Dixon Recreation Center

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 Energy and Waste Analyst Alan Heninger Lighting Analyst Wayne Johnson Energy and Productivity Analyst Yuming Qui Refrigeration Analyst Paul Stelson Energy Analyst Samuel Walker Lead Energy Analyst

Dr. George Wheeler IAC Director Batcheller Hall 341 Corvallis, OR 97331-2405 (541) 737-2515

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.

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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%.

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* 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 Cost % Use

Source Qty. Units Savings Reduction Savings %Steam Energy 9,657 106 Btu $139,061 53.9% 88.92% Electrical Energy 387,215 kWh $17,328 14.8% 11.08% Totals $156,400 100.0%

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.

Assessment Recommendation Summary Energy Electrical Cost Implementation Payback

AR# Description (106 Btu) Energy (kWh) Savings Cost* (years) 1 Natatorium Airflow 4,312 217,700 $71,900 $8,800 1,2 0.1 2 Templifier Heat Pump 4,052 20,800 $59,200 $80,500 2 1.4 3 Solar Water Heating 1,293 - $18,600 $58,300 2 3.1 4 Towel Monitoring - - $4,200 $40 0.0

5 Tennis Pavilion Lighting - 67,200 $4,040 $7,000 1,2 1.7 6 Day-Lighting - 15,400 $1,300 $1,800 1,2 1.4 7 Racquetball Lighting - 9,300 $540 $2,400 1,2 4.4 8 Reduce Discharge Pressure - 56,800 $2,600 $2,600 1.0

Totals 9,657 387,200 $162,300 $161,440 1.0

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Existing Annual Energy Use Summary Source Qty. Units 106Btu Use % Cost Cost %

Steam Energy 15,169,400 lbs 17,900 66.7% $257,880 68.8% Electric Energy 2,618,460 kWh 8,929 33.3% $117,186 31.2%

Totals 26,800 100.0% $375,100 100.0% 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.

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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.


(106 Btu) Energy (kWh) Savings Cost (years) 4,312 217,700 $71,900 $15,800 0.2

Estimated Incentive Summary

ETO1 BETC2 Net Net Payback Incentive Tax Credit Cost (years) $4,000 $3,000 $8,800 0.1

1 Energy Trust of Oregon Incentive 2 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.

• Air handling system operation: 24/7 or 8,760 annual operating hours

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• 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

1st Visit Outside

Air Zone Air 2nd Visit

Outside Air

Zone Air

Temp (oF) 89 88 Temp (oF) 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 Where, 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 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.

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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 Where, VF = Full Volumetric Flow = 40,000 cfm SV67 = Specific Volume of Air at 67°F = 13.35 ft3/lb Energy required to heat the air can be calculated as: BT67 = 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 Where, AH67 = Annual Hours for Bin 67°F = 525 hrs ΔSE67 = Change In Specific Enthalpy for Bin 67°F = SE84 – SE67 = 29.5 Btu/lb – 25.0 Btu/lb = 4.5 Btu/lb Where, SE84 = Specific Enthalpy for 84°F at the MCWB = 29.5 Btu/lb SE67 = Specific Enthalpy for 67°F at the MCWB = 25.0 Btu/lb

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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.

Btu Calculation Totals Bin Avg.

Temp (°F) Annual Hours

Temp Change (°F)

Change In Specific Enthalpy

Specfic Volume (Ft3/lb) MMBTU

2 1 82 20.0 11.70 4 7 2 77 20.0 11.82 8 12 7 72 20.0 11.95 28 17 24 67 20.0 12.08 95 22 52 62 18.0 12.21 148 27 123 57 13.0 12.33 311 32 441 52 12.0 12.45 1,062 37 798 47 11.0 12.58 1,751 42 1,180 42 10.0 12.71 2,229 47 1,388 37 9.0 12.84 2,336 52 1,406 32 5.5 12.97 2,081 57 1,119 27 6.0 13.09 1,334 62 772 22 5.5 13.23 770 67 525 17 4.5 13.35 425 72 359 12 3.0 13.48 192 77 249 7 2.0 13.61 66

Total 12,841 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 Where, THE = 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 Where, SC = Steam Cost = $0.0170/lb

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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 Where, 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 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 Where, SH = Space Heating Estimation (for remainder of facility) = RSC x 1/3 = $121,000 x 1/3 = $40,000/yr

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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 = Steam Btu for Bin 57°F = BT57 – XB57 = 1,334 x 106 Btu– 616 x 106 Btu = 718 x 106 Btu Where, XB57 = Exchanger Btu for Bin 57°F = 616 x 106 Btu The following table summarizes total energy, exchanger savings, and steam energy for each bin.

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Existing Condition Summary Bin Avg.

Temp (°F) Total

MMBTU Heat Exchanger

MMBTU Steam

MMBTU 2 4 3 1 7 8 6 2 12 28 22 6 17 95 76 19 22 148 102 46 27 311 227 84 32 1,062 637 425 37 1,751 1,142 609 42 2,229 1,449 780 47 2,336 1,298 1,038 52 2,081 1,301 780 57 1,334 616 718 62 770 210 560 67 425 0 425 72 192 0 192 77 66 0 66

Total 12,841 7,090 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 Where, HE = Heating Energy (from Btu table above) = 5,750 x 106 Btu/yr 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

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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 Where, MFAir84 = Mass Flow Rate Air at 84°F = VF ÷ SV = 40,000 cfm ÷ 13.77 ft3/lb = 2,905 lbs/min Where, 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. 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 = 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

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Where, HR84 = Humidity Ratio for 84°F = 0.0125 lbs water per lb air HR67 = 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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Proposed Condition Summary

Bin Avg. Temp

Total MMBTU

Heat Exchanger MMBTU

Steam MMBTU

2 1 1 <5 7 2 2 <5 12 7 6 <5 17 24 19 <5 22 37 26 11 27 78 57 21 32 266 159 106 37 438 285 152 42 557 362 195 47 584 324 260 52 520 325 195 57 333 154 180 62 193 53 140 67 106 0 106 72 48 0 48 77 16 0 16

Total 3,210 1,773 1,438

The proposed heating cost can now be calculated as: PHC = Proposed Heating Cost = PHE x IC = 1,438 x 106 Btu x $14.40/106 Btu

= $20,700/yr Where, PHE = 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 = Proposed Power = FLP x (.1 + %C3) = 28.1 kW x (.1 + .253) = 3.25 kW

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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 Where, PE = Proposed Electrical Usage = PP x OH = 3.25 kW x 8,760 hrs/yr = 28,500 kWh/yr 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.

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Savings Summary Source Quantity Units $/Unit Savings Steam Energy 4,312 106 Btu $14.40 $62,110 Electrical Energy 217,700 kWh $0.045 $9,800 Total $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 Data Bin Avg.

Temp (°F) MCWB

(°F) Outside Relative

Humidity Relative Humidity

After Heating 2 2 NA <10% 7 7 NA <10% 12 11 NA <10% 17 16 NA <10% 22 21 90% 10% 27 27 100% 11% 32 32 100% 17% 37 36 90% 20% 42 41 90% 23% 47 45 90% 24% 52 49 57% 22% 57 53 78% 35% 62 56 70% 35% 67 58 60% 33% 72 60 50% 35% 77 62 45% 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 Total Cost

40 hp VFD (Installed) 2 $7,900 $15,800

Savings will pay for implementation in approximately 0.2 years.

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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 or 0.25 x TC = Minimum of 217,700 kWh x $0.12/kWh or 0.25 x $15,800 = Minimum of $26,000 or $4,000 = $4,000 Where, 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 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 Cost Pre-incentive Cost $15,800Energy Trust Incentives ($4,000)Business Energy Tax Credit ($3,000)Total After Incentives $8,800

After incentives, savings will pay for implementation in 0.1 years.

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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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Bin Data

Bin Avg. Temp

(F) MCWB

(F)

Outside Relative

Humidity Hours Humidity

Ratio

Specific Volume Ft3/lb

Change In Specific

Enthalpy Current MMBTU

Current Steam

MMBTU

Needed Flow

(ACFM)

Proposed MMBTU at 10,000

CFM

Proposed Steam

MMBTU

2 2 NA 1 NA 11.70 20.0 4 1 NA 1 0

7 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

Total

12,841 5,750 3210 1438 *Note that the actual moisture in local outside air is lower during colder hours (even if the outdoor relative humidity may appear higher).

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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%.


(106Btu) Energy (kWh) Savings Cost (years) 4,052 20,800 $59,200 $108,000 1.8


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. 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

Figure 1: Templifier Heat Pump Photo courtesy of McQuay Please note, we do not endorse specific vendors.

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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.

44oF

50oF47oF

City Water @50oF

Supple-mentary Steam Heater

110oF

Water Tank

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** COP

100% 139.7 176.7 10% 2.875% 104.7 113.3 25% 3.350% 69.8 66.5 25% 3.725% 34.9 28.9 40% 4.3

Average 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

Chilled Water Loop

21

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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 Where, CP1 = Chiller Chilling at 100% Capacity = 139.7 ton CP2 = Chiller Chilling at 75% Capacity = 104.7 ton CP3 = Chiller Chilling at 50% Capacity = 69.8 ton CP4 = Chiller Chilling at 25% Capacity = 34.9 ton RP1 = Annual Running Percentage at 100% Capacity = 10% RP2 = Annual Running Percentage at 75% Capacity = 25% RP3 = Annual Running Percentage at 50% Capacity = 25% RP4 = Annual Running Percentage at 25% Capacity = 40% 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

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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 Where,

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 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

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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 Where, CO = Existing Chiller Part Load COP = 3.8 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 Where, F = Conversion Factor = 1 kWh/3,410 Btu OP = Operation Hours = 8,760 hr/yr IE = Incremental Energy Cost = $0.045/kWh 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:

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OR2000

SC = Steam Cost Savings = ES x IC = 4,052 x 106 Btu/yr x $14.40/106 Btu = $58,300/yr Where, 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 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 Qty Unit $/Unit Cost Chiller Input (243,400) kWh $0.045 ($11,000) Templifier Input 264,200 kWh $0.045 $11,900 Templifier Output 4,052 106 Btu $14.40 $58,300 Savings $59,200

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.

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Implementation Summary Source Total Cost 140 ton Templifier $95,000 2,000 gal water tank $10,000 Ducting and labor $3,000 Total $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 Where, TC = Total Implementation Cost = $108,000 The following table summarizes incentives and net costs.

Incentive Summary Description Cost Pre-incentive Cost $108,000Business Energy Tax Credit ($27,500)Total After Incentives $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

26

OR2000

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.

27

OR2000

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Figure 1: Typical solar pool heating system. Image courtesy of the US Department of Energy.

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 Payback106 Btu Savings Cost (years) 1,293 $18,600 $87,700 4.7


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.

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OR2000

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/ .

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EC = Energy Cost Savings = ES x IC = 1,293 x 106 Btu/yr x $14.40/106 Btu = $18,600/yr Where, 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 Where, SC = Steam Cost = $0.0170/lb h60 = Enthalpy of Steam at 60 psi = 1,180 Btu/lb 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 $/Unit Cost

Solar Collector 588 m2 $60.00 $35,280 Piping Materials 70 m $6.00 $420 Collector Support Structure 588 m2 $50.00 $29,400 Plumbing and Control 1 Project $300 $500 Collector Installation 588 m2 $20 $11,760 Solar Loop Installation 70 m $30 $2,100 Training 4 hours $60 $240 Contingencies 10 % $79,700 $7,970 Total $87,700

Note the following with respect to the above tabulated values:

• 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.

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• 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 Where, TC = Total Implementation Cost = $87,700 The following table summarizes implementation costs before and after incentives.

Incentive Summary Description Cost Pre-incentive Cost $87,700Business Energy Tax Credit ($29,400)Total after Incentives $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

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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.

33

RETScreen® Energy Model - Solar Water Heating Project Training & Support

Site Conditions Estimate Notes/RangeProject name Dixon Rec. Center See Online ManualProject location Corvallis, OregonNearest location for weather data Eugene, OR Complete SR&HL sheetAnnual solar radiation (tilted surface) MWh/m² 1.36Annual average temperature °C 11.3 -20.0 to 30.0Annual average wind speed m/s 3.4Desired load temperature °C 28Hot water use L/d N/ANumber of months analysed month 12.00Energy demand for months analysed MWh 1,102.16

System Characteristics Estimate Notes/RangeApplication type Swimming pool (indoor)

Base Case Water Heating SystemHeating fuel type - Natural gas - mmBtuWater heating system seasonal efficiency % 80% 50% to 190%

Solar CollectorCollector type - Evacuated See Technical Note 1Solar water heating collector manufacturer ABC S.A. See Product DatabaseSolar water heating collector model model XYZGross area of one collector m² 4.00 1.00 to 5.00Aperture area of one collector m² 4.00 1.00 to 5.00Fr (tau alpha) coefficient - 0.85 0.40 to 0.80 Wind correction for Fr (tau alpha) s/m 0.000 0.030 to 0.050Fr UL coefficient (W/m²)/°C 11.56 0.30 to 3.00 Wind correction for Fr UL (J/m³)/°C 0.00 3.00 to 15.00 Temperature coefficient for Fr UL (W/(m?°C)²) 0.00 0.000 to 0.010Suggested number of collectors 147Number of collectors 147Total gross collector area m² 588.0

StorageRatio of storage capacity to coll. area L/m² 45.9 37.5 to 100.0Storage capacity L 26,989

Balance of SystemHeat exchanger/antifreeze protection yes/no YesHeat exchanger effectiveness % 80% 50% to 85%Suggested pipe diameter mm 31 8 to 25 or PVC 35 to 50Pipe diameter mm 38 8 to 25 or PVC 35 to 50Pumping power per collector area W/m² 0 3 to 22, or 0Piping and solar tank losses % 1% 1% to 10%Losses due to snow and/or dirt % 3% 2% to 10%Horz. dist. from mech. room to collector m 20 5 to 20# of floors from mech. room to collector - 3 0 to 20

Annual Energy Production (12.00 months analysed) Estimate Notes/RangeSWH system capacity kWth 412

million Btu/h 1.404Pumping energy (electricity) MWh 0.00Specific yield kWh/m² 645System efficiency % 47%Solar fraction % 34%Renewable energy delivered MWh 379.00

million Btu 1,293.21Complete Cost Analysis sheet

34

RETScreen® Solar Resource and Heating Load Calculation - Solar Water Heating Project

Site Latitude and Collector Orientation Estimate Notes/RangeNearest location for weather data Eugene, ORLatitude of project location °N 44.1 -90.0 to 90.0Slope of solar collector ° 0.0 0.0 to 90.0Azimuth of solar collector ° 0.0 0.0 to 180.0

Monthly Inputs

Month

Fraction of

monthused

(0 - 1)

Monthly average

daily radiationon horizontal

surface(kWh/m²/d)

Monthly average

temperature

(°C)

Monthly averagerelative

humidity(%)

Monthly average

wind speed

(m/s)

Monthly average

daily radiationin plane of

solar collector(kWh/m²/d)

January 1.00 1.27 4.4 86.9 3.5 1.27February 1.00 1.97 6.1 84.8 3.5 1.97

March 1.00 3.14 7.9 79.8 3.7 3.14April 1.00 4.39 9.8 75.7 3.5 4.39May 1.00 5.55 12.9 73.0 3.4 5.55

June 1.00 6.21 16.5 69.0 3.4 6.21July 1.00 6.73 19.3 62.4 3.6 6.73

August 1.00 5.83 19.3 64.1 3.4 5.83September 1.00 4.42 16.3 69.0 3.4 4.42

October 1.00 2.70 11.5 80.8 3.0 2.70November 1.00 1.42 7.4 87.5 3.4 1.42December 1.00 1.05 4.7 88.8 3.5 1.05

Annual Season of UseSolar radiation (horizontal) MWh/m² 1.36 1.36Solar radiation (tilted surface) MWh/m² 1.36 1.36Average temperature °C 11.3 11.3Average wind speed m/s 3.4 3.4

Water Heating Load Calculation Estimate Notes/RangeApplication type - Swimming poolSystem configuration - With storage

Building or load type - Industrial Building or load type - Industrial Number of units - - Rate of occupancy % - 50% to 100% Estimated hot water use (at ~6 L/d N/A Hot water use L/d 12,000 Desired water temperature °C 60 Days per week system is used d 7 1 to 7 Type of pool - Indoor

Pool area m2 585 20 to 1,000 Use of cover h/d 0 0 to 24 Desired pool temperature °C 27.8 22 to 35 Makeup water ratio %/wk 5% 5% to 10% Wind sheltering coefficient - - 0.10 to 0.30 Pool shading factor % - 0% to 50%Cold water temperature - Auto Minimum °C 8.9 1.0 to 10.0 Maximum °C 14.1 5.0 to 15.0Months SWH system in use month 12.00Energy demand for months analy MWh 1,102.16

million Btu 3,760.57

See Weather Database

(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).

Return to Energy Model sheet

35

RETScreen® Cost Analysis - Solar Water Heating Project

Type of project: Pre-feasibility Currency: USA USD Cost references: NoneSecond currency: USA USD Rate: USD/USD 1.47730

Initial Costs (Credits) Unit Quantity Unit Cost Amount Relative Costs Quantity Range Unit Cost RangeFeasibility Study

Site investigation p-h 2 40USD 80USD - -Preliminary design p-h 0 -USD -USD - -Report preparation p-h 0 -USD -USD - -Travel and accommodation p-trip 0 -USD -USD - -Other - Feasibility study Cost 0 -USD -USD - -

Sub-total : -USD 0.0%Development

Permits and approvals p-h 2 40USD 80USD - -Project financing p-h 0 -USD -USD - -Project management p-h 0 -USD -USD - -Travel and accommodation p-trip 0 -USD -USD - -Other - Development Cost 0 -USD -USD - -

Sub-total : -USD 0.0%Engineering

SWH system design p-h 6 40USD 240USD - -Structural design p-h 1 40USD 40USD - -Tenders and contracting p-h 0 -USD -USD - -Construction supervision p-h 0 -USD -USD - -Other - Engineering Cost 0 -USD -USD - -

Sub-total : -USD 0.0%Energy Equipment

Solar collector m² 588.0 60USD 35,280USD - -Solar storage tank L 0 -USD -USD - -Solar loop piping materials m 70 6.00USD 420USD - -Circulating pump(s) W 0 -USD -USD - -Heat exchanger kW 352.8 -USD -USD - -Transportation project 0 -USD -USD - -Other - Energy equipment Cost 0 -USD -USD - -

Credit 0 -USD -USD - -Sub-total : 35,700USD 40.7%

Balance of SystemCollector support structure m² 588.0 50USD 29,400USD - -Plumbing and control project 1 500USD 500USD - -Collector installation m² 588.0 20USD 11,760USD - -Solar loop installation m 70 30.00USD 2,099USD - -Auxiliary equipment installation project 1 -USD -USD - -Transportation project 1 -USD -USD - -Other - Balance of system Cost 0 -USD -USD - -

Sub-total : 43,759USD 49.9%Miscellaneous

Training p-h 4 60USD 240USD - -Contingencies % 10% 79,699USD 7,970USD - -

Sub-total : 8,210USD 9.4%Initial Costs - Total 87,668USD 100.0%

Annual Costs (Credits) Unit Quantity Unit Cost Amount Relative Costs Quantity Range Unit Cost RangeO&M

Property taxes/Insurance project 0 -USD -USD - -O&M labour project 1 15USD 15USD - -Other - O&M Cost 0 -USD -USD - -Contingencies % 10% 15USD 2USD - -

Sub-total : 17USD 100.0%Electricity kWh 0 -USD -USD 0.0% - -

Annual Costs - Total 17USD 100.0%

Periodic Costs (Credits) Period Unit Cost Amount Interval Range Unit Cost RangeValves and fittings Cost 10 yr 250USD 250USD - -Pool heat pump compressor Credit 10 yr 1,200USD (1,200)USD - -

-USD - -End of project life - -USD Go to GHG Analysis sheet

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OR02000

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 = Current Cost = (TRT + TWT) x CT x T = (35 + 7) dozen/term x $28.50/dozen x 4 terms/yr = $4,790/yr Where, TRT = Towels Removed per Term = 35 dozen/term

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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) Where, I = Total Towel Inventory = 70 dozen 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 Where, PD = Percent of Towels Discarded Due to Wear and Tear = 20% PR = Percent Reduction After 10% Removal = 100% - 10% = 90% The total proposed cost to replace towels is calculated as: PTC = 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

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Total savings are a function of the fee amount imposed per removed towel. Total savings can be calculated as follows:

TS = 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) Where, FPT = 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 $806 $1,428 $3,361 $2.50 $840 $1,395 $3,395 $3.00 $1,008 $1,227 $3,563 $3.50 $1,176 $1,059 $3,731 $4.00 $1,344 $891 $3,899 $4.50 $1,512 $723 $4,067 $5.00 $1,680 $555 $4,235 $5.50 $1,848 $387 $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.

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Savings Summary

Worn

Towels Removed Towels

Towel Cost Fees

Total Cost

Existing 336 1,680 $4,788 0 $4,788 Proposed 605 336 $2,234 $1,680 $554 Savings (269) 1,344 $2,554 $1,680 $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 TotalTech Support 1 hour $30 $30 Flier design 10 hours $10 $100 Flier Prints Permanent Sign

20 prints 1 print

$0.25$100

$5$100

Total $235 Savings pay for implementation almost immediately.

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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) Savings Cost (years) 67,200 $4,040 $13,500 3.3

Estimated Incentive Summary ETO1 BETC2 Net Net Payback

Incentive Tax Credit Cost (years) $3,400 $3,100 $7,000 1.8

1 Energy Trust of Oregon Incentive 2 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.

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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 Where, NF = Number of Fixtures = 48 fixtures FW = Fixture Input Wattage = 458 watts/fixture Proposed power use is calculated as: PP = Proposed Power = NF x PW = 48 fixtures x 370 watts/fixture = 18 kW Where, PW = Proposed Input Wattage = 370 watts/fixture Energy savings associated with reduced operating hours are calculated as: 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

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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 Where, IC = Incremental Energy Cost = $0.045/kWh 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 Quantity UnitsEnergy

(106 Btu) Savings Energy 67,200 kWh 230 $3,000 Maintenance Labor $50 Maintenance Materials $990 Total 230 $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.

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Fixture costs are calculated as: CF = Cost of Fixtures = NF × CF = 48 fixtures × $231/fixture = $11,100 Where, CF = Cost per Fixture = $231/fixture 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 Where, IT = Installation Time = 1 hr/fixture EW = Electrician Wage = $50/hr


T5 High Output Fixtures with Integrated Motion Sensors

48 Fixtures $231 $11,100

Electrician Labor 48 Hours $50 $2,400 Total $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 = Energy Trust of Oregon Cash Incentive = Minimum of ES x $0.12/kWh or 0.25 x TC = Minimum of 67,200 kWh x $0.12/kWh or 0.25 x $13,500 = Minimum of $8,100 or $3,400 = $3,400

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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 pass-through 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 Cost Pre-incentive Cost $13,500 Energy Trust Incentives ($3,400) Business Energy Tax Credit ($3,100)Total After Incentives $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.

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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%.




ETO1 BETC2 Net Net Payback Incentive Tax Credit Cost (years)

$875 $800 $1,800 1.4 1 Energy Trust of Oregon Incentive 2 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:

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Lighting Inventory Area Fixture Number Watts/Fixture HoursStevens Natatorium 4 ft T8 Electric Ballast 45 34 5,600 West Lobby 2 Lamp CFL 15 84 5,600 West Vestibule Entrance 42 watt CFL 4 42 5,600 Main West Hallway 42 watt CFL 17 42 5,600 East Vestibule Entrance 42 watt CFL 4 42 5,600 East Lobby 42 watt CFL 6 42 5,600 East Entrance 42 watt CFL 5 42 5,600 2nd Story West Hallway 42 watt CFL 30 42 5,600 2nd Story West Hallway 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 Where, CF = Current Number of Four Foot T8 Fixtures = 45 fixtures CW = Current Fixture Input Wattage = 34 watts/fixture Energy savings due to reduced operating hours are calculated as: ES = Energy Savings = CP × (CH – PH) = 1.53 kW × (5,600 hrs/yr – 3,000 hrs/yr) = 4,000 kWh/yr

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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 Where, EC = Incremental Energy Cost = $0.045 /kWh 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 Quantity Units (106 Btu) Savings Energy 15,350 kWh 50 $680 Maintenance Labor $130 Maintenance Materials $510 Total 50 $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.

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CS = Material Cost of Sensors = (NS × CPS) + (NCU × CPC) = (2 sensors × $150/sensor) + (1 controller × $50/controller) = $350 Where, 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 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 Where, IT = Installation Time = 2 hrs/sensor EW = Electrician Wage = $50/hr 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.

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Photo Sensors 10 Sensors $150 $1,500 Electrician Labor 20 Hours $50 $1,000 Lighting Control System Upgrade $1,000 Total $3,500

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 or 0.25 x TC = Minimum of 15,350 kWh x $0.12/kWh or 0.25 x $3,500 = Minimum of $1,800 or $875 = $875 Where, TC = Total Implementation Cost = $3,500 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 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 pass-through 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.

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Incentive Summary Description Cost Pre-incentive Cost $3,500 Energy Trust Incentives ($875) Business Energy Tax Credit ($800)Total After Incentives $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.

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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.


Energy (kWh) Savings Cost (years) 9,315 $540 $7,200 13.3


ETO1 BETC2 Net Net Payback Incentive Tax Credit Cost (years) $3,800 $1,000 $2,400 4.4

1 Energy Trust of Oregon Incentive 2 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:

• Number of racquetball courts: 7 courts • Number of squash courts: 2 courts

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• 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 = Current Power = CW x NF = 87 watts/fixture x 21 fixtures = 1.827 kW Where, CW = Current Input Wattage = 87 watts/fixture NF = 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 Where, PW = Proposed Input Wattage = 58 watts/fixture 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 Where, OH = Operating Hours = 1,700 hrs/yr Total energy savings for all nine courts is therefore 9,315 kWh per year.

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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 Where, IC = Incremental Energy Charge = $0.045/kWh 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 (106 Btu) Savings Energy 1,035 kWh 4 $50 Lamp Replacement Savings $10 Total per Court 4 $60 Total For All Courts $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 = Installation Material Costs = BC x NB + LC x NL = $25/ballast x 21 ballasts + $1.80/lamp x 42 lamps = $525 + $75 = $600

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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 Where, IT = Installation Time = 0.5 hrs IW = Maintenance Wage = $20/hr

Implementation Summary per Court Source Quantity Units $/Unit Cost

T8 Programmed Start Ballasts 21 Ballast $25.00 $525 Four foot T8 Lamps 42 Lamp $1.80 $75 Maintenance Labor 10 Hour $20.00 $200 Total per Court $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:

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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 pass-through 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 Where, TC = Total Implementation Cost = $7,200 The following table summarizes incentives and net costs..

Incentive Summary Description Cost Pre-incentive Cost $7,200Energy Trust Incentives ($3,800)Business Energy Tax Credit ($1,000)Total After Incentives $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.

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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%.



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 Mfr Type Refrigerant Full Load Amps (A)

Compressor 1 McQuary Single Screw R22 111 Compressor 2 McQuary Single Screw R22 139

Total 250

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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:

Chiller Part Load Performance Load Percentage* Capacity (ton) Power (kW) Energy Efficiency Ratio

100% 139.7 176.7 9.675% 104.7 113.3 11.250% 69.8 66.5 12.725% 34.9 28.9 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.

Chiller Load Profile Estimation Load Percentage Power (kW) Annual Percentage of Time

100% 176.7 10%75% 113.3 25%50% 66.5 25%25% 28.9 40%

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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 Where, 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%

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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 Where, AB = Annual Bin Hours = 800 hrs/yr ET = Existing Condensing Temperature = 90°F PT = Proposed Condensing Temperature = 82°F SF = Savings Factor = 1% /°F 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 = 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 Where, WV = Working Voltage = 460 Volts

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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 Where, PH = Proposed Operating Hours = 318 hrs/yr EH = Existing Operating Hours = 445 hrs/yr 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 = Energy Cost Savings = ES x IE = 56,800 kWh/yr x $0.045/kWh = $2,600/yr

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Where, IE = Incremental Energy Cost = $0.045/kWh The following table compares resulting savings found by reducing discharge pressure.

Energy Summary Source

Compressor Energy

(kWh) Fan Energy

(kWh) Total Energy

(kWh) Existing 724,000 165,100 889,100 Proposed 672,600 159,700 832,300 Savings 51,400 5,400 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 Total Cost Initial Scale Analysis 1 $100 $100 Chemical Descaling 1 $2,500 $2,500 Total $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.

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CHILLER ENERGY SAVINGS

Application: Refrigeration Refrigerant: R22Buildings: Dixon Roof Energy Cost (E$): $0.04400 /kWhBin Data: OR Annual Hours: 8,760

Operating Conditions Existing Proposed Savings UnitsMinimum Condensing Temperature (Tm): 60 60 0 °FApproach Temperature Difference (DT): 28 20 8 °FCompressor Energy (EC): 724,000 672,600 51,400 kWh/yrCondenser Fan Horsepower (Hp): 15 15 0.0 hpFan Power (FP): 19.0 19.0 0.0 kWAverage Fan Use Factor (UFe): 99.4% 96.1% 3.2%Fan Energy (FE): 165,100 159,700 5,400 kWhTotal Energy Usage: 889,100 832,300 56,800 kWhTotal Energy Cost: $39,120 $36,620 $2,500

Bin CalculationExist Prop Compressor Fan Total

Dry Cond Cond Deg-hr Savings Savings Increase SavingsBulb Hours Temp Temp Savings % kWh kWh kWh(Tdb) (H) (Tce) (Tcp) (DHS) (E%) (CES) (FEI) (ES)

107 0 135 127 0 0.0% 0 0 0102 2 130 122 16 0.0% 13 0 1397 12 125 117 96 0.0% 79 0 7992 41 120 112 328 0.0% 271 0 27187 85 115 107 680 0.1% 562 0 56282 161 110 102 1,288 0.1% 1,065 0 1,06577 249 105 97 1,992 0.2% 1,646 0 1,64672 365 100 92 2,920 0.3% 2,413 0 2,41367 509 95 87 4,072 0.5% 3,365 0 3,36562 800 90 82 6,400 0.7% 5,289 0 5,28957 1,110 85 77 8,880 1.0% 7,339 0 7,33952 1,388 80 72 11,104 1.3% 9,177 0 9,17747 1,402 75 67 11,216 1.3% 9,270 0 9,27042 1,179 70 62 9,432 1.1% 7,795 0 7,79537 747 65 60 3,735 0.4% 3,087 (1,848) 4,93532 445 60 60 0 0.0% 0 (2,411) 2,41127 166 60 60 0 0.0% 0 (763) 76322 63 60 60 0 0.0% 0 (251) 25117 24 60 60 0 0.0% 0 (84) 8412 8 60 60 0 0.0% 0 (25) 25

7 1 60 60 0 0.0% 0 (3) 32 1 60 60 0 0.0% 0 (2) 2

-3 1 60 60 0 0.0% 0 (2) 2-8 1 60 60 0 0.0% 0 (2) 2

-13 0 60 60 0 0.0% 0 0 0 Totals 8,760 62,000 7.1% 51,400 (5,400) 56,800

Energy and Cost SavingsCompressor Energy Savings (CES): 51,400 kWh/yrFan Energy Increase (FEI): (5,400) kWh/yrTotal Energy Savings (ES): 56,800 kWh/yrTotal Cost Savings (CS): $2,500 /yrImplementation Cost (IC): $2,600Simple Payback: 1.0 years

63

OR2000

ExistingModel TR Quantity Hp Total Hp Power (kW)

McQuary ALS150 150 10 1.5 15 19.0

Totals 150 15 19.0

ProposedModel TR Quantity Hp Total Hp Power (kW)

McQuary ALS150 150 10 1.5 15 19.0

Totals 150 15 18.961936

Existing Proposed Existing Proposed Existing Proposed ProposedDry Fan Use Fan Use Operating Operating Fan Fan VFD FanBulb Per Bin Per Bin Hours Per Hours Per Energy Energy Energy(Tdb) Temp Temp Bin Temp Bin Temp kWh kWh kWh

107 100% 100% 0 0 0 0 0102 100% 100% 2 2 38 38 38

97 100% 100% 12 12 228 228 22892 100% 100% 41 41 777 777 77787 100% 100% 85 85 1,612 1,612 1,61282 100% 100% 161 161 3,053 3,053 3,05377 100% 100% 249 249 4,722 4,722 4,72272 100% 100% 365 365 6,921 6,921 6,92167 100% 100% 509 509 9,652 9,652 9,65262 100% 100% 800 800 15,170 15,170 15,17057 100% 100% 1,110 1,110 21,048 21,048 21,04852 100% 100% 1,388 1,388 26,319 26,319 26,31947 100% 100% 1,402 1,402 26,585 26,585 26,58542 100% 100% 1,179 1,179 22,356 22,356 22,35637 100% 87% 747 650 14,165 12,317 9,31332 100% 71% 445 318 8,438 6,027 3,07527 85% 61% 141 101 2,671 1,908 70122 74% 53% 46 33 880 629 17417 65% 47% 16 11 296 212 4612 58% 42% 5 3 88 63 117 53% 38% 1 0 10 7 12 48% 34% 0 0 9 7 1

-3 44% 32% 0 0 8 6 1-8 41% 29% 0 0 8 6 1

-13 38% 27% 0 0 0 0 0 Totals 8,704 8,420 165,100 159,700 151,800 AVERAGE UF 99.4% 96.1%

CONDENSER SUMMARY

Mfr

MfrFan Motors

Fan Motors

64

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)

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

Ө

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.

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• 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.

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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 3,413 Btu 1 MWh 3,413,000 Btu 1 cubic foot of natural gas 1,030 Btu 1 gallon of No. 2 oil (diesel) 140,000 Btu 1 gallon of No. 6 oil 152,000 Btu 1 gallon of gasoline 128,000 Btu 1 gallon of propane 91,600 Btu 1 pound of dry wood 8,600 Btu 1 bone dry ton of wood (BDT) 17,200,000 Btu 1 unit of wood sawdust (2,244 dry pounds) 19,300,000 Btu 1 unit of wood shavings (1,395 dry pounds) 12,000,000 Btu 1 unit of hogged wood fuel (2,047 dry pounds) 17,600,000 Btu 1 ton of coal 28,000,000 Btu 1 MWh 1,000 kWh 1 therm 100,000 Btu 1 MMBtu 1,000,000 Btu 1 106Btu 1,000,000 Btu

1 kilowatt 3,413 Btu/hr 1 horsepower (electric) 2,546 Btu/hr 1 horsepower (boiler) 33,478 Btu/hr 1 ton of refrigeration 12,000 Btu/hr

Unit Equivalent

1 gallon of water 8.33 pounds 1 cubic foot of water 7.48 gallons 1 kgal 1,000 gallons 1 unit wood fuel 200 ft3

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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.

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A.3. Energy Accounting

Electrical Energy UseFACILITIES SERVICESElectrical Meter BillsFY2007

The three tabulated values given for each month represent (top to bottom) the three Dixon electricalmeters: 145-Dixon Master Reader, 053-813-BI, 127-Tennis.

KWH Used Cost KWH Used Cost KWH Used Cost KWH Used Cost176,271 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

KWH Used Cost KWH Used Cost KWH Used Cost KWH Used Cost206,252 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

Nov-06 Dec-06 Jan-07 Feb-07

Jul-06 Aug-06 Sep-06 Oct-06

, , , ,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

KWH Used Cost KWH Used Cost KWH Used Cost KWH Used Cost203,183 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 SummaryTotal kWh 2,618,460Total Cost $117,186Average Cost per kWh $0.04475

Mar-07 Apr-07 May-07 Jun-07

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0

50,000

100,000

150,000

200,000

250,000

300,000

Kilo

wat

t Hou

rsElectrical Energy Use

$0.00

$2,000.00

$4,000.00

$6,000.00

$8,000.00

$10,000.00

$12,000.00

Dol

lars

Electrical Energy Cost

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Steam UseFACILITIES SERVICESSteam Meter BillsFY2007 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).

Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs384,500 6,536.50 35,900 610.30 73,100 1,242.70 290,900 4,945.30

0 - 0 - 0 - 0 - 384,500 $6,537 35,900 $610 73,100 $1,243 290,900 $4,945

Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs944,400 16,054.80 2,398,500 40,774.50 2,725,400 46,331.80 2,246,400 38,188.80

0 - 300 5.10 100 1.70 100 1.70

Jul-06 Aug-06 Sep-06 Oct-06

Jan-07 Feb-07Nov-06 Dec-06

0 300 5.10 100 1.70 100 1.70 944,400 $16,055 2,398,800 $40,780 2,725,500 $46,334 2,246,500 $38,191

Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs Lbs Used Cost/1000lbs2,024,200 34,411.40 1,966,600 33,432.20 1,254,700 21,329.90 824,300 14,013.10

0 - 100 1.70 0 - -100 (1.70) 2,024,200 $34,411 1,966,700 $33,434 1,254,700 $21,330 824,200 $14,011

Steam Usage SummaryTotal lbs 15,169,400Total MMBTU 17,900Total Cost $257,880Average Cost per lb $0.017

Mar-07 Apr-07 May-07 Jun-07

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0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

Poun

ds o

f Ste

amSteam Use

$‐

$5,000.00

$10,000.00

$15,000.00

$20,000.00

$25,000.00

$30,000.00

$35,000.00

$40,000.00

$45,000.00

$50,000.00

Dol

lars

Steam Cost

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$‐

$10,000.00

$20,000.00

$30,000.00

$40,000.00

$50,000.00

$60,000.00

Dol

lars

Total Energy Cost

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Water and SewerFACILITIES SERVICESCity of Corvallis--Water/Sewer Meter BillingFY2007Water 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).

Consum 23010 23012 Consum 23010 23012 Consum 23010 23012(ccf) Water$ Sew$ Total$ (ccf) Water$ Sew$ Total$ (ccf) Water$ Sew$ Total$

313 476.58 1,033.69 1,510.27 256 388.23 858.13 1,246.36 309 470.38 1,021.37 1,491.75 0 8.00 - 8.00 0 8.00 - 8.00 0 8.00 - 8.00 0 4.00 - 4.00 0 4.00 - 4.00 0 4.00 - 4.00

313 $489 $1,034 $1,522 256 $400 $858 $1,258 309 $482 $1,021 $1,504

Consum 23010 23012 Consum 23010 23012 Consum 23010 23012( f) Water$ Sew$ Total$ ( f) Water$ Sew$ Total$ ( f) Water$ Sew$ Total$

Jul-06 Aug-06 Sep-06

Oct-06 Nov-06 Dec-06

(ccf) Water$ Sew$ Total$ (ccf) Water$ Sew$ Total$ (ccf) Water$ Sew$ Total$524 803.63 1,683.57 2,487.20 422 645.53 1,369.41 2,014.94 302 459.53 999.81 1,459.34

0 8.00 - 8.00 0 8.00 - 8.00 0 8.00 - 8.00 0 4.00 - 4.00 0 4.00 - 4.00 0 4.00 - 4.00

524 $816 $1,684 $2,499 422 $658 $1,369 $2,027 302 $472 $1,000 $1,471


518 850.92 1,717.18 2,568.10 564 927.28 1,863.46 2,790.74 395 646.74 1,326.04 1,972.78 0 8.00 - 8.00 0 8.00 - 8.00 0 8.00 - 8.00 0 4.00 - 4.00 0 4.00 - 4.00 0 4.00 - 4.00

518 $863 $1,717 $2,580 564 $939 $1,863 $2,803 395 $659 $1,326 $1,985


522 857.56 1,729.90 2,587.46 514 844.28 1,704.46 2,548.74 330 538.84 1,119.34 1,658.18 0 8.00 - 8.00 0 8.00 - 8.00 0 8.00 - 8.00 0 4.00 - 4.00 0 4.00 - 4.00 0 4.00 - 4.00

522 $870 $1,730 $2,599 514 $856 $1,704 $2,561 330 $551 $1,119 $1,670

Water Billing Summary Sewer Billing SummaryTotal Consumption (ccf) 4,969 Total Consumption (ccf) 4,969Total Cost $8,054 Total Cost $16,426Average Cost per ccf $1.62 Average Cost per ccf $3.31

Jan-07 Feb-07

Apr-07 May-07

Mar-07

Jun-07

76

0

100

200

300

400

500

600

Hun

dred

Cub

ic F

eet

Water Consumption

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

Dol

lars

Water Cost

77

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

Dol

lars

Sewer Cost

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Dol

lars

Total Water and Sewer Cost

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

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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

Number of Fixtures 48

Hours 1400

Lamps/Fixture 6


Hours 4200

Output Factor 100%Output Factor 100%

Lamps/Fixture 1

Ballasts/Fixture 1 Ballasts/Fixture 1

Fixture Cost $195.00Fixture Cost $139.75

Replace Tennis Pavilion Fixtures

Description 400 Watt Clear Met. Hal.

Quantity: 48

Life 20000

Lamp Cost $80.35

Watts per Lamp 400

Lumens 30000

Replacement Fraction 21.00%

Annual Replacement Cost $809.93

Annual Maintenance Labor Cost $25.20

Description 54 Watt T5 HO

Quantity: 288

Life 30000

Lamp Cost $6.00

Watts per Lamp 54

Lumens 5000


Annual Lamp Replacement Cos $80.64


Description 400 watt Metal Halide

Quantity 48

Life 60000

Ballast Cost $119.20

Ballast Factor 100.00%

Input Watts 458




Description 46" T5

Quantity 48

Life 72000

Ballast Cost $150.00

Ballast Factor 100.00%

Input Watts 370




Area Lumens 1440000 Area Lumens 1440000

Footcandles 40 Footcandles 40

Lighting Efficiency 35 Lighting Efficiency 43.2

Power Use 21.984

Energy Use 92332.8

Power Use 17.76

Energy Use 24864

Demand Cost $0 Demand Cost $0

Energy Cost $4,099.58 Energy Cost $1,103.96

Maintenance Material Cost $1,210.44 Maintenance Material Cost $220.64

Maintenance Labor Cost $109.20 Maintenance Labor Cost $56.93

Total Operating Cost $5,419.22 Total Operating Cost $1,381.53

Implementation Costs Materials $11,088

Labor $2,400

4.224

67469

$990

$52

Saved

Simple Payback 3.3

Total Implementation Cost $13,488

$4,038

Building: Tennis Pavillion

Area: Tennis Pavilion

Ballast

Lamps Lamps

Ballast

Fixture Replacement Time: 60 minutes

Lamp Replacement Time: 10 minutes

Ballast Replacement Time: 30 minutes

Maintenance Labor Rate: $15

Electrician Labor Rate: $50

Incremental Energy Cost: $0.0444 /kW Incremental Demand Cost $0 /kW

Existing Fixtures Proposed FixturesMetal Halide 45" T5 HO with Motion Sensor

$0

$2,996

OR200085


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1



Turn off Lights Near Entrances, Windows and Skylights

Description 4 Ft T8 C.T.

Quantity: 45

Life 20000

Lamp Cost $1.89

Watts per Lamp 32

Lumens 2710





Quantity: 45

Life 20000

Lamp Cost $1.89

Watts per Lamp 32

Lumens 2710




Description 4 Ft F32T8

Quantity 45

Life 75000

Ballast Cost $36.75

Ballast Factor

Input Watts 34





Quantity 45

Life 75000

Ballast Cost $36.75

Ballast Factor

Input Watts 34





Footcandles 22 Footcandles 21.7

Lighting Efficiency 625 Lighting Efficiency 617.7

Power Use 1.53

Energy Use 8568

Power Use 1.53

Energy Use 4590


Energy Cost $380.42 Energy Cost $203.80

Maintenance Material Cost $147.29 Maintenance Material Cost $78.91


Total Operating Cost $643.21 Total Operating Cost $344.58

Implementation Costs Materials $0

Labor $0

0

3978

$68

$54

Saved

Simple Payback 0

Total Implementation Cost $0

$299

Building: Dixon Rec Center

Area: Steven Natatorium

Ballast

Lamps Lamps

Ballast







Existing Fixtures Proposed Fixtures4 Ft T8 Elec 4 Ft T8 Elec

$0

$177

OR200086


Hours 3000

Lamps/Fixture 2


Hours 5600


Lamps/Fixture 2




Description 42 Watt Compact Fluor.

Quantity: 30

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 30

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts

Replacement Fraction



Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts






Lighting Efficiency 54.2 Lighting Efficiency 54.2

Power Use 1.26

Energy Use 7056

Power Use 1.26

Energy Use 3780







Labor $0

0

3276

$133

$20

Saved

Simple Payback 0


$297


Area: West Lobby

Ballast

Lamps Lamps

Ballast







Existing Fixtures Proposed Fixtures2 Lamp CFL Fixture 2 Lamp CFL Fixture

$0

$145

OR200087


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 4

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 4

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275




Description No Ballast Needed

Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts




Area Lumens Area Lumens

Footcandles 150 Footcandles

Lighting Efficiency Lighting Efficiency

Power Use 0.168

Energy Use 940.8

Power Use 0.168

Energy Use 504







Labor $0

0

437

$18

$3

Saved

Simple Payback 0


$40


Area: West Vestibule Entrance

Ballast

Lamps Lamps

Ballast







Existing Fixtures Proposed FixturesCFL for 135 Watt Incand. CFL for 135 Watt Incand.

$0

$19

OR200088


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 17

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 17

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts




Area Lumens 116530 Area Lumens


Lighting Efficiency 163.2 Lighting Efficiency

Power Use 0.714

Energy Use 3998.4

Power Use 0.714

Energy Use 2142







Labor $0

0

1856

$75

$11

Saved

Simple Payback 0


$169


Area: Main West Hallway

Ballast

Lamps Lamps

Ballast








$0

$82

OR200089


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 4

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 4

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts







Power Use 0.168

Energy Use 940.8

Power Use 0.168

Energy Use 504







Labor $0

0

437

$18

$3

Saved

Simple Payback 0


$40


Area: East Vestibule Entrance

Ballast

Lamps Lamps

Ballast








$0

$19

OR200090


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 6

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 6

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts




Area Lumens 27100 Area Lumens


Lighting Efficiency 107.5 Lighting Efficiency

Power Use 0.252

Energy Use 1411.2

Power Use 0.252

Energy Use 756







Labor $0

0

655

$27

$4

Saved

Simple Payback 0


$59


Area: East Lobby

Ballast

Lamps Lamps

Ballast








$0

$29

OR200091


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 5

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 5

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts




Area Lumens Area Lumens


Lighting Efficiency Lighting Efficiency

Power Use 0.21

Energy Use 1176

Power Use 0.21

Energy Use 630







Labor $0

0

546

$22

$3

Saved

Simple Payback 0


$50


Area: East Entrance

Ballast

Lamps Lamps

Ballast








$0

$24

OR200092


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 30

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity: 30

Life 10000

Lamp Cost $16.99

Watts per Lamp 42

Lumens 2275





Quantity 0

Life 1000000

Ballast Cost $0.00

Ballast Factor

Input Watts




Description

Quantity 0

Life

Ballast Cost

Ballast Factor

Input Watts






Lighting Efficiency 79.6 Lighting Efficiency 43

Power Use 1.26

Energy Use 7056

Power Use 1.26

Energy Use 3780







Labor $0

0

3276

$133

$20

Saved

Simple Payback 0


$297


Area: 2nd Story West Hallway

Ballast

Lamps Lamps

Ballast








$0

$145

OR200093


Hours 3000

Lamps/Fixture 1


Hours 5600


Lamps/Fixture 1





Quantity: 10

Life 20000

Lamp Cost $1.89

Watts per Lamp 32

Lumens 2710





Quantity: 10

Life 20000

Lamp Cost $1.89

Watts per Lamp 32

Lumens 2710





Quantity 10

Life 75000

Ballast Cost $36.75

Ballast Factor

Input Watts 34





Quantity 10

Life 75000

Ballast Cost $36.75

Ballast Factor

Input Watts 34







Power Use 0.34

Energy Use 1904

Power Use 0.34

Energy Use 1020







Labor $0

0

884

$15

$12

Saved

Simple Payback 0


$66


Area: 2nd Story West Hallway

Ballast

Lamps Lamps

Ballast







Existing Fixtures Proposed Fixtures4 Ft T8 Elec 4 Ft T8 Elec

$0

$39

OR200094

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 = Larger [ Tme, T + DTe ] Tcp = Larger [ Tmp, T + DTp ] where, T = Twb, wet bulb for wet or evaporative condensers = Tdb, dry bulb for air cooled condensers 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 where, HT = Total annual bin hours: 8,760 hr/yr 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

Dixon Recreation Center

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