hour.
Material costs for photo sensors in Stevens Natatorium are calculated as an example below.
OR2000
48
CS
=
=
=
=
Material Cost of Sensors
(NS × CPS) + (NCU × CPC)
(2 sensors × $150/sensor) + (1 controller × $50/controller)
$350
NS
=
=
Number of Sensors
2 sensors
CPS
=
=
Cost per Sensor
$150/sensor
NCU
=
=
Number of Control Units
1 controller
CPC
=
=
Cost per Controller Unit
$50/controller
Where,
Labor costs associated with installation are calculated as:
CTI
=
=
=
=
Cost to Install
(NS + NCU) × IT × EW
(2 sensors + 1 controller) × 2 hr/sensor × $50/hr
$300
IT
=
=
Installation Time
2 hrs/sensor
EW
=
=
Electrician Wage
$50/hr
Where,
Total implementation cost for the Stevens Natatorium is calculated as:
TI
=
=
=
=
Total Implementation Cost
CS + CTI
$350 + $300
$650
Calculations for other areas mentioned in this report follow the same methodology.
After the photo sensors are installed, controls will need to be integrated into the master lighting
control system to allow for more accurate lighting management. We estimate this will cost
$1,000.
The following table summarizes implementation costs for all areas listed in the Data Collected
Summary section.
OR2000
49
Implementation Summary
Source
Quantity Units
$/Unit Cost
Photo Sensors
10 Sensors
$150 $1,500
Electrician Labor
20 Hours
$50 $1,000
Lighting Control System Upgrade
$1,000
$3,500
Total
Savings will pay for implementation in approximately 2.7 years.
Incentive Analysis
Energy Trust of Oregon custom cash incentives are available to help pay for lighting
implementation costs. Incentives will pay up to 25% of project costs, not exceeding $0.12 per
kWh saved.
ETO
=
=
=
=
=
Energy Trust of Oregon Cash Incentive
Minimum of
ES x $0.12/kWh
Minimum of
15,350 kWh x $0.12/kWh
Minimum of
$1,800
$875
=
=
Total Implementation Cost
$3,500
or
or
or
0.25 x TC
0.25 x $3,500
$875
Where,
TC
You may also be eligible for the Oregon Business Energy Tax Credit (BETC) if a lighting
retrofit project is 25% more efficient than the existing system (as written, this recommendation
reduces lighting energy consumption by over 30%). As a public entity your facility cannot take
the full incentive for retrofit lighting projects (35% of the project costs). Instead, you may take
advantage of a “pass-through” option, which allows you to transfer the 35% tax credit to a passthrough partner in exchange for a lump sum cash payment, equal to 30.5% of project costs, after
applying other incentives. This rate is specific to retrofit projects with total costs of $20,000 or
less. For such projects, the tax credit may be applied over one year, rather than the standard five
years. The BETC will further reduce implementation costs as follows:
BETC
=
=
=
=
Business Energy Tax Credit
(TC – ETO) x 0.305
($3,500 – $875) x 0.305
$800
The following table summarizes incentives and net costs.
OR2000
50
Incentive Summary
Description
Pre-incentive Cost
Energy Trust Incentives
Business Energy Tax Credit
Total After Incentives
Cost
$3,500
($875)
($800)
$1,800
After incentives, savings will pay for implementation in 1.4 years.
Note
The Energy Trust of Oregon and the Oregon Department of Energy require written agreement
prior to project implementation.
OR2000
51
AR No. 7
Racquetball Lighting
Recommended Action
Replace T12 ballasts and lamps with T8 ballasts and lamps in the racquetball and squash courts.
This will reduce energy use in these areas, and help you simplify your lighting inventory, as
these courts are some of the last areas still utilizing T12 lamps.
Assessment Recommendation Summary
Electrical
Cost
Implementation Payback
Energy (kWh)
9,315
Savings
$540
Cost
$7,200
(years)
13.3
Estimated Incentive Summary
ETO
BETC2
Net
Net Payback
Incentive
Tax Credit
Cost
(years)
$3,800
$1,000
$2,400
4.4
1
1
2
Energy Trust of Oregon Incentive
Oregon Department of Energy Business Energy Tax Credit (pass-through option)
Background
There are multiple sizes of fluorescent lamps distinguished by a T followed by a number. T12,
T8 and T5 are common examples. The number that follows the T signifies lamp thickness in
eighths of an inch, representing the diameter of the fluorescent tube. A T12 is 12/8 inch, or one
and a half inches, thick, while a T8 is 8/8, or one, inch thick. The narrower the fluorescent tube,
the less energy is needed to excite the gas contents of the tube to produce light.
A ballast supplies electricity to fluorescent lamps. Some ballast types, such as programmed start
ballasts, are specifically designed for motion sensor operation. Motion sensors are beneficial
because they can decrease lighting energy use and increase lamp life.
You currently use T12 fluorescent fixtures with motion sensors in the racquetball and squash
courts. These fixtures have magnetic ballasts, which are not very efficient. T8 lamps with
electric ballasts decrease energy use and increase bulb life, while maintaining the same lighting
level and quality.
Data Collected Summary
During our visit, we collected a partial lighting inventory. We also received an estimate of
annual operating hours for each racquetball and squash room. This data is summarized below:
•
•
OR2000
Number of racquetball courts: 7 courts
Number of squash courts: 2 courts
52
•
•
•
Number of two lamp four foot T12 fixtures per court: 21 fixtures
Average annual operating hours per court: 1,700 hours
Electrical energy rate: $0.045/kWh
Savings Analysis
Savings are a result of the reduced energy used by T8 lamps, as well as increased bulb life
associated with programmed start ballasts. Energy savings are calculated per court. Current
power is calculated as:
CP
Where,
CW
NF
=
=
=
=
Current Power
CW x NF
87 watts/fixture x 21 fixtures
1.827 kW
=
=
Current Input Wattage
87 watts/fixture
=
=
Number of Fixtures
21 fixtures
Proposed power is calculated as:
PP
=
=
=
=
Proposed Power
PW x NF
58 watts/fixture x 21 fixtures
1.218 kW
PW
=
=
Proposed Input Wattage
58 watts/fixture
Where,
Energy savings are calculated as:
ES
=
=
=
=
Energy Savings per Court
(CP – PP) x OH
(1.827 kW – 1.218 kW) x 1,700 hrs/yr
1,035 kWh/yr
OH
=
=
Operating Hours
1,700 hrs/yr
Where,
Total energy savings for all nine courts is therefore 9,315 kWh per year.
OR2000
53
Energy cost savings are calculated as:
EC
=
=
=
=
Energy Cost Savings per Court
ES x IC
1,035 kWh/yr x $0.045/kWh
$50/yr
IC
=
=
Incremental Energy Charge
$0.045/kWh
Where,
New ballasts will also increase lamp life, decreasing lamp replacement costs. Also, because of
the high quantity of T8 lamps that you currently use, the cost of lamps will also decrease. We
assume that you will save approximately $10 annually in lamp replacement costs per court.
The following table summarizes the savings for one court:
Savings Summary
Energy
Source
Quantity Units
Energy
1,035 kWh
Lamp Replacement Savings
Total per Court
Total For All Courts
(106 Btu)
4
4
Savings
$50
$10
$60
$540
Cost Analysis
Implementation costs for this recommendation consist of the cost for new ballasts, new lamps,
and labor.
We use the following cost information to perform our implementation cost estimate.
•
•
Programmed start T8 ballasts cost approximately $25 each.
New four foot T8 lamps cost on average $1.80 each.
Installation material costs per court are:
IM
OR2000
=
=
=
=
=
Installation Material Costs
BC x NB + LC x NL
$25/ballast x 21 ballasts + $1.80/lamp x 42 lamps
$525 + $75
$600
54
Where,
BC
=
=
Ballast Cost
$25/ballast
NB
=
=
Number of Ballasts Needed per Room
21 ballasts
LC
=
=
Lamp Cost
$1.80/lamp
NL
=
=
Number of Lamps Needed Per Room
42 lamps
We assume that facility personnel can perform the installation during normal operating hours at a
wage of $20 per hour and 30 minutes per ballast. Installation costs are calculated as:
IC
=
=
=
=
Installation Cost
NB x IT x IW
21 ballasts x 0.5 hrs x $20/hr
$210
IT
=
=
Installation Time
0.5 hrs
IW
=
=
Maintenance Wage
$20/hr
Where,
Implementation Summary per Court
Source
Quantity Units $/Unit
T8 Programmed Start Ballasts
21 Ballast $25.00
Four foot T8 Lamps
42 Lamp
$1.80
Maintenance Labor
10 Hour
$20.00
Total per Court
Cost
$525
$75
$200
$800
Total For All Courts
$7,200
Savings will pay for implementation in approximately 13.3 years.
Incentive Analysis
Energy Trust of Oregon offers cash incentives for energy efficient lighting improvements.
Replacing T12 fixtures with T8 fixtures results in a $20 per fixture incentive, calculated as:
OR2000
55
ETO
=
=
=
Energy Trust of Oregon Cash Incentive
$20/fixture x 21 fixtures/court x 9 courts
$3,800
You may also be eligible for the Oregon Business Energy Tax Credit (BETC) if a lighting
retrofit project is 25% more efficient than the existing system (as written, this recommendation
reduces existing energy consumption by 33%). As a public entity your facility cannot take the
full incentive for retrofit lighting projects (35% of the project costs). Instead, you may take
advantage of a “pass-through” option, which allows you to transfer the 35% tax credit to a passthrough partner in exchange for a lump sum cash payment, equal to 30.5% of project costs, after
applying other incentives. This rate is specific to retrofit projects with total costs of $20,000 or
less. For such projects, the tax credit may be applied over one year, rather than the standard five
years. The BETC will further reduce implementation costs as follows:
BETC
=
=
=
=
Business Energy Tax Credit
(TC – ETO) x 0.305
($7,200 – $3,800) x 0.305
$1,000
=
=
Total Implementation Cost
$7,200
Where,
TC
The following table summarizes incentives and net costs..
Incentive Summary
Description
Pre-incentive Cost
Energy Trust Incentives
Business Energy Tax Credit
Total After Incentives
Cost
$7,200
($3,800)
($1,000)
$2,400
After incentives, savings will pay for implementation in 4.4 years.
Notes
The Energy Trust of Oregon and the Oregon Department of Energy require written agreement
prior to project implementation.
Large quantity orders of programmed start ballasts may result in a reduced cost, which would
further decrease implementation costs.
OR2000
56
AR No. 8
Reduce Discharge Pressure
Recommended Action
Analyze the scale composition and apply chemical descaling on your roof condenser to reduce
the approach temperature (between refrigerant and ambient air) from 28°F to 20°F. This will
reduce the load on your chiller system compressors, lowering compressor energy costs by 7%.
Assessment Recommendation Summary
Electrical
Cost Implementation Payback
Energy (kWh) Savings
Cost
(years)
56,800
$2,600
$2,600
1.0
Background
Refrigerant condensing temperature is determined by compressor discharge pressure, which is
generally controlled by condenser fans. Dirt and scale buildup on the condenser surface can
decrease heat exchange efficiency between the refrigerant and air, thus increasing condensing
temperature. Compressors require more power and energy to operate against a higher discharge
pressure. Reducing compressor discharge pressure will save approximately 1% of compressor
energy consumption for each degree Fahrenheit reduction of condensing temperature. The usual
designed condenser approach temperature is less than 20°F.
During our visit, we observed one of your chiller condensers running at a 28°F approach
temperature, with all five fans at 100% speed when the ambient dry bulb temperature was 78°F.
Dirt was found in the condenser coils. The chiller design approach temperature is 15°F
(according to the manufacturer); thus we assume the approach temperature can be reduced by
cleaning the condenser.
Data Collected Summary
During our site visit, we collected the following information concerning your chiller
compressors:
Compressor Summary
Name
Compressor 1
Compressor 2
Total
OR2000
Mfr
McQuary
McQuary
Type
Refrigerant
Single Screw
Single Screw
57
R22
R22
Full Load
Amps (A)
111
139
250
We also collected the following information concerning your chiller:
•
•
Chiller runs 24/7, i.e. 8,760 hours/year
The condenser is air-cooled with 10 fans
o Each fan is rated at 2.8 full load amps (FLA)
Compressor 1 ran with a discharge temperature of 106°F when the ambient dry bulb
temperature was 78°F, i.e. approach temperature was 28°F
•
We obtained the following part load performance specifications for your chiller:
Load Percentage*
100%
75%
50%
25%
Chiller Part Load Performance
Capacity (ton)
Power (kW)
139.7
176.7
104.7
113.3
69.8
66.5
34.9
28.9
Energy Efficiency Ratio
9.6
11.2
12.7
14.7
* Represents the load percentage of the whole chiller capacity, including both compressors
We knew little about your annual chiller load profile, and therefore made the following
assumption based on local weather bin data and the measured scenario.
Load Percentage
100%
75%
50%
25%
OR2000
Chiller Load Profile Estimation
Power (kW)
Annual Percentage of Time
176.7
10%
113.3
25%
66.5
25%
28.9
40%
58
Savings Analysis
We determined a possible savings estimate based on the following assumptions:
•
1% of compressor energy will be saved for each degree Fahrenheit that condensing
temperature is reduced
Existing condensing temperature is assumed to float 28°F above the ambient temperature
while maintaining the existing minimum condensing temperature of 60°F (see the
preceding graph)
The approach temperature can reach 20°F by removing scale buildup on the condenser
The second refrigeration loop has the same approach temperature
The minimum condensing temperature is 60°F
•
•
•
•
The previous figure shows existing and proposed condensing temperatures for the annual range
of dry bulb temperatures. Savings calculations are presented in the Chiller Energy Savings
worksheets at the end of this recommendation. Worksheet definitions are provided in Appendix
C. The worksheet uses annual temperatures for your area, with hours of operation occurrence for
each temperature. The operating bin hours are listed in the “Hours” column of the worksheet.
Chiller compressors energy use is calculated below.
ECE
=
=
=
=
Existing Chiller Compressors Energy Use
OP x (ECP1 x RP1 + ECP2 x RP2 + ECP3 x RP3 + ECP4 x RP4)
8,760 hrs x (176.7 x 10% + 113.3 x 25% + 66.5 x 25% + 28.9 x 40%) kW
724,000 kWh
OP
=
=
Operation Hours
8,760 hrs
ECP1
=
=
Existing Compressor Power at 100% Capacity
176.7kW
ECP2
=
=
Existing Compressor Power at 75% Capacity
113.3kW
ECP3
=
=
Existing Compressor Power at 50% Capacity
66.5kW
ECP4
=
=
Existing Compressor Power at 25% Capacity
28.9kW
RP1
=
=
Running Percentage at 100% Capacity
10%
RP2
=
=
Running Percentage at 75% Capacity
25%
Where,
OR2000
59
RP3
=
=
Running Percentage at 50% Capacity
25%
RP4
=
=
Running Percentage at 25% Capacity
40%
To calculate total savings we add up savings for each temperature bin (temperature band). Using
the 62°F (dry bulb temperature) bin as an example, compressor energy savings for each bin are
calculated as:
CB
=
=
=
=
Compressor Energy Savings for Each Bin
ECE x AB x ( ET – PT ) x SF ÷ OP
724,000 kWh x 800 hrs/yr x (90°F – 82°F) x 1%/°F ÷ 8,760 hrs
5,289 kWh/yr
AB
=
=
Annual Bin Hours
800 hrs/yr
ET
=
=
Existing Condensing Temperature
90°F
PT
=
=
Proposed Condensing Temperature
82°F
SF
=
=
Savings Factor
1% /°F
Where,
For all bin temperatures together, the compressor energy savings total (see “Chiller Energy
Savings” worksheet at the end of this recommendation for complete data):
CES
=
=
Compressor Energy Savings
51,400 kWh/yr
Cleaning the condenser surface can increase heat exchange efficiency, and further decrease
overall condenser fan energy use, as seen in the worksheets. The chiller condenser fans have ten
1.5 hp motors with Full Load Amps of 2.8 Amps each. Fan power in kilowatts (kW) is calculated
as:
EFP
Where,
WV
OR2000
=
=
=
=
Existing Fan Power
WV x WA x PF x 1.73 x 1kW/(1,000V·A)
460 Volts x 2.8 Amps x 85% x 1.73 x 1 kW/(1,000 Volt·Amps)
19 kW
=
=
Working Voltage
460 Volts
60
WA
=
=
Working Amperage
2.8 Amps
PF
=
=
Power Factor
85%
Proposed fan power (not energy) equals existing fan power (demand), as no condensers need to
be added:
PFP
=
=
Proposed Fan Power
19 kW
The fan energy decrease for each bin (temperature band) is calculated as follows, using the 32°F
(dry bulb temperature) bin as an example:
FB
=
=
=
=
Fan Energy Increase for Each Bin
(PFP x PH) - (EFP x EH)
(19 kW x 318 hrs/yr) - (19 kW x 445 hrs/yr)
-2,411 kWh/yr
PH
=
=
Proposed Operating Hours
318 hrs/yr
EH
=
=
Existing Operating Hours
445 hrs/yr
Where,
The negative result represents a net savings in fan energy. For all bin temperatures together, the
fan energy decrease totals:
FEI
=
=
Fan Energy Increase
-5,400 kWh/yr
See the “Chiller Energy Savings” worksheet at the end of this AR for complete data. Total
energy savings are calculated as:
ES
=
=
=
CES - FEI
51,400 kWh/yr + 5,400 kWh/yr
56,800 kWh/yr
Energy cost savings are calculated by:
EC
OR2000
=
=
=
=
Energy Cost Savings
ES x IE
56,800 kWh/yr x $0.045/kWh
$2,600/yr
61
Where,
IE
=
=
Incremental Energy Cost
$0.045/kWh
The following table compares resulting savings found by reducing discharge pressure.
Source
Existing
Proposed
Savings
Energy Summary
Compressor Energy Fan Energy
(kWh)
(kWh)
724,000
672,600
51,400
165,100
159,700
5,400
Total Energy
(kWh)
889,100
832,300
56,800
Cost Analysis
There is no implementation cost for plant personnel to reset the refrigeration control system. A
vendor has provided cost estimates for the required analysis of scale composition and subsequent
descaling. The following table summarizes the implementation costs.
Implementation Summary
Source
Qty Unit Price
Initial Scale Analysis
1
$100
Chemical Descaling
1
$2,500
Total
Total Cost
$100
$2,500
$2,600
Cost savings will pay for implementation in 1.0 year.
Note
We also recommend installing a water-cooled condenser in another recommendation (See AR 2 Templifier Heat Pump, which can also reduce your discharge pressure. If you implement that
recommendation there is no need to perform the chemical descaling, and you can still achieve the
same energy savings or more.
OR2000
62
CHILLER ENERGY SAVINGS
Application:
Buildings:
Bin Data:
Refrigeration
Dixon Roof
OR
Refrigerant:
Energy Cost (E$):
Annual Hours:
Operating Conditions
Minimum Condensing Temperature (Tm):
Approach Temperature Difference (DT):
Compressor Energy (EC):
Condenser Fan Horsepower (Hp):
Fan Power (FP):
Average Fan Use Factor (UFe):
Fan Energy (FE):
Total Energy Usage:
Total Energy Cost:
Existing
60
28
724,000
15
19.0
99.4%
165,100
889,100
$39,120
R22
$0.04400 /kWh
8,760
Proposed
60
20
672,600
15
19.0
96.1%
159,700
832,300
$36,620
Savings
0
8
51,400
0.0
0.0
3.2%
5,400
56,800
$2,500
Units
°F
°F
kWh/yr
hp
kW
kWh
kWh
Bin Calculation
Dry
Bulb
(Tdb)
107
102
97
92
87
82
77
72
67
62
57
52
47
42
37
32
27
22
17
12
7
2
-3
-8
-13
Totals
Hours
(H)
0
2
12
41
85
161
249
365
509
800
1,110
1,388
1,402
1,179
747
445
166
63
24
8
1
1
1
1
0
8,760
Exist
Cond
Temp
(Tce)
135
130
125
120
115
110
105
100
95
90
85
80
75
70
65
60
60
60
60
60
60
60
60
60
60
Prop
Cond
Temp
(Tcp)
127
122
117
112
107
102
97
92
87
82
77
72
67
62
60
60
60
60
60
60
60
60
60
60
60
Deg-hr
Savings
(DHS)
0
16
96
328
680
1,288
1,992
2,920
4,072
6,400
8,880
11,104
11,216
9,432
3,735
0
0
0
0
0
0
0
0
0
0
62,000
Energy and Cost Savings
Compressor Energy Savings (CES):
Fan Energy Increase (FEI):
Total Energy Savings (ES):
Total Cost Savings (CS):
Implementation Cost (IC):
Simple Payback:
OR2000
Savings
%
(E%)
0.0%
0.0%
0.0%
0.0%
0.1%
0.1%
0.2%
0.3%
0.5%
0.7%
1.0%
1.3%
1.3%
1.1%
0.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
7.1%
Compressor
Savings
kWh
(CES)
0
13
79
271
562
1,065
1,646
2,413
3,365
5,289
7,339
9,177
9,270
7,795
3,087
0
0
0
0
0
0
0
0
0
0
51,400
Fan
Increase
kWh
(FEI)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(1,848)
(2,411)
(763)
(251)
(84)
(25)
(3)
(2)
(2)
(2)
0
(5,400)
51,400
(5,400)
56,800
$2,500
$2,600
1.0
63
Total
Savings
kWh
(ES)
0
13
79
271
562
1,065
1,646
2,413
3,365
5,289
7,339
9,177
9,270
7,795
4,935
2,411
763
251
84
25
3
2
2
2
0
56,800
kWh/yr
kWh/yr
kWh/yr
/yr
years
CONDENSER SUMMARY
Existing
Mfr
McQuary
Model
ALS150
TR
150
Totals
Quantity
10
150
15
Proposed
Mfr
McQuary
Model
ALS150
Totals
Existing
Dry
Fan Use
Bulb
Per Bin
(Tdb)
Temp
107
100%
102
100%
97
100%
92
100%
87
100%
82
100%
77
100%
72
100%
67
100%
62
100%
57
100%
52
100%
47
100%
42
100%
37
100%
32
100%
27
85%
22
74%
17
65%
12
58%
7
53%
2
48%
-3
44%
-8
41%
-13
38%
Totals
AVERAGE UF
OR2000
Fan Motors
Hp
Total Hp
1.5
15
TR
150
Quantity
10
Fan Motors
Hp
Total Hp
1.5
15
150
Proposed
Fan Use
Per Bin
Temp
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
87%
71%
61%
53%
47%
42%
38%
34%
32%
29%
27%
Existing
Operating
Hours Per
Bin Temp
15
Proposed
Operating
Hours Per
Bin Temp
0
2
12
41
85
161
249
365
509
800
1,110
1,388
1,402
1,179
747
445
141
46
16
5
1
0
0
0
0
8,704
99.4%
64
0
2
12
41
85
161
249
365
509
800
1,110
1,388
1,402
1,179
650
318
101
33
11
3
0
0
0
0
0
8,420
96.1%
Existing
Fan
Energy
kWh
0
38
228
777
1,612
3,053
4,722
6,921
9,652
15,170
21,048
26,319
26,585
22,356
14,165
8,438
2,671
880
296
88
10
9
8
8
0
165,100
Proposed
Fan
Energy
kWh
0
38
228
777
1,612
3,053
4,722
6,921
9,652
15,170
21,048
26,319
26,585
22,356
12,317
6,027
1,908
629
212
63
7
7
6
6
0
159,700
Power (kW)
19.0
19.0
Power (kW)
19.0
18.961936
Proposed
VFD Fan
Energy
kWh
0
38
228
777
1,612
3,053
4,722
6,921
9,652
15,170
21,048
26,319
26,585
22,356
9,313
3,075
701
174
46
11
1
1
1
1
0
151,800
APPENDIX A
UTILITIES
A.1. Energy Definitions
An essential component of any energy management program is tracking energy. When utility
bills are received, we record energy use and cost in a spreadsheet and develop the appropriate
graphs.
We have prepared a utility spreadsheet analysis based on the information provided by Facilities
Services Accounting. The worksheets are in section A.3, Energy Accounting.
We use specific terminology and calculations in analyzing and discussing your energy and water
expenses, detailed below.
Electricity Definitions:
Average Energy Cost. The total amount billed for 12 months of energy, divided by the total
number of energy units. Each energy type (oil, gas, electricity, propane, etc.) has its own
average energy cost. The average cost per energy unit includes the fees, taxes and unit cost.
Average Energy Cost = (Total Billed $) ÷ (Total Energy Units)
Average Load Factor. The ratio of annual electrical energy use divided by the average kilowatts
(kW) and the hours in a year.
Average Load Factor = (Total kWh/yr) ÷ (Average kW x 8,760 hrs/yr)
Average Load Factor expresses how well a given electrical system uses power. A higher load
factor yields lower average energy cost.
An example of how load factor applies: A large air compressor has high electric demand for
small periods of time and is not a large energy user. It will usually have low load factor and
relatively high demand charges. A smaller air compressor that runs for longer periods of time at
higher part load efficiency will have higher load factor and lower demand charges.
Basic Charge. The fee a utility company can charge each month to cover their administrative,
facility, or other fixed costs. Some companies have higher energy or power rates that
compensate for no or low basic charge.
Energy. The time-rate of work expressed in kWh for electric energy. The common unit is
million Btu. For a more complete description, see Power.
Energy = Work ÷ Time = (Force x Distance) ÷ Time
Incremental Demand Cost. It is the price charged by your utility company for the capacity to
meet your power needs at any given time. Peak demand is the highest demand level required
over a set period of time and is calculated by continuously monitoring demand levels. Demand
is usually billed based on peak power, but charges such as facility charges and other fees billed
65
per kW are also included in the incremental demand cost. If your utility company has stepped
demand cost rates, the step with the greatest demand is considered in the incremental demand
cost. If your utility company bills one set rate for all power needs, this value is used as the
incremental demand cost.
Incremental Energy Cost (Electricity). It is the cost of one more unit of energy, from current
use. This cost is usually taken from your utility rate schedule. When all large meters are on the
same rate schedule, the incremental energy cost is the cost from the highest energy tier, or tail
block. To further clarify this method: if a company is charged $0.05/kWh up to 100,000 kWh,
and $0.03/kWh over 100,000 kWh and they are consistently buying over 100,000 kWh each
month, any energy savings will be calculated using the $0.03/kWh cost.
If your company has multiple meters on different rate schedules or tariffs, the incremental cost is
calculated by adding electrical energy costs and dividing by the total electrical energy use.
Incremental Energy Cost = (Total kWh $) ÷ (Total kWh)
Minimum Charge. The least amount billed by a utility at the end of the billing period.
Power (and Energy). The rate at which energy is used, expressed as the amount of energy use
per unit time, and commonly measured in units of watts and horsepower. Power is the term used
to describe the capacity the utility company must provide to serve its customers. Power is
specified three ways: real, reactive and total power. The following triangle gives the relationship
between the three.
Total Power (kVA)
Reactive Power (kVAR)
Ө
Real Power (kW)
Real power is the time average of the instantaneous product of voltage and current (watts).
Apparent power is the product of rms (root mean square) volts and rms amps (volt-amps).
Demand
The highest electrical power required by the customer, generally averaged over 15 minute
cycling intervals for each month. Demand is usually billed by kW unit.
Kilovolt Amperes (kVA)
Kilovolt amperes are a measure of the current available after accounting for power factor. See
the triangle on the previous page. Power is sometimes billed by kVA.
Reactive Power
Reactive power is measured in units of kVAR. Reactive power produces magnetic fields in
devices such as motors, transformers, and lighting ballasts that allow work to be done and
electrical energy to be used. Kilo Volt Amperes Reactive (kVAR) could occur in an electrical
circuit where voltage and current flow are not perfectly synchronized. Electric motors and other
devices that use coils of wire to produce magnetic fields usually cause this misalignment of
66
three-phase power. Out-of-phase current flow causes more electrical current to flow in the
circuit than is required to supply real power. kVAR is a measure of this additional reactive
power.
High kVAR can reduce the capacity of lines and transformers to supply kilowatts of real power
and therefore cause additional expenses for the electrical service provider. Electric rates may
include charges for kVAR that exceed a normal level. These charges allow the supplying utility
to recover some of the additional expenses caused by high KVAR conditions, and also
encourages customers to correct this problem.
Power Factor
The ratio of real power to total power. Power factor is the cosine of angle θ between total
power and real power on the power triangle.
PF = cos θ = kW ÷ kVA
Disadvantages of Low Power Factor
•
•
•
Increases costs for suppliers because more current has to be transmitted requiring greater
distribution capacity. This higher cost is directly billed to customers who are metered for
reactive power.
Overloads generators, transformers and distribution lines within the plant, resulting in
increased voltage drops and power losses. All of which represents waste, inefficiency and
wear on electrical equipment.
Reduces available capacity of transformers, circuit breakers and cables, whose capacity
depends on the total current. Available capacity falls linearly as the power factor decreases.
Low Power Factor Charges
Most utilities penalize customers whose power factor is below a set level, typically in the range
of 95% - 97%, or kVAR greater than 40% of kW. Improving power factor may reduce both
energy and power costs, however these are generally much less than savings from real power
penalties enforced by electrical utilities. Energy savings are also difficult to quantify. Therefore
in our recommendations, only power factor penalty avoidance savings are included.
Improving Power Factor
The most practical and economical power factor improvement device is the capacitor. All
inductive loads produce inductive reactive power current (lags voltage by a phase angle of 90°).
Capacitors, on the other hand, produce capacitive reactive power, which is the opposite of
inductive reactive power (current leads…). Current peak occurs before voltage by a phase angle
of 90°. By careful selection of capacitance required, it is possible to totally cancel out the
inductive reactive power, but in practice it is seldom feasible to correct beyond your utilities’
penalty level (~95% for kVA meters).
Improving power factor results in:
•
Reduced utility penalty charges.
67
•
•
•
•
Improved plant efficiency.
Additional equipment on the same line.
Reduced overloading of cables, transformers, and switchgear.
Improved voltage regulation due to reduced line voltage drops and improved starting torque
of motors.
Power Factor Penalty
Utility companies generally calculate monthly power factor two ways. One way is based on
meters of reactive energy and real energy.
Monthly PF = cos [tan-1 (kVARh ÷ kWh)]
The second method is based on reactive power and real power.
Monthly PF = cos [tan-1 (kVAR ÷ kW)]
Power Factor is often abbreviated as “PF”. Also see the Power Factor definition below.
Cost Calculations
Annual operating expenses include both demand and energy costs. Demand cost (DC) is
calculated as the highest peak demand (D) multiplied by your incremental demand charge and
the number of operating months per year:
DC
=
D x demand rate ($/kW·mo) x 12 mo/yr
Energy cost (EC) is energy multiplied by your incremental electric rate:
EC
=
E x energy rate ($/kWh)
Natural Gas Definitions:
Rate Schedules. (Or tariffs) specify billing procedures and set forth costs for each service
offered. The state public utility commission approves public utility tariffs. For example: an
electric utility company will set a price or schedule of prices for power and energy and specify
basic and PF charges. A natural gas utility will specify cost to supply or transport gas and
include costs such as price per therm, basic charge, minimum charges and other costs. Current
rate schedules can often be found online at the utility company’s website. If you think your
company belongs in a different rate schedule, your utility representative can help you best.
Tariff. Another term for rate schedule.
Therm. The unit generally used for natural gas (1 therm = 100,000 Btu), but sometimes it is
measured in 106 Btu.
Commodity Rate. The component of the billing rate that represents the company’s annual
weighted average commodity cost of natural gas.
68
A.2. Energy Conversions
An essential component of any energy management program is a continuing account of energy
use and its cost. This can be done best by keeping up-to-date graphs of energy consumption and
costs on a monthly basis. When utility bills are received, we recommend that energy use be
immediately plotted on a graph. A separate graph will be required for each type of energy used,
such as oil, gas, or electricity. A combination will be necessary, for example, when both gas and
oil are used interchangeably in a boiler. A single energy unit should be used to express the
heating values of the various fuel sources so that a meaningful comparison of fuel types and fuel
combinations can be made. The energy unit used in this report is the Btu, British Thermal Unit,
or million Btu's (106 Btu). The Btu conversion factors and other common nomenclature are:
Energy Unit
Energy Equivalent
1 kWh
1 MWh
1 cubic foot of natural gas
1 gallon of No. 2 oil (diesel)
1 gallon of No. 6 oil
1 gallon of gasoline
1 gallon of propane
1 pound of dry wood
1 bone dry ton of wood (BDT)
1 unit of wood sawdust (2,244 dry pounds)
1 unit of wood shavings (1,395 dry pounds)
1 unit of hogged wood fuel (2,047 dry pounds)
1 ton of coal
1 MWh
1 therm
1 MMBtu
1 106Btu
1 kilowatt
1 horsepower (electric)
1 horsepower (boiler)
1 ton of refrigeration
3,413
3,413,000
1,030
140,000
152,000
128,000
91,600
8,600
17,200,000
19,300,000
12,000,000
17,600,000
28,000,000
1,000
100,000
1,000,000
1,000,000
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
Btu
kWh
Btu
Btu
Btu
3,413
2,546
33,478
12,000
Btu/hr
Btu/hr
Btu/hr
Btu/hr
8.33
7.48
1,000
200
pounds
gallons
gallons
ft3
Unit Equivalent
1 gallon of water
1 cubic foot of water
1 kgal
1 unit wood fuel
69
The value of graphs can best be understood by examining those plotted for your company in the
Energy Accounting. Energy use and costs are presented in the following tables and graphs.
From these figures, trends and irregularities in energy usage and costs can be detected and the
relative merits of energy conservation can be assessed.
70
A.3. Energy Accounting
Electrical Energy Use
FACILITIES SERVICES
Electrical Meter Bills
FY2007
The three tabulated values given for each month represent (top to bottom) the three Dixon electrical
meters: 145-Dixon Master Reader, 053-813-BI, 127-Tennis.
Jul-06
Aug-06
Sep-06
Oct-06
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
176,271
7,719.29
216,797 9,579.84
189,924
8,211.51
254,537 11,280.49
811
35.52
811
35.85
10,088
436.16
11,700
518.52
2,145
93.93
2,847
125.80
3,057
132.17
3,591
159.14
179,227
$7,849
220,455
$9,741 203,069
$8,780 269,828
$11,958
Nov-06
Dec-06
Jan-07
Feb-07
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
206,252
8,904.79
193,174 8,254.95
215,533
9,584.96
198,793
9,044.68
10,712
,
462.48
9,568
,
408.87
9,360
,
416.25
11,128
,
506.30
2,008
86.69
428
18.29
593
26.37
2,947
134.08
218,972
$9,454
203,170
$8,682 225,486
$10,028 212,868
$9,685
Mar-07
Apr-07
May-07
Jun-07
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
KWH Used
Cost
203,183
9,314.42
194,836 9,096.97
224,937 10,449.79
207,202
9,590.45
11,544
529.20
10,296
480.73
12,584
584.61
10,036
464.52
2,391
109.61
2,597
121.25
2,802
130.17
2,977
137.79
217,118
$9,953
207,729
$9,699 240,323
$11,165 220,215
$10,193
Electric Energy Summary
Total kWh
Total Cost
Average Cost per kWh
2,618,460
$117,186
$0.04475
71
Electrical Energy Use
300,000 Kilowatt Hours
250,000 200,000 150,000 100,000 50,000 0 Electrical Energy Cost
$12,000.00 $10,000.00 Dollars
$8,000.00 $6,000.00 $4,000.00 $2,000.00 $0.00 72
Steam Use
FACILITIES SERVICES
Steam Meter Bills
FY2007
FY07 Rate/1000lbs: $17.00
The two tabulated values given for each month represent (top to bottom) the two Dixon steam meters:
Dixon Master (145-003-S), McAlexander (053-000-S).
Jul-06
Aug-06
Sep-06
Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs
384,500
6,536.50
35,900
610.30
73,100
1,242.70
0
0
0
384,500
$6,537
35,900
$610
73,100
$1,243
Oct-06
Lbs Used Cost/1000lbs
290,900
4,945.30
0
290,900
$4,945
Nov-06
Dec-06
Jan-07
Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs
Feb-07
Lbs Used Cost/1000lbs
944,400
0
944,400
16,054.80
$16,055
2,398,500
300
2,398,800
40,774.50 2,725,400
5.10
100
$40,780 2,725,500
46,331.80
2,246,400
38,188.80
1.70
100
1.70
$46,334
Mar-07
Apr-07
May-07
Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs
2,024,200
0
2,024,200
34,411.40
$34,411
1,966,600
100
1,966,700
33,432.20 1,254,700
1.70
0
$33,434 1,254,700
Steam Usage Summary
Total lbs
15,169,400
Total MMBTU
17,900
Total Cost
$257,880
Average Cost per lb
$0.017
73
21,329.90
$21,330
2,246,500
$38,191
Jun-07
Lbs Used Cost/1000lbs
824,300
-100
824,200
14,013.10
(1.70)
$14,011
Steam Use
Pounds of Steam
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
Steam Cost
$50,000.00 $45,000.00 $40,000.00 Dollars
$35,000.00 $30,000.00 $25,000.00 $20,000.00 $15,000.00 $10,000.00 $5,000.00 $‐
74
Total Energy Cost
$60,000.00 $50,000.00 Dollars
$40,000.00 $30,000.00 $20,000.00 $10,000.00 $‐
75
Water and Sewer
FACILITIES SERVICES
City of Corvallis--Water/Sewer Meter Billing
FY2007
Water is billed per hundred cubic feet (ccf)
The three tabulated values given for each month represent (top to bottom) the three Dixon water and sewer
meters: Dixon Rec Ctr (162815), Dixon Rec Ctr (162845), McAlexander Fldhse (163935).
Jul-06
Consum 23010
23012
(ccf)
Water$
Sew$
313 476.58 1,033.69
0
8.00
0
4.00
313
$489
$1,034
Oct-06
Consum 23010
23012
( f)
(ccf)
Water$
Sew$
524 803.63 1,683.57
0
8.00
0
4.00
524
$816
$1,684
Jan-07
Consum 23010
23012
(ccf)
Water$
Sew$
518 850.92 1,717.18
0
8.00
0
4.00
518
$863
$1,717
Apr-07
Consum 23010
23012
(ccf)
Water$
Sew$
522 857.56 1,729.90
0
8.00
0
4.00
522
$870
$1,730
Water Billing Summary
Total Consumption (ccf)
Total Cost
Average Cost per ccf
Total$
1,510.27
8.00
4.00
$1,522
Aug-06
Consum 23010
23012
(ccf)
Water$
Sew$
256 388.23
858.13
0
8.00
0
4.00
256
$400
$858
Total$
2,487.20
8.00
4.00
$2,499
Nov-06
Consum 23010
23012
( f)
(ccf)
Water$
Sew$
422 645.53 1,369.41
0
8.00
0
4.00
422
$658
$1,369
Total$
2,568.10
8.00
4.00
$2,580
Feb-07
Consum 23010
23012
(ccf)
Water$
Sew$
564 927.28 1,863.46
0
8.00
0
4.00
564
$939
$1,863
Total$
2,587.46
8.00
4.00
$2,599
May-07
Consum 23010
23012
(ccf)
Water$
Sew$
514 844.28 1,704.46
0
8.00
0
4.00
514
$856
$1,704
Consum
Total$
1,246.36
8.00
4.00
$1,258
(ccf)
309
0
0
309
Consum
Total$
2,014.94
8.00
4.00
$2,027
( f)
(ccf)
302
0
0
302
Consum
Total$
2,790.74
8.00
4.00
$2,803
(ccf)
395
0
0
395
Consum
Total$
2,548.74
8.00
4.00
$2,561
(ccf)
330
0
0
330
Sep-06
23010
23012
Water$
Sew$
470.38 1,021.37
8.00
4.00
$482
$1,021
Total$
1,491.75
8.00
4.00
$1,504
Dec-06
23010
23012
Water$
Sew$
459.53
999.81
8.00
4.00
$472
$1,000
Total$
1,459.34
8.00
4.00
$1,471
Mar-07
23010
23012
Water$
Sew$
646.74 1,326.04
8.00
4.00
$659
$1,326
Total$
1,972.78
8.00
4.00
$1,985
Jun-07
23010
23012
Water$
Sew$
538.84 1,119.34
8.00
4.00
$551
$1,119
Total$
1,658.18
8.00
4.00
$1,670
Sewer Billing Summary
Total Consumption (ccf)
Total Cost
Average Cost per ccf
4,969
$8,054
$1.62
76
4,969
$16,426
$3.31
Water Consumption
Hundred Cubic Feet
600
500
400
300
200
100
0
Water Cost
$1,000 $900 $800 Dollars
$700 $600 $500 $400 $300 $200 $100 $0 77
Sewer Cost
$2,000 $1,800 $1,600 Dollars
$1,400 $1,200 $1,000 $800 $600 $400 $200 $0 Total Water and Sewer Cost
$3,000 Dollars
$2,500 $2,000 $1,500 $1,000 $500 $0 78
APPENDIX B
LIGHTING
B.1 LIGHTING WORKSHEET DEFINITIONS
The following lighting inventory and any lighting worksheets contained in the report use
information obtained during the on-site visit to determine any potential energy savings related to
lighting improvements. In all cases the value in the Savings column is the existing value less the
proposed value. The terminology and calculations are described as follows:
PLANT
Building. A description of the building if the plant includes several buildings.
Area: The lighting calculations may refer to a specific location within the building.
Recommended Footcandles. The recommended footcandle levels come from the Illuminating
Engineering Society (IES) Lighting Handbook.
Average Demand Cost (D$). The demand cost ($/kW-month) is taken from the appropriate rate
schedule of your utility. Winter and summer rates are averaged, if necessary.
Average Energy Cost (E$). The energy cost ($/kWh) is taken from the appropriate rate
schedule of your utility for the least expensive energy block. Winter and summer rates are
averaged, if necessary.
Labor Cost ($/H). The cost of labor is estimated for operating and installation cost calculations.
FIXTURES
Description (FID). Fixture type, size, manufacturer, or catalog number may be included here.
Quantity (F#). The number of fixtures in the area are recorded during the site visit.
Operating Hours (H). The number of hours which the lighting fixtures operate each year.
Use Factor (UF). The fraction of fixtures that are used multiplied by the fraction of operating
hours (H) that the lights are on.
Lamps/Fixture (L/F). The number of lamps in each fixture.
Ballasts/Fixture (B/F). The number of ballasts in each discharge fixture.
79
Cost (FC). The cost of the existing and proposed fixtures can be compared when modifying or
replacing fixtures.
LAMPS
Description (LID). Lamp type, size, manufacturer, or catalog number may be included here.
Quantity (L#). The number of lamps can be calculated from the number of fixtures and the
number of lamps per fixture:
L#
=
F# x L/F
Life (LL). Lamp life is defined as the number of operating hours after which half the original
lamps will fail. The life recorded here is based on 3 operating hours per start. This provides a
more conservative estimate of lamp life than using longer hours per start.
Replacement Fraction (Lf). The fraction of lamps that normally can be expected to burn out
during a year can be calculated from the operating hours, the use factor, and the lamp life:
Lf
=
H x UF / LL
Watts / Lamp (W/L). The rated lamp power does not include any ballast power, which is
included in the Ballasts section.
Lumens (LM). Lamp output is measured in lumens. Lumens are averaged over lamp life
because lamp output decreases with time.
Cost (C/L). The retail cost per lamp is entered here.
BALLASTS
This section applies only to discharge lamps with ballasts. This section will be blank for
incandescent lamps.
Description (BID). Additional information such as type, size, manufacturer, or catalog number
may be included here.
Quantity (B#). The number of ballasts can be calculated from the number of fixtures and the
number of ballasts per fixture:
B#
=
F# x B/F
80
Life (BL). Ballast life is determined from manufacturer's data. A life of 87,600 hours for a
standard ballast and 131,400 hours for an efficient ballast is used in the calculations.
Replacement Fraction (Bf). The fraction of ballasts normally expected to burn out during a
year can be calculated from the operating hours, the use factor, and the ballast life:
Bf
=
H x UF / BL
Input Watts (IW). Ballast catalogs specify ballast input watts that include lamp power. The
input wattage varies for different combinations of lamps and ballasts.
Cost (BC). The retail ballast cost is entered here.
POWER AND ENERGY
Total Power (P). For incandescent lamps total power is the product of the number of lamps and
the watts per lamp.
P
=
L# x W/L
(Incandescent Lamps)
For discharge lamps total power is the product of the ballast input watts and the number of
ballasts:
P
=
B# x IW
(Discharge Lamps)
Energy Use (E). The annual energy use is the product of the total power, the use factor, and the
annual operating hours:
E
=
P x UF x H / (1,000 watts/kilowatt)
LIGHT LEVEL CHECK
Total Lumens (TLM). The existing and proposed lumen levels are summed for all lamps.
TLM
=
L# x LM
Footcandles (FC). Light is measured in units of footcandles. The existing footcandle level
(FC0) is measured, while the proposed level (FC1) is determined from the ratio of the proposed
total lumens (TLM1) to existing total lumens (TLM0) times the existing footcandle level.
FC1
=
FC0 x (TLM1 / TLM0)
The proposed footcandle level can then be compared to both the existing and the recommended
levels to determine if there will be adequate light for the work space.
81
Lumens / Watt (LM/W). The total lamp output in lumens divided by the total power is a
measure of lighting efficiency.
LM/W
=
TLM / P
ANNUAL OPERATING COST
Power Cost (PC). The annual demand cost is the total power times the average monthly demand
cost from the worksheet times 12 months per year:
PC
=
P x D$ x 12 months/year
Energy Cost (EC). The annual energy cost is the energy use times the electricity cost from your
utility rate schedule:
EC
=
E x E$
Lamp O&M Cost (LOM). Operation and maintenance costs are the sum of lamp and labor
costs for replacing the fraction of lamps (L# x Lf) that burn out each year.
LOM
=
L# x Lf x [LC + (0.166 hours x $/H)]
We assume that two people can replace a lamp and clean the fixture and lens in about five
minutes (0.166 man-hours/lamp), replacing lamps as they burn out.
Ballast O&M Cost (BOM). Operation and maintenance costs are the sum of ballast (BC) and
labor costs ($/H) for replacing the fraction of ballasts (B# x Bf) that burn out each year.
BOM
=
B# x Bf x [BC + (0.5 hours x $/H)]
We assume that one person can replace a ballast in about thirty minutes (0.5 man-hours/ballast),
replacing ballasts as they burn out.
Total Operating Cost (OC). The sum of the annual power and energy costs and lamp and
ballast O&M costs.
OC
=
PC + EC + LOM + BOM
82
IMPLEMENTATION COST
The implementation costs depend on whether refixturing, group relamping, or spot replacing of
lamps and ballasts is recommended.
Refixturing
Materials: The cost is the cost per fixture (C/F) times the number of fixtures (F#) plus the
lamp cost (LC) times the number of lamps (L#).
M$
=
F# x (C/F) + L# x C/L
Labor: The labor cost includes the removal of the existing fixtures and the installation of the
recommended fixtures.
Group Relamping
Materials: When replacing all lamps at one time (group relamping), the cost of materials can
be found from
M$
=
L# x C/L
Labor: We estimate the labor cost for group relamping to be one half the cost of replacing
each lamp as it burns out. We assume that two people can replace two lamps and clean the
fixture and lens in about 5 minutes (0.083 man-hours/lamp, H/L). Because relamping does
not require a licensed electrician, the labor rate for relamping is often lower than the labor
rate for fixture replacement. To calculate the total labor cost for group lamp replacement we
calculate the labor cost of group replacing all of the lamps.
L$GROUP
=
L# x H/L x $/H
Spot Replacement of Lamps & Ballasts
Materials: When replacing lamps only as they burn out (spot relamping), we use the cost
difference (LC1 - LC0) between standard and energy-efficient lamps for all lamps.
M$
=
L# x (LC1 - LC0)
When replacing ballasts only as they burn out (spot reballasting), we use the cost difference
(BC1 - BC0) between standard and energy-efficient ballasts for all ballasts.
M$
=
B# x (BC1 - BC0)
Labor: There is no additional labor cost.
83
Total Cost (IC). Total implementation cost is the sum of materials and labor cost
IC
=
M$ + L$
SIMPLE PAYBACK.
The simple payback (SP) is calculated on each lighting worksheet.
SP
=
IC / OC 84
Replace Tennis Pavilion Fixtures
Building:
Tennis Pavillion
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
Tennis Pavilion
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
Metal Halide
Number of Fixtures
Hours
48
4200
Proposed Fixtures
45" T5 HO with Motion Sensor
Number of Fixtures
Hours
48
1400
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
6
Ballasts/Fixture
1
Ballasts/Fixture
1
Fixture Cost
$139.75
Lamps
Description
Lamp Cost
Watts per Lamp
Lumens
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
48
20000
$80.35
400
30000
21.00%
Quantity:
54 Watt T5 HO
288
Life
30000
Lamp Cost
$6.00
Watts per Lamp
Lumens
Replacement Fraction
54
5000
4.67%
Annual Lamp Replacement Cos
$80.64
$25.20
Annual Maintenance Labor Cost
$33.60
Ballast
400 watt Metal Halide
Quantity
Life
Description
$809.93
Ballast
Description
$195.00
Lamps
400 Watt Clear Met. Hal.
Quantity:
Life
Fixture Cost
48
60000
Description
Quantity
Life
46" T5
48
72000
Ballast Cost
$119.20
Ballast Cost
$150.00
Ballast Factor
100.00%
Ballast Factor
100.00%
Input Watts
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
Area Lumens
458
7.00%
$400.51
$84.00
1440000
Footcandles
40
Lighting Efficiency
Power Use
Energy Use
Demand Cost
35
21.984
92332.8
$0
Input Watts
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Energy Cost
$4,099.58
Energy Cost
Maintenance Material Cost
$1,210.44
Maintenance Material Cost
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
Saved
$109.20
$5,419.22
Maintenance Labor Cost
Total Operating Cost
370
1.94%
$140.00
$23.33
1440000
40
43.2
17.76
4.224
24864
67469
$0
$1,103.96
$0
$2,996
$220.64
$990
$56.93
$52
$1,381.53
$4,038
Materials
$11,088
Labor
$2,400
Total Implementation Cost
$13,488
Simple Payback
3.3
OR2000
85
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
Steven Natatorium
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
4 Ft T8 Elec
Number of Fixtures
Hours
45
5600
Proposed Fixtures
Number of Fixtures
Hours
4 Ft T8 Elec
45
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
1
Ballasts/Fixture
1
Fixture Cost
$50.00
Lamps
Description
Fixture Cost
$50.00
Lamps
4 Ft T8 C.T.
Quantity:
45
Description
Quantity:
4 Ft T8 C.T.
45
Life
20000
Life
20000
Lamp Cost
$1.89
Lamp Cost
$1.89
Watts per Lamp
Lumens
32
2710
Watts per Lamp
Lumens
32
2710
Replacement Fraction
28.00%
Replacement Fraction
15.00%
Annual Replacement Cost
$23.81
Annual Lamp Replacement Cos
$12.76
Annual Maintenance Labor Cost
$31.50
Annual Maintenance Labor Cost
$16.88
Ballast
Description
Ballast
4 Ft F32T8
Quantity
Life
Ballast Cost
45
75000
$36.75
Ballast Factor
Annual Replacement Cost
Annual Maintenance Labor Cost
Area Lumens
34
7.47%
$123.48
$84.00
1856180
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Description
Quantity
Life
Ballast Cost
4 Ft F32T8
45
75000
$36.75
Ballast Factor
Input Watts
Replacement Fraction
Saved
22
625
1.53
8568
$0
Input Watts
Replacement Fraction
34
4.00%
Annual Replacement Cost
$66.15
Annual Maintenance Labor Cost
$45.00
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
1834500
21.7
617.7
1.53
0
4590
3978
$0
$0
Energy Cost
$380.42
Energy Cost
$203.80
$177
Maintenance Material Cost
$147.29
Maintenance Material Cost
$78.91
$68
Maintenance Labor Cost
$115.50
Maintenance Labor Cost
$61.88
$54
Total Operating Cost
$643.21
Total Operating Cost
$344.58
$299
Implementation Costs
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
86
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
West Lobby
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
2 Lamp CFL Fixture
Number of Fixtures
Hours
15
5600
Proposed Fixtures
Number of Fixtures
Hours
2 Lamp CFL Fixture
15
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
2
Lamps/Fixture
2
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$75.00
Fixture Cost
Lamps
Description
Lamp Cost
30
10000
$16.99
Watts per Lamp
Lumens
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
$75.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
Description
Quantity:
Life
Lamp Cost
42
2275
56.00%
Watts per Lamp
Lumens
Replacement Fraction
42 Watt Compact Fluor.
30
10000
$16.99
42
2275
30.00%
$285.43
Annual Lamp Replacement Cos
$152.91
$42.00
Annual Maintenance Labor Cost
$22.50
Ballast
Ballast
Description
Description
Quantity
0
Quantity
Life
Life
Ballast Cost
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
Replacement Fraction
0
100.00%
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
68250
Footcandles
150
Lighting Efficiency
54.2
Power Use
Energy Use
Demand Cost
Saved
1.26
7056
$0
Area Lumens
68250
Footcandles
150
Lighting Efficiency
54.2
Power Use
Energy Use
Demand Cost
1.26
0
3780
3276
$0
$0
Energy Cost
$313.29
Energy Cost
$167.83
$145
Maintenance Material Cost
$285.43
Maintenance Material Cost
$152.91
$133
$22.50
$20
$343.24
$297
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$42.00
$640.72
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
87
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
West Vestibule Entrance
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
4
5600
Proposed Fixtures
CFL for 135 Watt Incand.
Number of Fixtures
Hours
4
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
4
10000
$16.99
Watts per Lamp
Lumens
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
Description
Quantity:
Life
Lamp Cost
42
2275
42 Watt Compact Fluor.
Watts per Lamp
Lumens
4
10000
$16.99
42
2275
Replacement Fraction
56.00%
Replacement Fraction
30.00%
Annual Replacement Cost
$38.06
Annual Lamp Replacement Cos
$20.39
$5.60
Annual Maintenance Labor Cost
$3.00
Annual Maintenance Labor Cost
Ballast
Description
Ballast
No Ballast Needed
Quantity
Life
Ballast Cost
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
Footcandles
Energy Use
Demand Cost
100.00%
Area Lumens
150
Lighting Efficiency
Power Use
Saved
Footcandles
Lighting Efficiency
0.168
940.8
$0
Power Use
Energy Use
Demand Cost
0.168
0
504
437
$0
$0
Energy Cost
$41.77
Energy Cost
$22.38
$19
Maintenance Material Cost
$38.06
Maintenance Material Cost
$20.39
$18
$3.00
$3
$45.77
$40
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$5.60
$85.43
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
88
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
Main West Hallway
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
17
5600
Proposed Fixtures
Number of Fixtures
Hours
CFL for 135 Watt Incand.
17
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
17
10000
$16.99
Watts per Lamp
Lumens
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
42
2275
56.00%
Ballast Cost
Quantity:
Life
Watts per Lamp
Lumens
17
10000
$16.99
42
2275
30.00%
$161.74
Annual Lamp Replacement Cos
$86.65
$23.80
Annual Maintenance Labor Cost
$12.75
Ballast
No Ballast Needed
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
42 Watt Compact Fluor.
Replacement Fraction
Quantity
Life
Description
Lamp Cost
Ballast
Description
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
116530
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Saved
18
163.2
0.714
3998.4
$0
100.00%
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
0.714
0
2142
1856
$0
$0
Energy Cost
$177.53
Energy Cost
$95.10
$82
Maintenance Material Cost
$161.74
Maintenance Material Cost
$86.65
$75
Maintenance Labor Cost
$12.75
$11
$194.50
$169
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$23.80
$363.07
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
89
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
East Vestibule Entrance
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
4
5600
Proposed Fixtures
CFL for 135 Watt Incand.
Number of Fixtures
Hours
4
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
4
10000
$16.99
Watts per Lamp
Lumens
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
Description
Quantity:
Life
Lamp Cost
42
2275
42 Watt Compact Fluor.
Watts per Lamp
Lumens
4
10000
$16.99
42
2275
Replacement Fraction
56.00%
Replacement Fraction
30.00%
Annual Replacement Cost
$38.06
Annual Lamp Replacement Cos
$20.39
$5.60
Annual Maintenance Labor Cost
$3.00
Annual Maintenance Labor Cost
Ballast
Description
Ballast
No Ballast Needed
Quantity
Life
Ballast Cost
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
9100
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Saved
20
54.2
0.168
940.8
$0
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
100.00%
9100
20
54.2
0.168
0
504
437
$0
$0
Energy Cost
$41.77
Energy Cost
$22.38
$19
Maintenance Material Cost
$38.06
Maintenance Material Cost
$20.39
$18
$3.00
$3
$45.77
$40
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$5.60
$85.43
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
90
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
East Lobby
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
6
5600
Proposed Fixtures
CFL for 135 Watt Incand.
Number of Fixtures
Hours
6
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
6
10000
$16.99
Watts per Lamp
Lumens
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
Description
Quantity:
Life
Lamp Cost
42
2275
42 Watt Compact Fluor.
Watts per Lamp
Lumens
6
10000
$16.99
42
2275
Replacement Fraction
56.00%
Replacement Fraction
30.00%
Annual Replacement Cost
$57.09
Annual Lamp Replacement Cos
$30.58
$8.40
Annual Maintenance Labor Cost
$4.50
Annual Maintenance Labor Cost
Ballast
Description
Ballast
No Ballast Needed
Quantity
Life
Ballast Cost
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
27100
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Saved
79
107.5
0.252
1411.2
$0
100.00%
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
0.252
0
756
655
$0
$0
Energy Cost
$62.66
Energy Cost
$33.57
$29
Maintenance Material Cost
$57.09
Maintenance Material Cost
$30.58
$27
$4.50
$4
$68.65
$59
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$8.40
$128.14
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
91
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
East Entrance
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
5
5600
Proposed Fixtures
CFL for 135 Watt Incand.
Number of Fixtures
Hours
5
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
5
10000
$16.99
Watts per Lamp
Lumens
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
Description
Quantity:
Life
Lamp Cost
42
2275
42 Watt Compact Fluor.
Watts per Lamp
Lumens
5
10000
$16.99
42
2275
Replacement Fraction
56.00%
Replacement Fraction
30.00%
Annual Replacement Cost
$47.57
Annual Lamp Replacement Cos
$25.49
$7.00
Annual Maintenance Labor Cost
$3.75
Annual Maintenance Labor Cost
Ballast
Description
Ballast
No Ballast Needed
Quantity
Life
Ballast Cost
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
32
Lighting Efficiency
Energy Use
Demand Cost
100.00%
Area Lumens
Footcandles
Power Use
Saved
Footcandles
Lighting Efficiency
0.21
1176
$0
Power Use
Energy Use
Demand Cost
0.21
0
630
546
$0
$0
Energy Cost
$52.21
Energy Cost
$27.97
$24
Maintenance Material Cost
$47.57
Maintenance Material Cost
$25.49
$22
$3.75
$3
$57.21
$50
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$7.00
$106.79
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
92
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
2nd Story West Hallway
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
CFL for 135 Watt Incand.
Number of Fixtures
Hours
30
5600
Proposed Fixtures
Number of Fixtures
Hours
CFL for 135 Watt Incand.
30
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
0
Ballasts/Fixture
0
Fixture Cost
$0.00
Fixture Cost
Lamps
Description
Lamp Cost
30
10000
$16.99
Watts per Lamp
Lumens
Replacement Fraction
Annual Replacement Cost
Annual Maintenance Labor Cost
42
2275
56.00%
Ballast Cost
Quantity:
Life
Watts per Lamp
Lumens
Replacement Fraction
30
10000
$16.99
42
2275
30.00%
Annual Lamp Replacement Cos
$152.91
$42.00
Annual Maintenance Labor Cost
$22.50
Ballast
No Ballast Needed
0
1000000
$0.00
Description
Quantity
0
Life
Ballast Cost
Ballast Factor
Ballast Factor
Input Watts
Input Watts
Replacement Fraction
42 Watt Compact Fluor.
$285.43
Quantity
Life
Description
Lamp Cost
Ballast
Description
$0.00
Lamps
42 Watt Compact Fluor.
Quantity:
Life
0.56%
Replacement Fraction
Annual Replacement Cost
$0.00
Annual Replacement Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Annual Maintenance Labor Cost
$0.00
Area Lumens
100270
Footcandles
300
Lighting Efficiency
79.6
Power Use
Energy Use
Demand Cost
Saved
1.26
7056
$0
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
100.00%
54200
162.2
43
1.26
0
3780
3276
$0
$0
Energy Cost
$313.29
Energy Cost
$167.83
$145
Maintenance Material Cost
$285.43
Maintenance Material Cost
$152.91
$133
$22.50
$20
$343.24
$297
Maintenance Labor Cost
Total Operating Cost
Implementation Costs
$42.00
$640.72
Maintenance Labor Cost
Total Operating Cost
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
93
Turn off Lights Near Entrances, Windows and Skylights
Building:
Dixon Rec Center
Maintenance Labor Rate:
$15
Fixture Replacement Time:
60 minutes
Area:
2nd Story West Hallway
Electrician Labor Rate:
$50
Lamp Replacement Time:
10 minutes
Ballast Replacement Time:
30 minutes
Incremental Energy Cost:
$0.0444 /kW
Existing Fixtures
Incremental Demand Cost $0 /kW
4 Ft T8 Elec
Number of Fixtures
Hours
10
5600
Proposed Fixtures
Number of Fixtures
Hours
4 Ft T8 Elec
10
3000
Output Factor
100%
Output Factor
100%
Lamps/Fixture
1
Lamps/Fixture
1
Ballasts/Fixture
1
Ballasts/Fixture
1
Fixture Cost
$50.00
Lamps
Description
Fixture Cost
$50.00
Lamps
4 Ft T8 C.T.
Quantity:
10
Description
Quantity:
4 Ft T8 C.T.
10
Life
20000
Life
20000
Lamp Cost
$1.89
Lamp Cost
$1.89
Watts per Lamp
Lumens
Replacement Fraction
32
2710
28.00%
Watts per Lamp
Lumens
Replacement Fraction
32
2710
15.00%
Annual Replacement Cost
$5.29
Annual Lamp Replacement Cos
$2.84
Annual Maintenance Labor Cost
$7.00
Annual Maintenance Labor Cost
$3.75
Ballast
Description
Ballast
4 Ft F32T8
Quantity
Life
Ballast Cost
10
75000
$36.75
Ballast Factor
Description
Quantity
Life
Ballast Cost
4 Ft F32T8
10
75000
$36.75
Ballast Factor
Input Watts
Replacement Fraction
34
7.47%
Input Watts
Replacement Fraction
34
4.00%
Annual Replacement Cost
$27.44
Annual Replacement Cost
$14.70
Annual Maintenance Labor Cost
$18.67
Annual Maintenance Labor Cost
$10.00
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
Saved
100270
300
151.9
0.34
1904
$0
Area Lumens
Footcandles
Lighting Efficiency
Power Use
Energy Use
Demand Cost
54200
162.2
82.1
0.34
0
1020
884
$0
$0
Energy Cost
$84.54
Energy Cost
$45.29
$39
Maintenance Material Cost
$32.73
Maintenance Material Cost
$17.54
$15
Maintenance Labor Cost
$25.67
Maintenance Labor Cost
$13.75
$12
Total Operating Cost
$76.57
$66
Total Operating Cost
Implementation Costs
$142.94
Materials
$0
Labor
$0
Total Implementation Cost
$0
Simple Payback
0
OR2000
94
APPENDIX C
REFRIGERATION
C.1. REFRIGERATION WORKSHEET DEFINITIONS
The refrigeration worksheet uses data gathered during the on-site visit and local weather data to
estimate the energy savings due to reducing condensing pressure. The worksheet calculation
methods and symbols are described as follows:
EXISTING OPERATING CONDITIONS (e)
Minimum Existing Condensing Temperature (Tme). The condenser fans cycle on and off to
maintain a minimum condensing temperature. The minimum existing condensing temperature is
the average of the fan cut-in and fan cut-out temperatures. When system load or low ambient
temperatures permit, the condensing temperature drops. A pressure switch maintains the
minimum condensing temperature and pressure by turning the condenser fans off, reducing the
condensing capacity, and causing the condensing temperature to rise. The same pressure switch
also turns the fans back on when the condensing temperature rises. During periods of high
system load or high ambient temperatures, the condensing temperature may stay above the fan
shut off point.
Temperature Difference (DTe). With the condenser fans on, the condensing temperature floats
at an average temperature difference above the ambient temperature.
Compressor Energy (ECe). The annual energy consumption of the high-stage compressors.
Condenser Fan Horsepower (HPe). The total condenser fan horsepower of the system.
Fan Power (FPe). The actual power used by the condenser fans, taking motor load and
efficiency into consideration.
Annual Operating Hours (OH). Annual operating hours of refrigeration system.
PROPOSED OPERATING CONDITIONS (p)
Minimum Proposed Condensing Temperature (Tmp). Same as the definition for the existing
conditions, except that the fan cut-in and fan-cut out points have been reduced. The condensing
capacity may have been increased if needed to reduce the condensing temperature. The
minimum proposed condensing temperature is 60°F for reciprocating compressors and screw
compressors without liquid injection cooling. The minimum pressure is 125 psig for screw
compressors with liquid injection cooling, and 93 psig with liquid injection booster pumps.
95
Temperature Difference (DTe). Same as the definition for the existing conditions, except that
the temperature difference may be reduced if condenser capacity or fan use is increased.
Compressor Energy (ECp). The annual energy consumption of the high-stage compressors
with reduced condensing temperature.
BIN CALCULATION
Long term (30-year average) local weather data is commonly available in a "bin" format. A
temperature bin is a five degree range of dry bulb temperatures. Bin weather data consists of the
average number of hours per year that the temperature was within each 5-degree range. The
middle temperature of each bin is defined as the dry bulb temperature for that bin. For example,
the temperature bin between 45°F and 49°F is listed as the average dry bulb temperature of 47°F.
Dry Bulb Temperature (Tdb). The dry bulb temperature for each bin is used for air-cooled
condensers.
Wet Bulb Temperature (Twb). The mean coincident wet bulb temperature for the
corresponding bin is used for wet or evaporative condensers.
Hours (H). The annual hours of occurrence for the bin temperature
Existing (Tce) and Proposed (Tcp) Condensing Temperature. We assume the existing
condensing temperature floats above the ambient wet or dry bulb temperature while maintaining
the existing minimum condensing temperature. Resetting fan pressure switches will allow the
proposed condensing temperature to float above the wet or dry bulb temperature with a new
proposed minimum condensing temperature. The actual condensing temperatures are therefore:
Tce
Tcp
=
=
Larger [ Tme, T + DTe ]
Larger [ Tmp, T + DTp ]
T
=
=
Twb, wet bulb for wet or evaporative condensers
Tdb, dry bulb for air cooled condensers
where,
Degree-Hour Savings (DHS). The Degree-Hour Savings reflects the decrease in condensing
temperature multiplied by the number of hours for each bin temperature in the worksheet. The
Degree-Hour Savings is calculated when the proposed condensing temperature is less than the
existing condensing temperature:
DHS
=
( Tce - Tcp ) x H
Energy Savings Percent (E%). Energy savings will occur due to reduced running time,
increased capacity, and reduced compressor power. Savings of 1% in compressor energy per
96
degree drop in condensing temperature are possible. The energy savings percent of the total
annual compressor energy for each bin temperature can be found from:
E%
=
DHS / HT
HT
=
Total annual bin hours: 8,760 hr/yr
where,
Compressor Energy Savings (CES). The compressor energy savings for each bin temperature
can be calculated by:
CE
=
ECe x E%
Fan Energy Increase (FEI). Reducing the minimum condensing temperature will increase the
condenser fan energy consumption. We assume that the fans will operate at full load during
periods when the condensing temperature is above the minimum condensing temperature. When
the condensing temperature reaches its minimum setpoint, a decrease in the dry or wet bulb
temperature results in fan cycling to maintain the minimum condensing temperature. The fan
energy increase for each bin temperature can be found from
FE
=
FP x H x (OH/HT) x [ DTp/(Tcp-T) - DTe/(Tce-T)]
ENERGY AND COST SAVINGS
Total Energy Savings (ES). The compressor energy savings minus the fan energy increase.
ES
=
CE - FE
Total Cost Savings (CS). The total annual cost savings resulting from multiplying the total
annual energy savings by the cost of electricity (E$):
CS
=
ES x E$
Implementation Cost (IC). There is no implementation cost to reduce the pressure switch
settings. If there are no pressure switches, these cost about $75 each to install. The cost of
liquid pumps for screw compressors with liquid injection to ensure adequate compressor cooling
or other systems will be approximately $3,000 each. Hy-Save pumps for freon systems cost
approximately $1,200 each. The cost of increasing evaporative condenser capacity is estimated
at $75/ton.
Simple Payback (PB). The simple payback is calculated as:
PB
=
IC / CS
97