Industrial Assessment Report

For

Any Plant Your Address

INDUSTRIAL ASSESSMENT CENTER

OREGON STATE UNIVERSITY INDUSTRIAL ASSESSMENT CENTER

Sponsored by U.S. Department of Energy

Managed by Office of Industrial Productivity and Energy Assessment

Rutgers University New Jersey

Assessment Report No. ###

Month, Year

Dr. George Wheeler, IAC Director ________________________________ Principal Auditor ________________________________ Lead Analyst ________________________________ Waste Analyst ________________________________ Waste Analyst ________________________________ Energy Analyst ________________________________ Productivity Analyst ________________________________

Dr. George Wheeler IAC Director Batcheller Hall 344 Corvallis, OR 97331-2405 (541) 737-2515

Dr. John Shea Assistant Director Covell Hall 118 Corvallis, OR 97331-2407 (541) 737-3342

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 U.S. Department of Energy with project management provided by the Office of Industrial Productivity and Energy Assessment, Rutgers University, New Jersey. 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, Office of Industrial Productivity and Energy Assessment, 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. General Background ......................................................................................................... 5 3.1. Facility Description.................................................................................................... 5 3.2. Process Description 3.3. Operating Schedule .................................................................................................... 9 4. Energy Use Summary & Energy Accounting ................................................................. 10 5. Assessment Recommendations ....................................................................................... 24 AR No. 1. Reduce Tolerances on Cutter................................................................ 24 Student AR No. 2. Reduce Paint/Solvent............................................................................ 27 Student AR No. 3. Reduce Coolant Use ............................................................................. 30 Student AR No. 4. Dewater Coolant ................................................................................... 33 Student AR No. 5. Tune Boiler ........................................................................................... 37 Student AR No. 6. Replace Incandescent Fixtures ............................................................. 41 Student AR No. 7. Insulate Walls ....................................................................................... 44 Student AR No. 8. Improve Power Factor .......................................................................... 46 Student AR No. 9. Quick-change Pattern Shop .................................................................. 51 Student AR No. 10. Automate Pattern Shop......................................................................... 54 Student AR No. 11. Retail Line Case Erector....................................................................... 56 Student 6. Other Measures Considered ............................................................................................ 61 OMC No. 1. Install metal Shavings Compactor ........................................................ 61 OMC No. 2. Replace Broken Windows .................................................................... 61 OMC No. 3. Implement Coolant Management ......................................................... 61 OMC No. 4 Install High Precision Laser Cutter ...................................................... 61

APPENDIX A. Motors ............................................................................................................................. 64 A.1. Motor Definitions................................................................................................... 64 A.2. Inventory ................................................................................................................ 68

A.3. Applications ........................................................................................................... 70 A.4. Motor Use Summary .............................................................................................. 72 A.5. Economics .............................................................................................................. 72 A.6. Diversity Factor...................................................................................................... 72 A.7. Motor Performance Table ...................................................................................... 73 A.8. Power Factor Curve................................................................................................ 74 B. Lighting........................................................................................................................... 75 B.1. Lighting Definitions ................................................................................................ 75 B.2. Lighting Inventory................................................................................................... 81 C. Boiler Efficiency Tips..................................................................................................... 83 C.1. Combustion Efficiency Definitions......................................................................... 85

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 recent visit to your plant. The report is divided into 6 major sections and 3 appendices: 1. Introduction. The purpose, contents and organization of the report are described. 2. Executive Summary. Your energy use and waste generation costs, productivity, energy, and waste savings,

and our recommendations are summarized here with details in the following sections. 3. General Background. The third section describes your facility, including operating schedules and process

flow diagrams. 4. Energy Use Summary. Your utility bills and energy use by process are summarized and plotted. Our

calculations are consistent with your bills. Costs for electrical energy and demand are taken from your rate schedule and used to calculate cost savings. Average electricity cost represents total annual dollars spent on electrical bills divided by annual energy (kilowatt-hours) use. It includes basic, demand, energy, reactive power charges, and taxes.

5. Assessment Recommendations. This section includes a more detailed description of our Assessment

Recommendations (AR). It also includes the methods and assumptions we use to estimate savings, our estimate of the implementation cost, and the simple payback. Some of our 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 payback period, limited by the maximum acceptable payback that you specified.

6. Other Measures Considered. These measures were considered but not recommended because: (1) they

are alternatives to measures that were recommended; (2) the payback period is too long; (3) we were unable to obtain the information necessary to estimate savings or cost accurately; or (4) the measure would adversely affect production. Some measures are included in response to specific questions you raised during the plant visit, but which do not appear to be feasible.

7. Operation & Maintenance. These measures apply to tuning, operating and maintaining existing equipment

to improve efficiency and increase equipment life. The cost savings are difficult to estimate, but can be substantial with little or no cost.

Appendix A: Motors. Motors are typically a large energy user. This section lists your largest motors with nameplate information. We include measured current, voltage and use factor for the motors we were able to monitor during our visit. Motor energy use is summarized for each application and end use. Energy and cost savings are estimated for using energy-efficient motors, high torque drive and notched V-belts. 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: Boilers. We measured the boiler operating conditions during the visit from which we calculate the existing boiler efficiency. We assume that any recommendations affecting boiler efficiency will be implemented. Any further recommendations in the report that affect steam use or boiler load will be based on the proposed operating conditions tabulated in this section. This section also includes Boiler Tips that will improve present boiler operating efficiency.

2. EXECUTIVE SUMMARY This section includes a summary of energy use and waste generation in your plant, our recommendations, and total productivity, energy, waste, and cost savings of all recommendations if implemented. 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 (KVAR or power factor), and other fees such as basic charges, transformer rental, and taxes. However, if a recommendation does not affect your electrical demand, such as turning off equipment at night, then we use the cost of electrical energy alone. The fuel costs we used can be found in the Energy Use Summary in Section 4. Recommendation Summary. The following is a brief explanation of each of the recommendations made in this report. If all 10 recommendations are implemented, the total cost savings will be $1,218,480 and will pay for costs in 1.1 year. AR No. 1, Reduce Tolerances on Cutter: Tighten the tolerance between parts cut by the natural gas torch cutter from 1 inch to 1/2 inch. AR No. 2, Reduce Paint/Solvent Waste: Use only water-based paints and primers (finished materials) during production to reduce hazardous waste disposal costs. AR No. 3, Reduce Coolant Use: Add skimmer/aerators to increase machining coolant life. AR No. 4, Dewater Coolant: Install a separator machine to dewater the waste coolant before disposal. Savings from this recommendation assumes that the previous recommendation, AR No. 2: Reduce Coolant Use, has been implemented. AR No. 5, Tune the boiler: Maintain an optimum air-fuel ratio on the gas-fired Pacific boiler 1 to improve the boiler efficiency. AR No. 6, Replace Incandescent Fixtures: Replace fourteen 300-watt incandescent fixtures with four 120-watt 8 ft. fixtures with 59-watt T8 Slimline fluorescent lamps in the small storage area in the parts shop to reduce energy use. AR No. 7, Insulate Walls: Insulate the exterior walls of your plant that are not currently insulated with 6 inch R-19 fiberglass insulation and covering. AR No. 8, Improve Power Factor: Install 1,400 kVAR of capacitance to correct for low power factor. AR No. 9, Quick-change Fixtures: Make more quick-change fixtures for the matsura 3 milling machine to increase utilization time. AR No. 10, Automate Pattern Shop: Install a CNC five-axis mill and support software in the pattern (mold) making department to reduce labor cost. AR No. 11, Retail Line Case Erector: Install box erectros to fold open and bottom seal boxes to reduce the cost of labor.

Our productivity, energy and waste recommendations are summarized in the following table.

Assessment Recommendation Summary Energy Waste Savings Implementation Payback

AR# Description 106Btu Gallons Pounds $ Cost (years)

1 Reduce Tolerances on Cutter 0 0 352,410 $116,300 $0 0

2 Reduce Paint/Solvent 0 705 0 $17,850 $0 0

3 Reduce Coolant Use -9 4,994 0 $11,080 $2,000 0.2

4 Dewater Coolant 1,149 9,480 0 $5,702 $10,000 1.8

5 Tune Boiler 2,111 0 0 $7,179 $500 0.1

6 Replace Incandescent Fixtures 111 0 0 $2,202 $1,144 0.5

7 Insulate Walls 2,494 0 0 $12,370 $23,720 1.9

8 Improve Power Factor 0 0 0 $8,246 $28,000 3.4

9 Quick-change Fixtures 0 0 0 $44,400 $5,000 0.1

10 Automate Pattern Shop 0 0 0 $1,040,000 $1,300,000 1.3

11 Retail Line Case Erector -30 0 0 $229,748 $79,349 0.3

Total 5,826 15,179 352,410 $1,495,189 $1,495,189 1.0

Total savings are the sum of the savings for each recommendation. Some of the recommendations may interact. Therefore, actual savings may be less than the total indicated above. In our calculations we indicate where we have assumed that other recommendations will be implemented in order to provide a realistic estimate of actual savings. When either one or another recommendation can be implemented, but not both, we have included the recommendation we recommend in this table and the alternate recommendation in a later section, Other Measures Considered. Total savings, including interactions among recommendations, can be better estimated after you select a package of recommendations. Savings Summary. Total cost savings are summarized by productivity, energy, and waste cost savings. We then normalize savings as a percentage of annual plant costs. For example, Energy Cost% is energy cost savings divided by the total energy cost from the Utility Summary. Waste Cost% is waste cost savings divided by the total cost of waste generation from the Waste Generation Summary. Productivity Cost% is the increased revenue divided by the revenue from annual production (annual sales). Savings% is cost savings for each category (energy, waste or productivity) divided by total cost savings.

Savings Summary Cost Savings Cost% AR Cost Payback

Energy $21,751 4.0% $53,364 2.5 Productivity $1,322,506 N/A $1,379,849 1.0 Waste $150,932 95.7% $12,000 0.1 Total $1,495,189 $1,388,717 0.9

Energy Use Summary. We used your utility bills to determine annual energy use for all fuels. From these bills we summarized annual energy consumption at your plant in the following table.

Energy Use Summary Source Quantity Units MMBtu Use% Cost Cost%

Electric Energy 15,040,353 kWh 51,333 45% $575,319 61% Demand 8,702 kW 0 0% $118,854 13% Reactive Power 3,606 kVAR 0 0% $9,665 1% Natural Gas 616,682 therms 61,668 55% $229,947 25% Electric Fees 0 0 0 0% $2,198 0% Total 113,001 100% $935,983 100%

Waste Generation Summary. Your waste streams are summarized in the following table.

Waste Generation Summary Waste Costs

Source Gallons Pounds Material Treatment Disposal Total CostCoolant Water 9,988 $12,984 $12,984Sewar Water 18,730,000 $65,261 $65,261Waste Steel 447,391 $58,064 $58,064Solvent Water 705 $2,690 $15,160 $17,850Total 447,391 $2,690 $28,144 $123,325 $154,159

3. GENERAL BACKGROUND 3.1 Facility Description SIC Number: xxxx Location: West Annual Sales: $20 Million Employees: 300 Annual Production: 5000 Pumps Audit date: MM/DD/YYYY Principal Products: Pumps Client hours: 8 The plant encompasses 20 acres including an office building and eight plant buildings. The eight plant buildings consist of heavy, medium, and light bay areas, assembled pump test area, assembly, process pump assembly (CAP), hydrostatic test area, paint shop, pattern shop, plate shop, and service center. 3.2 Process Description The plant produces bearing, multistage, and process pumps. Raw Materials: Cast Iron Pump Housings Sandblasting Grit Water and Solvent-based Paints Iron Bar Stock Impeller Castings Principal Products: Bearing Pumps Multistage Pumps Process Pumps

Process Flow Diagram: Waste streams, material usage, and the production process are diagrammed in the following figure.

Receiving

PumpCastings

ImpellerCastings

BarStock

Milling/Lathes in Heavyor Medium Bay

ManualLayout

CMM/Automatic

Layout

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Pump Castings

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Lathes in LightBay

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Inspection

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MountImpellers

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coolant

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water

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waste grit

laquer/thinner paint

waste paint/residue

woodcrates

ImpellerCastings

Bar Stock

WasteStreams

Receiving: Impeller and pump castings are delivered to receiving from the foundry. In receiving, the castings are laid out either manually or automatically by the Computer Machine Module (CMM). During layout, the castings are separated and then combined with their counterparts. Once together, they are measured and marked corresponding to the appropriate cuts that are going to be made on the castings to produce the final product. Light Bay: From receiving, impeller castings are delivered to the Light Bay. The castings are machined to proper tolerances. The lathes remove metal in a precise pattern that was produced in the layout step in receiving. The surfaces are then ground to remove burrs and then inspected for proper dimensions and quality.

Energy Application Quantity Total Power Grinder 3 5.5 hp Baldor Saw 1 3 hp Lathe 1 30 hp Milling Machines 1 50 hp Power Draw Bar 1 50 hp Turning Center 2 120 hp

Heavy/Medium Bay: Pump castings are moved to the heavy or medium bay depending on the size of the casting. In either bay, the castings are faced (milling on the face). The mills then further mill the holes and volutes from the castings. In the Medium Bay, bar stock is cut to length and sent to the lathes for. Once the correct dimensions are obtained for the shaft, the shaft is further milled to produce keyways.

Energy Application Quantity Total Power Saws 2 20 hp Lathes 5 170 hp Mills 13 950 hp Machining Tables 3 290 hp Drill 1 10 hp Crane 1 10 hp

Nuclear Production Area: When the facility receives special orders from the military or nuclear power plants, the pumps must be milled under stricter requirements and specifications. The entire process follows that of the light, medium, and heavy bays but with higher quality control standards.

Energy Application Quantity Total Power Grinders 6 42 hp Lathes 1 50 hp Mills 1 75 hp Drill 1 10 hp Crane 13 60 hp

Hydrostatic Testing: From the heavy or medium bay, the pumps are transported to the hydrostatic testing area. All outlets are sealed and the pumps are pressure tested. This is done by adding a water and surfactant solution to the pumps under pressure to detect leaks in the casting. The surfactant is added to lower the viscosity of the water, making leak detection easier and faster.

Energy Application Quantity Total Power Hydraulic Pump Test Motors (Testing Area) 22 2,015 hp

Plate Shop: In the plate shop, the base for the pump assembly is created. Plate iron is cut to dimension via a gas torch. The resulting pieces are welded together to form the pump assembly base.

Energy Application Quantity Total Power Rotating Table 3 170 hp Band Saw 2 20 hp Shears 2 10 hp

Final Assembly: Shafts, impellers and pump castings are now transported to assembly. First the impeller is mounted on the shaft. Then the shaft and impeller combination are balanced by grinding metal in specific areas to produce a balanced shaft-impeller assembly. The shaft-impeller assembly is then placed in the pump casting. Once complete, the pump is tested to ensure proper operation by pumping water through the pump. Finally, the entire pump housing is mounted on a platform that contains the pump and motor that will drive the pump.

Energy Application Quantity Total Power Other Test Motors (R&D or Assembly) 29 22,475 hp

Painting/Sand Blasting: From final assembly, the pump is mounted on the platform and transported to painting. The entire assembly is sand blasted, primed, and painted. Warehouse/Shipping: From painting, the pump is transported to the warehouse where it awaits delivery or is loaded onto a truck or ship and delivered to the customer immediately. CAP (Centrifugal and Axial Pumps): This is a separate portion of the main plant and is treated as a separate production unit. Standardized centrifugal and axial pumps are constructed. Castings are milled and turned on lathes to produce a final product. General Plant Equipment The plant is supported by a 150-hp and a 300-hp air compressor, two boilers, and several different cranes and hoists.

Energy Application Quantity Total Power Cranes 52 193 hp Hoists 4 400 hp Boiler Fans 2 5 hp Air Compressors 2 450 hp Boilers 2 800 hp

3.3 Operating Schedule

Area Annual Days Annual Hours Operating Schedule Assembly 255 6,120 24 hrs: 5 days/wk, 51 wk/yr CAP 255 6,120 24 hrs: 5 days/wk, 51 wk/yr Light Bay 255 6,120 24 hrs: 5 days/wk, 51 wk/yr Medium Bay 255 6,120 24 hrs: 5 days/wk, 51 wk/yr Heavy Bay 306 7,344 24 hrs: 6 days/wk, 51 wk/yr Office 255 2,040 8 hrs: 5 days/wk, 51 wk/yr Painting 255 6,120 24 hrs: 5 days/wk, 51 wk/yr Pattern Shop 255 2,040 8 hrs: 5 days/wk, 51 wk/yr Plate Shop 255 4,080 16 hrs: 5 days/wk, 51 wk/yr Receiving/Setup 255 4,080 16 hrs: 5 days/wk, 51 wk/yr Service Center 255 4,080 16 hrs: 5 days/wk, 51 wk/yr Hydrodynamic Test 255 6,120 24 hrs: 5 days/wk, 51 wk/yr Tool Shop 306 7,344 24 hrs: 6 days/wk, 51 wk/yr Warehouse 255 2,040 8 hrs: 5 days/wk, 51 wk/yr

4. ENERGY USE SUMMARY & ENERGY ACCOUNTING 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 (106Btu). 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

* Varies slightly with supplier The following table lists several other conversion factors often used in our calculations:

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

The value of graphs can best be understood by examining those plotted for your company in the Energy Summary. 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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$8,5

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May

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4,59

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,180

$4,1

930

$8,3

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$12,

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Jun-

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4,92

6$4

,421

$4,4

863,

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$4,2

31$8

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$8,6

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$4,2

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Solid Waste ChargesRolloff Trash Rolloff Wood Frontload Recycle Total

Month tons $ tons $ pounds $ pounds $Dec-YY 4.81 $1,046 3.59 $596 18,203 $3,540 35,007 $5,182Jan-YY 4.94 $1,059 4.81 $705 22,060 $2,460 41,561 $4,223Feb-YY 10.21 $1,532 3.80 $614 13,730 $0 41,746 $2,146Mar-YY 8.79 $1,404 0.27 $297 6,180 $3,180 24,294 $4,881Apr-YY 4.54 $1,350 1.35 $394 14,290 $3,880 26,068 $5,623May-YY 2.69 $710 3.58 $595 17,730 $3,930 30,277 $5,234Jun-YY 8.20 $1,437 4.05 $712 20,560 $2,940 45,060 $5,089Jul-YY 5.86 $1,013 4.05 $591 17,830 $3,060 37,650 $4,664Aug-YY 5.16 $1,170 7.38 $864 10,620 $3,300 35,700 $5,333Sep-YY 9.03 $1,235 7.07 $794 15,966 $3,105 48,166 $5,134Oct-YY 4.65 $1,122 7.45 $977 14,964 $2,910 39,164 $5,009Nov-YY 6.83 $1,099 5.34 $876 18,358 $3,570 42,698 $5,544Totals 75.71 $14,175 52.74 $8,013 190,491 $35,875 447,391 $58,064Avg/Mo 6.31 $1,181 4.40 $668 15,874 $2,990 37,283 $4,839

Solid Waste Utility Summary

Rolloff Trash

Haul Fee $79Ton Rate $90 /tonRespot Charge $20Monthly Container Rental $90Attempted Service/Wait Time $1 /minute

Rolloff Recycle

Haul Fee $90Ton Rate $20 /tonRespot Charge $20Monthly Container Rental $90Attempted Service/Wait Time $1 /minute

Frontload Trash and Recycle Rates Per Pickup

4.0 yd Trash Container $30All Recycle Containers $0Extra Loose Yards $15 /ydCase of Recycle Liners $0

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

kilo

Wat

ts

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Electrical Demand

Power Factor

70%

80%

90%

100%

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YYMonth

Perc

ent

xxxxx1-0657-3875-0

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

kilo

Wat

t Hou

rs

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Electrical Energy Consumption

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

Dol

lars

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Total Electricity Cost

0

20,000

40,000

60,000

80,000

100,000

120,000T

herm

s

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Natural Gas Consumption

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

Dol

lars

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Natural Gas Cost

0

1,000

2,000

3,000

4,000

5,000

6,000

ccf

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Water Usage

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

$16,000

Dol

lars

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Water & Sewer Cost

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

Dol

lars

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Solid Waste Cost

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000M

MB

tu

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Total Energy Consumption

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

Dol

lars

Dec-YY Feb-YY Apr-YY Jun-YY Aug-YY Oct-YY

Month

Total Energy Cost

Average Electricity Cost: $0 /kWhAverage Natural Gas Cost: $0 /therm

ELECTRICITYUSE UNIT MMBTU ENERGY % COST COST %

Hydodynamic Testing 4,960,461 kWh 16,930 33.0% $232,646 33.0%Special Energy Use 3,114,736 kWh 10,631 20.7% $146,081 20.7%Heavy machinin Stations 3,022,425 kWh 10,316 20.1% $141,852 20.1%Meduim Machining Stations 1,313,537 kWh 4,483 8.7% $61,605 8.7%Air Compressors 740,643 kWh 2,528 4.9% $34,736 4.9%Lights 358,836 kWh 1,225 2.4% $16,829 2.4%Nuclear Test Area 311,467 kWh 1,063 2.1% $14,608 2.1%Cranes and Hoists 284,949 kWh 973 1.9% $13,364 1.9%Boiler 31,873 kWh 109 0.2% $1,495 0.2%Light Machining Stations 291,922 kWh 996 1.9% $13,691 1.9%Miscellaneous Motors 17,711 kWh 60 0.1% $831 0.1%Miscellaneous Motors 591,793 kWh 2,020 3.9% $27,755 3.9%TOTALS 15,040,353 kWh 51,334 100.0% $705,493 100.0%

NATURAL GASUSE UNIT MMBTU ENERGY % COST COST %

538,740 therm 53,874 87.4% $200,950 87.4%Boiler 77,942 therm 7,794 12.6% $29,072 12.6%Heat Treat Furnace 616,682 therm 61,668 100.0% $230,022 100.0%TOTALS

FUEL SUMMARYUSE UNIT MMBTU ENERGY % COST COST %

Electricity 15,040,353 kWh 51,333 45.4% $705,393 75.4%Gas 616,682 therm 61,668 54.6% $230,022 24.6%TOTALS 113,001 100.0% $935,415 100.0%

END USE SUMMARY

Electrical Consumption

Special Energy Use21%

Light Machining Stations2%

Air Compressors 5%

Nuclear Test Area2%

Cranes and Hoists 2%

Heavy Machining Stations20%

Medium Machinig Stations9%

Miscellaneous Motors0.1%

Hydodynamic Testing33%

Miscellaneous 4%Lights 2%

Natural Gas ConsumptionHeat Treat

Furance13%

Boiler87%

Energy Use

Electricity45%

Gas55%

Energy Cost

Electricity75%

Gas25%

5. ASSESSMENT RECOMMENDATIONS

AR No. 1

Tighten Tolerances on Gas Cutter Recommended Action Tighten the tolerance between parts cut by the natural gas torch cutter from 1 inch to 1/2 inch.

Assessment Recommendation Summary Waste Cost Implementation Payback Pounds Savings Cost (years) 352,410 $116,300 $0 0.0

Background Currently, most parts are cut by an automated natural gas torch on a water table. The thickness of the carbon steel parts varies up to a maximum of one inch, but the majority of the parts are cut from 1/2 inch thick steel plate. Parts are cut adjacent to one another out of the 5 ft x 10 ft plate. Due to the shrinkage, bowing, and plate movement that occurs with a gas torch on a water table, the operator feels that parts should be separated by a one inch clearance. Tighter tolerances can be accomplished by maximizing the speed of the torch cutter. The maximum speed lessens the heat affected zone. By calculating the optimum speed the minimum tolerance can be found. We felt the 1 inch tolerance is excessive. Once the parts are cut from the steel plate, what remains is scrap steel plate full of holes, called skeleton plate. Calculations from the company information show waste skeleton plate, combined with the other waste steel scraps, represents 18% of the purchased steel. The operator uses a 1 inch clearance, however it may be possible to reduce to the 1/2 inch clearance without adversely affecting the product. Reducing the clearance between parts will decrease the wasted steel by 50% and decrease the required purchase of raw material. Anticipated Savings According to company records, 3,524,100 lbs of steel are purchased annually. Waste

bills show that skeleton plate represent 651,260 lbs annually. This waste is representative of 18% of the purchased steel. By reducing the tolerance to 1/2 inch the steel scrap can be reduced to 9% of the current steel purchase. By reducing waste per plate, less steel will have to be purchased to produce the same number of finished parts. Currently, 82% (100%-18%) of each steel plate (CW) arrives as final product. Reducing the tolerances will allow 91% (100%-9%) of each plate (PW) to be used. Therefore, the reduction of steel plate is calculated as a percentage of current use (NS). NS = 1 - (CW / PW) = 1 - (82% / 91%) = 10% A 10% reduction of steel use will reduce the steel purchase by an amount (SA) shown below. SA = current amount of steel x NS = 3,524,100 x 10% = 352,410 lb With a purchase price of steel at $0.36 /lb of steel (RSC), the steel cost savings (SS) are shown below. SS = SA x RSC = 352,410 x $0.36 /lb = $126,870 Waste steel is also reduced by the amount SA, which will reduce the savings. Waste steel is sold at a cost of $0.03 /lb (WSC), and the reduction in scrap revenue scrap (SR) is shown below. SR = SA x WSC = 352,410 lb x $0.03 /lb = $10,570 The total savings (TS) from the reduction of steel purchase and scrap recycling will be: TS = SS - SR = $126,870 - $10,570 = $116,300

The following is the Savings Summary Table.

Savings Summary Waste Cost

Source Quantity Units Pounds $ Waste Steel 352,410 pounds 352,410 ($10,570) Purchased Steel 352,410 pounds 0 $126,870 Total 352,410 $116,300

Implementation Cost Since there is no cost associated with this AR the payback is immediate. Savings will be proportionately greater or smaller depending on how far you can reduce the tolerance without problem. See OMC #4 for an alternate project to install a laser cutter.

AR No. 2

Reduce Paint/Solvent Waste Recommended Use only water-based paints and primers (finished materials) during production to reduce hazardous waste disposal costs.

Assessment Recommendation Summary Waste Cost Implementation Payback

Gallons Savings Cost (years) 705 $17,850 $0 0.0

Background Currently, the company sales representatives offer both solvent and water-based finished materials at the time of contract sale. The use of solvent-based finished materials create a hazardous waste that requires controlled handling and disposal costs. Note: The purchase cost of water-based refinish materials versus solvent-based refinish materials are comparable range depending on color. Anticipated Savings The primary source of savings is a decrease in hazardous waste disposal cost. The elimination of solvent-based refinish materials will decrease the amount of hazardous waste sent to the incinerator for disposal. According to paint shop employee estimations, 70% of the current primer/paint work is performed with water-based refinish materials, this generates approximately 5% of the total incinerator waste materials produced. Therefore, 95% of the current hazardous waste generation is being caused by 30% of the finished product line. The annual Waste Savings (WS) may be calculated from of the amount of solvent-based materials sent to the incinerator. However, the waste savings will be offset by the Increase in Water-Based Waste Generation (IW), which is calculated as follows:

IW = HWG (@100%) - HWG (@70%) = [CWG x PW / CUP] - [CWG x PW] = [3.19 ton x 5% / 70%] - [3.19 ton x 5%] = 0.23 ton - 0.16 ton = 0.07 ton where, HWG = Hazardous Waste Generation by Water-Based Refinish Materials CWG = Current Hazardous Waste Generation: 3.19 ton/yr PW = Percent of Water-Based Waste Generation: 5% CUP = Current Percent of Water-Based Material Use: 70% Therefore, the Waste Savings (WS) would be: WS = (CWG x PS - IW) / Density = (3.19 ton x 95% - 0.07 ton) / 0.0042 ton/gal = 705 gal where, PS = Percent of Solvent-Based Waste Generation: 95% Density = Approximate: 8.4 lbs/gal or 0.0042 ton/gal The annual Disposal Cost Savings (DC) that would result are: DC = WS x Disposal Cost = 705 gal x $21.50/gal = $15,160 The elimination of solvent-based refinish materials will also eliminate the need to clean equipment with solvent (lacquer thinner). This will result in savings due to the elimination of the need to purchase lacquer thinner. According to company records, 468 gallons of lacquer thinner were purchased last year. Therefore, the Solvent Purchase Savings (SPS) is as follows SPS = Lacquer Thinner Purchased x Purchase Cost = 468 gal x $5.75/gal = $2,690 The Total Cost Savings (CS) anticipated from this measure are calculated as follows TCS = DC + SPS = $15,160 + $2,690 = $17,850

The following table is a summary of the cost savings.

Savings Summary Waste Cost

Source Quantity Units Gallons $ Liquid (Haz) Disposal 705 gallons 705 $15,160 Solvent Purchase 468 gallons $2,690 Total $17,850

Implementation Cost There are no costs associated with this measure, and payback is therefore immediate.

AR No. 3

Reduce Coolant Use Recommended Action Add skimmer/aerators to increase machining coolant life.

Assessment Recommendation Summary

Energy Waste Cost Implementation Payback (106Btu) Gallons Savings Cost (years)

-9 4,994 $11,080 $2,000 0.2 Background Currently, there are five machining stations that use machining coolant. Parts are sprayed with coolant while being machined to remove fines and produce a clean, machined surface. Contaminants removed from the parts are suspended in the coolant or deposited in the coolant reservoir that is under the machine. Coolant is used until an unpleasant smell develops. The unpleasant smell is generated from anaerobic bacteria. The contaminated fluid is then sent to the holding tank for evaporation. Anticipated Savings We recommend installing skimmer/aerators on the five machining stations. The skimmer component removes particles and oil from the coolant, while the aerator reduces odor. Aeration inhibits growth of odor-causing anaerobic bacteria by adding oxygen to the coolant. According to distributor estimates, continuous operation of the skimmer/aerators can double coolant life, without interfering in the machining process. As a result, 50% of the coolant would be saved on an annual basis. During 1996, the plant produced 9,988 gallons (CU) of waste coolant with a specific gravity of 0.8 (SG = 0.8). The annual Machine Coolant Savings (MS) would be: MS = CU x 50% = 9,988 gal/yr x 50% = 4,994 gal/yr.

The annual Machine Coolant Cost Savings (MCS) are: MCS = MS x Water Factor x Coolant Cost = 4,994 gal/yr. x 0.1 x $13.00/gal = $6,492/yr. Where: Water Factor = Mixing ratio (1 gal concentrated coolant/10 gal mixed coolant): 0.10 *Note: The waste disposal savings that result from this implementation are calculated in AR No. 3 Currently the coolant in each tank is changed weekly with an average changing time of 2.5 hours per tank. Skimmers will reduce the tank's maintenance schedule from weekly to every two weeks. Therefore, the annual Labor Savings (LS) from the decreased maintenance of all five machines would be: LS = 2.5 hr/tank x 5 tanks x 25 wk/yr. = 313 hr/yr. The annual Labor Cost Savings (LC) are as follows: LC = LS x Labor Cost = 313 hr/yr. x $15.00/hr = $4,695/yr. Operating the skimmer decreases annual savings. The Electrical Demand (ED) for the five machines is: ED = Qty x Volts x Amps = 5 x 115 V x 0.6 A = 0.3kW Assuming the skimmer will operate continuously for best performance, the annual Electrical Energy (EE) is as follows: EE = ED x 8,760 hr/yr. = 0.3 kW x 8,760 hr/yr. = 2,628 kWh/yr. = 9 x 106 Btu/yr.

The annual Demand Cost (DC) and Energy Cost (EC) for the skimmers are: DC = ED x 12 mo/yr x Demand Cost = 0.3 kW x 12 mo/yr x $4.36/kW-mo = $16 /yr. and, EC = EE x Energy Cost* = 2,628 kWh x $0.03461 /kWh = $91 /yr. *Average energy cost for on/off-peak charges. The following table is a summary of the Cost Savings.

Savings Summary Energy Waste Cost

Source Quantity Units 106Btu Gallons $ Demand 0 kW 0 0 ($16) Electric Energy -2,628.0 kWh -9 0 ($91) Personnel Changes

0 0 0 0 $4,695

Coolant Cost 4,994 gallons 0 4,994 $6,492 Total -9 4,994 $11,080

Implementation Cost Installation of the skimmer/aerators is limited to plugging the pump into a standard outlet, so implementation costs are limited to the purchase price. Each unit is estimated to cost $400, based on the distributors quote. For five units, the implementation cost (IC) is then: IC = Qty x Unit Price = 5 x $400 = $2,000 The annual cost savings will pay for the implementation cost in 0.4 years.

AR No. 4

Dewater Coolant

Recommended Action Install a separator machine to dewater the waste coolant before disposal. Savings from this recommendation assumes that the previous recommendation, AR No. 2: Reduce Coolant Use, has been implemented.

Assessment Recommendation Summary Energy Waste Cost Implementation Payback

(106Btu) Gallons Savings Cost (years) 1,028 4,740 $5,530 $10,000 1.8

Background Currently, machine coolant is used during the processing of chucks and shafts. During the machining process, the coolants remove heat and metal shavings from the cutting blades. Over time, the coolant will build up an excessive amount of particulate matter to be used effectively. Once the coolant is changed, it is placed in a tank for storage until disposal. When the storage tank is full, the coolant is processed by a waste disposal company. The coolant is purchased as a concentrated liquid that is reconstituted with water before being used in the equipment. Anticipated Savings Savings would be realized by removing the water from the waste coolant and disposing of the removed water to the sanitary sewer. The manufacturer claims the water separator will reduce 20 gallons of waste coolant to 1 gallon of waste oil. The resulting oil will still be processed as waste with the same disposal company. From the previous recommendation, the plant produced 9,988 gallon of waste coolant with a specific gravity of 0.8 (SG = 0.8). But, installing the skimmer/aerators would decrease the annual waste coolant production by 50%, resulting in an annual waste coolant production rate (C) of 4,994 gallons per year.

The annual Waste Savings (WS) are: WS = C x RF = 4,994 gallon/yr x 95% = 4,740 gallons/yr where, RF = volume reduction factor = 19 parts water/20 parts coolant mixture = 95% The waste disposal company charges $0.62 /gal. Therefore, the annual Waste Cost Savings (WC) would be: WC = WS x Waste Disposal Cost = 4,740 gallons/yr x $0.62 /gallon = $2,939/yr The water separator is driven by a 1/2-hp electric motor. The manufacturer stated the water separator could treat 55 gallons in six hours. Therefore, the annual operating hours (OHws) of the proposed water separator motor is: OHws = 4,740 gallons/yr x (6 hrs/55 gallons) = 517 hrs/yr The demand will increase because the recommended motor is larger than the 1/3-hp motor that the evaporator currently uses. However, energy savings will be realized since the proposed motor will operate for fewer hours. The Demand Increase (DI) from the proposed motor is: DI = (Hpws - Hpe) x 0.746 kW/hp / η = (0.5 hp - 0.33 hp) x 0.746 kW/hp / 70% = 0.18 kW where, Hpe = existing evaporator horsepower: 1/3 Hpws = proposed water separator horsepower: 1/2 η = motor efficiency: approximately 70% This will result in an increase in the facility's Demand Charges (DC). DC = DI x Demand Cost x 12 mo/yr = 0.18 kW x $4.36 /kW-mo x 12 mo/yr = $9 /yr

The annual Energy Savings (ES) that would result from the proposed operating hours would be: ES = [(Hpe x 8,760 hrs/yr) - (Hpws x OHws)] x 0.746 kW/hp / η = [(0.33 hp x 8,760 hrs/yr) - (0.5 hp x 517 hrs/yr)] x 0.746 kW/hp / 70% = 2,880 kWh/yr The annual Energy Cost (EC) of operating the new separator would be: EC = ES x average energy cost = 2,880 kWh/yr x $0.03461/kWh = $100 The water separator produces clean water as a byproduct. This water could now be discharged to the sanitary sewer. The sanitary Sewer Charge (SC) is. SC = (WS x 0.001337 gal/ccf) x sewer charge/ccf = (4,740 gal x 0.001337 gal/ccf) x $1.52/ccf = $10 The water separator contains two 10 micron bag filters and a coalescing filter. These filters become clogged periodically and must be changed. The manufacturer estimates that new filters would need to be replaced eight times per year. The filters cost $100 a piece. On a yearly basis, the total would be $800. The majority of this operating and maintenance cost is incurred from the coalescing filter. Since the filters are relatively small, disposal cost of these filters is negligible. The Cost of the Filters (CF) is calculated below. CF = 8/year x $100/filter = $800/year The current evaporator uses natural gas with a maximum burner rating of 195,000 Btu/hr. It evaporates water at a rate 15 gallon/hour. The evaporator operates 16 hours a day, 365 days per year. The annual Natural Gas Savings (NGS) and annual Natural Gas Cost Savings (NGC) that would result from replacing the evaporator would be: NGS = Heat Use / Efficiency x Operating Hours = 195,000 Btu/hr x 5,840 hrs/yr = 1,139 x 106 Btu/yr = 11,390 therms/yr and, NGC = NGS x Natural Gas Cost = 11,390 therms/yr x $0.3233/therm = $3,682 /yr

The following is a Savings Summary Table.

Savings Summary Energy Waste Cost

Source Quantity Units 106Btu Gallons $ Coolant (haz) 4,740 gallons 0 4,740 $2,939 Demand -0.2 kW 0 0 ($9) Electric Energy 2,880 kWh 10 0 $100 Natural Gas 10,180 therms 1,018 0 $3,290 Ancillary Material Cost

0 0 0 0 ($800)

Waste Water 4,740 gallons 0 4,740 $10 Total 1,028 9,480 $5,530

Implementation Cost The implementation cost (IC) for this measure includes the purchase and installation of a water separator unit. IC = $10,000 The savings will pay for the implementation of this measure in 1.8 years. Note: If only this recommendation is implemented, cost savings will increase $4,588 and payback will decrease to 1 years.

AR No. 5

Tune the Boiler Recommended Action Maintain an optimum air-fuel ratio on the gas-fired Pacific boiler 1 to improve the boiler efficiency.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) 2,111 $7,179 $500 0.1

We also recommend that boiler 2 be tuned for optimal efficiency. However, since boiler 1 and 2 are identical, we assumed they operated the same. For further recommendations, see the Boiler Efficiency Tips in Appendix C. We assume that any AR's involving improvements in boiler efficiency will be implemented as described and summarized in Appendix C. Boiler Description

Boiler Description Boiler:

Manufacturer Pacific Maximum Firing Rate 12.30 106Btu/hr Model HSB 26219 Annual Hours 8,760 hrs/yr Fuel Natural Gas Horse Power N/A Year 1951 Maximum Pressure 15 psi

Steam Conditions: Pressure 10 Psig Temperature 240 °F

Anticipated Savings During our site visit, we analyzed the boiler 1 flue gases at medium fire. The following table summarizes the present boiler operating conditions.

Existing Operating Conditions Energy Use: Firing Level Low Medium High Total Percent Capacity 20 50 100 % Firing Rates 2.46 6.15 12.30 106Btu/hr Operating Hours 0 8,760 0 8,760 hrs/yr Annual Energy Use 0 53,874 0 53,874 106Btu Temperatures: Stack Temperature N/A 290 N/A °F Combustion Air Temperature 60 60 60 °F Net Stack Temperature N/A 230 N/A °F Flue Gas Concentrations: Oxygen (O2) 0 11.2 0 % Carbon Dioxide (CO2) 0 5.5 0 % Carbon Monoxide (CO) 0 180 0 ppm Efficiency (ηηηη0) N/A 80.9 N/A %

Ideally, a boiler should use just enough combustion air to burn all of the fuel, with no excess air. Excess air carries heat up the stack and reduces boiler efficiency. However, no burners are ideal; they all require some excess air to ensure complete combustion. We assume that you can operate your boiler with 4.0% oxygen (O2), corresponding to 21.1% excess air and 9.6% CO2 for natural gas. You may be able to reduce O2 below 4.0% for additional savings, although combustibles and CO may rise to unacceptable levels.

The combustion efficiency tables in Appendix C show combustion efficiency as a function of net stack temperature and %O2. The proposed efficiency attainable by tuning to 4.0% O2 can be found by following the 4.0% O2 row across to the 230°F net stack temperature column for low fire condition. The proposed operating conditions are summarized in the following table.

Proposed Operating Conditions Firing Level Low Medium High Percent Capacity 20 50 100 % Temperatures: Stack Temperature N/A 290 N/A °F Combustion Air Temperature 60 60 60 °F Net Stack Temperature N/A 230 N/A °F Flue Gas Concentrations: Oxygen (O2) 5.0 4.0 4.0 % Carbon Dioxide (CO2) 9.0 9.6 9.6 % Carbon Monoxide (CO) 0 180 0 ppm Efficiency (ηηηηp) N/A 84.2 N/A %

The annual energy savings (ES) realized by tuning the boiler can be calculated as: ES = E x [1 - (η0 / ηp)] where, E = annual energy use by boiler η0 = present boiler efficiency ηp = proposed boiler efficiency

Energy Use Summary Firing Level

Percent Capacity

Operating Hours

Existing Efficiency

Proposed Efficiency

Existing Energy

Proposed Energy

Energy Savings

Cost Savings

η0 ηp Use Use (%) (hr) (%) (%) (106Btu) (106Btu) (106Btu) ($) Low 10 0 N/A N/A 0 0 0 $0

Medium 50 8,760 80.9 84.2 53,874 51,763 2,111 $7,179 High 100 0 N/A N/A 0 0 0 $0

Total 53,874 51,763 2,111 $7,179

Therefore, the annual energy savings are: ES = 21,114 therm/yr = 2,111 106Btu/yr The annual cost savings (CS) that would result is: CS = ES x Average Natural Gas Cost = 21,114 therm/year x $0.34/therm = $7,179 /year

Savings Summary Energy Cost

Source Quantity Units 106Btu $ Natural Gas 21,114 therms 2,111 $7,179

Implementation Cost In order to adjust the air-fuel ratio for maximum efficiency, we suggest that a flue gas analysis kit be purchased. A fluid-type testing device costs about $500. More expensive electronic combustion analyzers are available that are more convenient for frequent testing. The air-fuel ratio should be checked monthly or more often as needed to maintain optimum efficiency. The procedure is simple, requiring about 10 minutes. The primary air supply to the burner can then be appropriately adjusted to obtain the optimum air-fuel ratio. The boiler may also be visually inspected for exterior cracks or holes where excess air may be entering the system. The implementation cost is: IC = $500 The cost savings will pay for the implementation cost in 0.1 years. This assumes that flue gas analysis can be added to the regular maintenance schedule with negligible change in the maintenance labor costs. Should you require any help in operating the combustion analyzer, please contact us. We will be glad to provide help. Boiler tuning can be dangerous. An alternative is to hire someone to tune and service the boiler regularly. This might cost $100 to $150 per visit. Note that the savings from even a small improvement in boiler efficiency will pay for the cost almost immediately.

AR No. 6

Replace Incandescent Fixtures Recommended Action Replace fourteen 300-watt incandescent fixtures with four 120-watt 8 ft. fixtures with 59 watt T8 Slimline fluorescent lamps in the small storage area in the parts shop to reduce energy use.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) 111 $2,202 $1,144 0.5

Background The general light level was measured to be an average of 40 foot-candles (FC) in the small storage area. The recommended lighting level for general lighting in this application is 15 FC. We estimate the lighting level will be 19 FC after implementation. More fixtures will increase light level and cost and reduce savings. However, the payback will still be short. Anticipated Savings Savings occur because the fluorescent lamps provide approximately 4.1 times more light than the incandescent lamps for each watt of power consumed. Fluorescent lamps also have a much longer lifetime (15,000 hours) than incandescent lamps (750 hours) and therefore will not need replacement as often. The demand, energy, and cost savings are calculated in the following Replace Incandescent Fixture worksheet. The methods and terminology used in the lighting worksheet(s) are described in Appendix B. The demand (DS) and energy (ES) savings will be: DS = 4 kW ES = 32,412 kWh/yr = 111 x 106Btu/yr The total operating cost savings include demand (DC), energy (EC), maintenance material (MMC) and maintenance labor (MLC). CS = DC + EC + MMC + MLC

The following is the Savings Summary Table.

Savings Summary Energy Cost

Source Quantity Units 106Btu $ Demand 3.7 kW 0 $194 Electric Energy 32,412 kWh 111 $1,121 Maintenance Labor Cost 0 0 0 $394 Maintenance Material Cost

0 0 0 $493

Total 111 $2,202 Implementation Cost The implementation cost (IC) of replacing incandescent fixtures with fluorescent fixtures, including lamps, is calculated from IC = (F# x C/F) + (L# x C/L) + Labor Charge where, F# = The number of fixtures in the area 4 C/F = The cost per fixture: $120 L# = The number of lamps 8 C/L = The retail lamp cost per lamp: $16 We estimate that it will take two hours for one person to replace each fixture at a rate of $30.00 per hour. Therefore, the implementation cost is: IC = (4 x $120) + (8 x $16) + (4 x 2 x $30.00) = $844 The Cost of Removing (CR) the 10 additional incandescant fixtures is calculated below assuming it will take one person one hour at a rate of $30.00 per hour. CR = # of fixtures x hours/fixture x hourly wage = 10 x 1 hr/fixture x $30.00 = $300 The Total Cost (TC) is calculated below. TC = IC + CR = $844 + $300 = $1,144 The cost savings will pay for the implementation cost in 0.5 years.

REPLACE INCANDESCANT FIXTURES

PLANT DATA Report Number: 292 Bldg.: Pattern Shop Demand Cost (D$): $4.36 /kW-mo. Area: Small Storage Energy Cost (E$): $0.03461 /kWh Lamp Replacement Time: 1/6 hours Rec. Foot-candles: 15 Ballast Replacement Time: 1/2 hours Maintenance Labor Rate:($/H) $15.00 /hour Fixture Replacement Time: 2 hours Electrician Labor Rate:($/H) $30.00 /hourFIXTURES Symbol Existing Proposed Savings Units Description: FID Incandescent 8 ft. Slimline Lamps Quantity: F# 14 4 10 Operating Hours: H 8,760 8,760 0 hours Use Factor: UF 100% 100% 0% Lamps/Fixture: L/F 1 2 (1) Ballasts/Fixture: B/F 0 1 (1) Cost: C/F $37.29 $120.20 ($82.91)

LAMPS Description: LID PS25 T8/SPX41 Quantity: L# 14 8 6 Life: LL 750 15,000 (14,250) hours Cost: C/L $3.39 $15.46 ($12.07) Replacement Fraction: Lf 1168% 58% 1110% Watts/Lamp: W/L 300 59 241 watts Lumens: LM 6,300 5,440 860 Maintenance Replacement Cost: LRC $554.33 $36.11 $518.22 Maintenance Labor Cost: LLC $407.16 $5.82 $401.35

BALLASTSBALLAST CODE 0 F-96-8 Description: BID N/A S-251-S-TP Quantity: B# 0 4 (4) Life: BL 0 75,000 (75,000) hours Cost: C/B $0.00 $54.95 ($54.95) Replacement Fraction: Bf 0% 12% -12% Ballast Factor: BEF 0% 98% -98% Input Watts: IW 0 120 (120) watts Maintenance Replacement Cost: BRC $0.00 $25.67 ($25.67) Maintenance Labor Cost: BLC $0.00 $7.01 ($7.01)

POWER AND ENERGY Total Power: P 4.2 0.5 3.7 kW Energy Use: E 36,792 4,380 32,412 kWh

LIGHT LEVEL CHECK Total Lumens: TLM 88,200 42,650 45,550 Foot-candles: FC 40 19 21 Lighting Efficiency: LM/W 21.0 88.9 67.9

ANNUAL OPERATING COST Total Power Cost: PC $220 $26 $194 Energy Cost: EC $1,273 $152 $1,121 Maintenance Material Cost: MMC $554 $62 $493 Maintenance Labor Cost: MLC $407 $13 $394 Total Operating Cost: OC $2,454 $253 $2,202

IMPLEMENTATION COST Materials: M$ $604 $604 Labor: L$ $740 $740 Total Cost: IC $1,344 $1,344

SIMPLE PAYBACK SP 0.6 years

AR No. 7

Insulate Walls Recommended Action Insulate the exterior walls of your plant that are not currently insulated with 6.25 inch fiberglass insulation and half-inch thick, chip board, sheeting cover.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) 4,478 $22,210 $25,094 1.1

Background Currently the outside bearing walls in the heavy/medium bay, light bay, and plate shop are not insulated. The average temperature in your area of the country is approximately 55°F. The estimated average temperature of the building is 65°F. Since the outside temperature is lower than the building wall temperature, heat is lost from the building to the atmosphere. By insulating the walls this heat energy loss can be decreased significantly. Anticipated Savings The existing energy loss (E0) can be found from: E0 = U0 x A x (TS - TA) x OH / η where, U0 = Existing heat transfer coefficient: 1.5 Btu/hr-°F-ft A = Wall surface area: 29,650 ft2 TS = Surface temperature 65°F TA = Outside ambient temperature: 55°F OH = Operating hours: 8,760 hr/yr η = Heater Efficiency: 84.2 % The energy loss (E1), after adding 6.25 inches of (R-19) fiberglass insulation with (R-1) chip board covering, can be found from: E1 = U1 x A x (TS - TA) x OH / η where, U1 = Proposed heat transfer coefficient = 1 / (1 / U0 + R) R = Insulation R-Value: 20 ft2-hr-°F/Btu The energy savings (ES) can be found from: ES = E0 - E1

The following wall insulation worksheets shows energy savings, cost savings, implementation costs, simple payback, and incremental payback for a variety of insulation thickness. The incremental payback is the ratio of additional cost to additional cost savings for each increment of insulation. Based on a simple payback of 2.5 years or less and building wall design, we recommend 6.25 inches of fiberglass insulation on the walls of several buildings. The insulation thickness, energy and cost savings are summarized in tables on the following pages, and in the following calculations. The energy (ES) savings from the three worksheets have been calculated as: ES = (2,010 + 824.5 + 1643.2) 106Btu/yr = 4,478 106Btu/yr = 44,780 Therm/yr The cost savings (CS) can be found from: CS = ES x (energy charge) = 4,478 106Btu/yr x $4.96 /106Btu = $22,210 /yr

Savings Summary Energy Cost

Source Quantity Units 106Btu $ Natural Gas 44,780.0 therms 4,478 $22,210

Implementation Cost In addition to the fiberglass insulation(INS), a chip board(CB) covering will be necessary for protection. The implementation costs are summarized below. IC = INS (ft2) x $0.53 /ft2 + CB (ft2) x $0.31 /ft2 = 29,650 ft2 x $0.53 /ft2 + 29,650 ft2 x $0.31 /ft2

= $25,094 The cost saving will pay for the implementation cost in 1.1 years.

AR No. 8

Improve Power Factor Recommended Action Install 1,400 kVAR of capacitance to correct for low power factor.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) 0 $8,246 $28,000 3.4

Background Total demand is made up of two parts: real power and reactive power. The real power does the useful work and is measured in kilowatts (kW). Reactive power is measured in kiloVolt-Amperes Reactive (kVAR). It is the power needed to excite the magnetic field of an induction motor or other inductive load. This component does no useful work, and is not registered on a real power meter. However, it does contribute to the heating of generators, transformers, wiring, and transmission lines. Thus, it constitutes an energy loss. The power factor is the percentage of the total power that is real. The power factor can be improved by adding capacitors to your electric service. The cost savings will occur by a reduction in the utility's penalty charge for low power factor. Anticipated Savings You are billed for any kVAR in excess of 40% of the kW, which is called Excess kVAR. The monthly reactive power charge (RC) is assessed by the following method: RC = [kVAR - (40% x kW)] x kVAR$ where, kVAR = KiloVolt-Amperes Reactive kW = Kilowatt demand kVAR$ = kVAR charge: $0.50 /kVAR The following Power Factor Correction worksheet shows the effect of adding various amounts of capacitance (kVAR Correction) to correct the power factor. This is necessary because the reactive power varies from month to month. The worksheet shows monthly amounts of demand (kW), kiloVolt-Amperes Reactive (kVAR), and kVAR in excess of 40% of the demand (Excess kVAR). In the Proposed Excess kVAR table, the Excess kVAR is shown by month for each

amount of kVAR Correction. The Proposed Cost Savings table shows the reduction in kVAR charges for each amount of kVAR Correction. The Proposed Cost Savings (PCS) for each month and each amount of kVAR correction is found from: PCS = [(Existing - Proposed) Excess kVAR] x kVAR$ When the Excess kVAR reaches zero for any month, no further cost savings are claimed for additional correction. The Savings and Cost Summary table shows proposed kVAR correction, cost savings, implementation cost, and simple and incremental payback. We choose the optimum amount of correction based on an incremental payback of less than 5 years. The incremental payback is the ratio of the implementation cost and cost savings for each additional increment of kVAR. Once the optimum is selected, the total annual cost savings (CS) are determined, along with the simple payback. The best combination of cost savings and payback was found by adding 850 kVAR of capacitance for meter number K54351P and 550 kVAR of capacitance for meter number K82472P. The following is a savings summary table.

Savings Summary Energy Cost

Source Quantity Units 106Btu $ Reactive Power 1,400 kVAR 0 $8,246

Implementation Cost Assuming an installed cost of approximately $20 /kVAR, the implementation cost (IC) would be: IC = 1,400 kVAR x $20/kVAR = $28,000 The cost savings will pay for the implementation cost in 3.4 years. Automatic power factor correction is also available that automatically adds the correct number of capacitors to maintain the optimum power factor as plant electric loads change. However, the cost is approximately 3 times as great and the payback 3 times as long. Note: In general, small motors often can be corrected as a group at the motor control centers. On larger motors, we recommend installing capacitors at the motor starter. The capacitors will disconnect automatically when the motor is not operating to prevent over correction. In no case do we recommend overcorrecting the power factor. The determination of the optimum power factor correction and the installation and location of the capacitors may require additional engineering. We recommend that additional professional

advice, if needed, be obtained from a capacitor supplier or an engineering firm. If soft-start motor starters or motor load controllers are being used, the capacitors may require installation ahead of the controller. Placing capacitors between the controller and the motor may result in damage to the controller and other equipment. We recommend following the controller manufacturer's recommendations when installing capacitors. There are additional benefits from improving power factor. Less total current flows in the plant wiring, motors, and other equipment. Less current means reduced power losses with resulting energy and demand savings. However, energy savings due to these power losses are typically less than 1% of plant electricity use. Other benefits from improved power factor are that motors run cooler and that system voltage is higher. Therefore, motor efficiency, capacity and starting torque will also be slightly higher. Branch circuit capacity also is higher because more real work can be done with the same total current.

POWER FACTOR CORRECTION

Power ComapanyMeter Number:Excess kVAR Percentage: 40%Reactive Power Charge: $0.50 /kVARCorrection Cost per kVAR: $20 /kVAR

Present Conditions Proposed Excess kVARExcess kVAR Correction

Month kW kVAR kVAR 450 500 550 600 650Aug 2,476 1,580 590 140 90 40 0 0Sep 2,600 1,656 616 166 116 66 16 0Oct 2,312 1,400 475 25 0 0 0 0Nov 2,060 1,404 580 130 80 30 0 0Dec 2,016 1,436 630 180 130 80 30 0Jan 2,224 1,552 662 212 162 112 62 12Feb 2,368 1,640 693 243 193 143 93 43Mar 2,516 1,828 822 372 322 272 222 172Apr 2,336 1,768 834 384 334 284 234 184May 2,428 1,696 725 275 225 175 125 75Jun 2,220 1,752 864 414 364 314 264 214Jul 1,704 1,324 642 192 142 92 42 0

Present Conditions Proposed Cost SavingskVAR kVAR Correction

Month kW kVAR Charge 450 500 550 600 650Aug 2,476 1,580 $295 $225 $250 $275 $295 $295Sep 2,600 1,656 $308 $225 $250 $275 $300 $308Oct 2,312 1,400 $238 $225 $238 $238 $238 $238Nov 2,060 1,404 $290 $225 $250 $275 $290 $290Dec 2,016 1,436 $315 $225 $250 $275 $300 $315Jan 2,224 1,552 $331 $225 $250 $275 $300 $325Feb 2,368 1,640 $347 $225 $250 $275 $300 $325Mar 2,516 1,828 $411 $225 $250 $275 $300 $325Apr 2,336 1,768 $417 $225 $250 $275 $300 $325May 2,428 1,696 $363 $225 $250 $275 $300 $325Jun 2,220 1,752 $432 $225 $250 $275 $300 $325Jul 1,704 1,324 $321 $225 $250 $275 $300 $321

Savings and Cost SummaryProposed kVAR: 450 500 550 600 650Cost Savings (CS, $/Yr): $2,700 $2,988 $3,263 $3,523 $3,717AR Cost (IC, $): $9,000 $10,000 $11,000 $12,000 $13,000Payback (Years): 3.3 3.3 3.4 3.4 3.5Incremental Payback (Years): 3.5 3.6 3.8 5.2

POWER FACTOR CORRECTION

Power ComapanyMeter Number:Excess kVAR Percentage: 40%Reactive Power Charge: $0.50 /kVARCorrection Cost per kVAR: $20 /kVAR

Present Conditions Proposed Excess kVARExcess kVAR Correction

Month kW kVAR kVAR 450 500 550 600 650Aug 2,476 1,580 590 140 90 40 0 0Sep 2,600 1,656 616 166 116 66 16 0Oct 2,312 1,400 475 25 0 0 0 0Nov 2,060 1,404 580 130 80 30 0 0Dec 2,016 1,436 630 180 130 80 30 0Jan 2,224 1,552 662 212 162 112 62 12Feb 2,368 1,640 693 243 193 143 93 43Mar 2,516 1,828 822 372 322 272 222 172Apr 2,336 1,768 834 384 334 284 234 184May 2,428 1,696 725 275 225 175 125 75Jun 2,220 1,752 864 414 364 314 264 214Jul 1,704 1,324 642 192 142 92 42 0

Present Conditions Proposed Cost SavingskVAR kVAR Correction

Month kW kVAR Charge 450 500 550 600 650Aug 2,476 1,580 $295 $225 $250 $275 $295 $295Sep 2,600 1,656 $308 $225 $250 $275 $300 $308Oct 2,312 1,400 $238 $225 $238 $238 $238 $238Nov 2,060 1,404 $290 $225 $250 $275 $290 $290Dec 2,016 1,436 $315 $225 $250 $275 $300 $315Jan 2,224 1,552 $331 $225 $250 $275 $300 $325Feb 2,368 1,640 $347 $225 $250 $275 $300 $325Mar 2,516 1,828 $411 $225 $250 $275 $300 $325Apr 2,336 1,768 $417 $225 $250 $275 $300 $325May 2,428 1,696 $363 $225 $250 $275 $300 $325Jun 2,220 1,752 $432 $225 $250 $275 $300 $325Jul 1,704 1,324 $321 $225 $250 $275 $300 $321

Savings and Cost SummaryProposed kVAR: 450 500 550 600 650Cost Savings (CS, $/Yr): $2,700 $2,988 $3,263 $3,523 $3,717AR Cost (IC, $): $9,000 $10,000 $11,000 $12,000 $13,000Payback (Years): 3.3 3.3 3.4 3.4 3.5Incremental Payback (Years): 3.5 3.6 3.8 5.2

AR No. 9

Quick-change Fixtures

Recommended Action Make more quick-change fixtures for the Matsura 3 milling machine to increase utilization time.

Assessment Recommendation Summary Overtime Production Cost Implementation Payback

Hours Pumps Savings Cost (years) 880 900 $44,400 $5,000 0.1

Background Currently the milling department has 3 Matsura milling machines and 5 Chiron milling machines. Parts either come from the Chirons to the Matsuras or directly from raw materials to the Matsuras. With up to 100 parts per hour being fed to the Matsuras, which are processing an average of 54 parts per hour, overtime is incurred to keep up with production. This department is the current constraint in the plant. Matsura 1 and 2 are set up to run only certain types of parts. They are currently utilized 90% of the time (CU1 and CU2). Matsura 3 is set up to run a variety of short run jobs with quick-change fixtures and is currently utilized 40% of the time (CU3). The reason it is not utilized more is because there are not quick-change fixtures available to run the same types of jobs as are run on Matsura 1 and 2. This inflexibility results in batches of parts milled on the Chirons waiting in queue for the one Matsura that can run those parts. Parts sometimes wait for several days. Employees in the area say this contributes to overtime because of promises to the customer of a certain delivery time and then if the parts are waiting too long for a particular machine the order falls behind schedule. Currently the department incurs 10 overtime labor hours each week and operates an additional 20 Saturdays annually, which incur an average of 18 overtime labor hours each. This is a total of 880 overtime labor hours per year (OT). Anticipated Savings Based on the current 4,840 operating hours per year (OH) we calculated the annual machine hours currently utilized (CU) by the Matsura milling machines as follows: CU = (CU1 + CU2 +CU3) x OH = (90% + 90% + 40%) x 4,840 hours/year = 10,650 hours/year We were told by the lead mill operator that 90% utilization of the machines is the maximum (MU%) available with tool changes and maintenance. Since Matsuras 1 and 2 are currently

utilized to their maximum capacity we recommend continuing to operate them in the same way. Additional utilization of Matsura 3 will be possible with more fixtures. We calculated this additional availability using the maximum hours available with 90% utilization for all 3 milling machines (#M) and subtracting the required quick-change setup time on Matsura 3. We estimated the number of changeovers per day (CD) as follows: CD = DOH ÷ (APB ÷ APH) = 17 hours/day ÷ (60 parts/batch ÷ 18 parts/hour) = 5 changes/day Where; DOH = Desired daily operating hours (scheduled operating hours without overtime.) APB = Average parts per batch in the milling area estimated by the lead operator. APH = Average parts per hour run a Matsuras calculated from company process flow charts. The quick changes take between 45 minutes and 1 hour to perform. We use the average of 0.875 hours (QCT) in the following calculation. The proposed utilization time (PU) of the milling machines is: PU = MU% x #M x DAH – CD x QCT x OD = 90% x 3 x 4,420 hours/year – 5/day x 0.875 hour x 260 days/year = 10,800 hours/year Where; OD = Desired milling department annual operating days (not operating any Saturdays) DAH = Desired annual operating hours (scheduled operating hours without overtime.) The increase in machine time (MT) available using quick-change fixtures is: MT = PU – CU = 10,800 hours/year – 10,650 hours/year = 150 machine hours/year This 150 hours additional machine time is made available within the desired 4,420 annual operating hours, which does not allow for any overtime. Therefore the milling departments overtime labor cost is eliminated. From company wage structure sheets we calculated the average burdened overtime wage at $23.36 per hour (AOW). Total annual labor savings (LS) will be: LS = OT x AOW = 880 hours/year x $23.36/hour = $20,600/year

Since the Matsuras are the current production constraint additional savings come from the extra 150 machine hours made available. The additional production (AP) from these hours are calculated as follows: AP = MT x APH ÷ PP = 150 hours/year x 18 parts/hour ÷ 3 parts/pump = 900 pumps/year Where; PP = Number of parts that go through the Matsuras for each pump. We assume that there will not be another constraint to prevent the additional 900 pumps from being manufactured, and that your company has a 10% profit margin (PM). With the average revenue from each pump, which we found from your production and sales records to be $264 (AR), we estimated the savings for this additional production (SP) as: SP = AP x PM x AR = 900/year x 10% x $264 = $23,800/year

Savings Summary Cost

Source Quantity Units $ Labor Savings 880 Hours $20,600 Increased Production 900 Pumps $23,800 Total $44,400

Implementation Cost Two fixtures (#F) will have to be made that hold the type of parts that run on Matsura 1 and 2. Previous fixtures made for Matsura 3 cost up to $2,500 each ($F). Total implementation cost (IC) will be: IC = #F x $F = 2 fixtures x $2,500/fixture = $5,000 The annual savings will pay for the implementation cost in 0.1 years.

AR No. 10

Automate Pattern Shop

Background Install a CNC five axis mill and support software in the pattern (mold) making department to reduce labor cost.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) 0 $1,040,000 $1,300,000 1.3

Background The plant creates and stores its own molds/patterns for the production of pump components. Currently, all pattern drawings are created with computer aided design (CAD) software and fabricated, by hand, using skilled workers. The time and labor involved in creating a new pattern is considerable. Since the pattern makers are skilled craftsman, their wages are $70 per hour. A computer numerical control (CNC) milling machine can be used to create these patterns at greater precision and speed. Since the patterns are of complex shapes, we assume the milling machine will have to operate with five degrees of freedom. This will require sophisticated support software to generate the machine code. A computer aided machining (CAM) package will have to be purchased that is capable of generating the machine code. Also, the CAM software must be able to interface with the CAD software that generates the part drawings. We assume your present CAD system will either be too cumbersome or unable to handle the level of detail required by the CNC milling machine. In short, the CAD, CAM, and CNC mill must be compatible with each other. Anticipated Savings Savings will result from reducing the labor cost required to create the patterns. Once the proposed system is in place, the labor requirements will be to program the CAM files from the CAD drawings and to run the mill. We assume two employees, skilled with CNC machinery, would be required at a wage of $25 per hour.

The labor cost savings (LC) is determined as the difference of the existing labor cost of employing eight pattern makers versus employing two CNC machine operators. The following table compares the existing and proposed labor statistics. Labor Statistics Summary

Num. of Operating Employee Total Labor Force Employees Wage Hours Hours Cost

Existing 8 $70 /hr 2,040 16,320 $1,142,400 Proposed 2 $25 /hr 2,040 4,080 $102,000 Savings 6 $45 /hr 12,240 $1,040,000

The accuracy of the milling machine is high so little finishing work will be needed for the patterns. Implementation Cost As described under Background, we will assume a new CAD package, a CAM software package, and a 5-axis CNC milling machine will be required. The CAD software should be a three dimensional solid modeller with the ability to represent complex 3D surfaces. An example would be something like Catia. This will also require a powerful computer, such as a UNIX or Windows NT workstation. The following table summarizes the cost associated with implementing the software and equipment.

Implementation Cost Item Cost

5-axis milling machine $1,250,000 CAM software $10,000 CAD software $30,000 Workstation computer $10,000 Total $1,300,000

The savings will result in a simple payback of 1.3 years.

AR No. 11

Retail Line Case Erector Recommended Action Install box erectors to fold open and bottom seal boxes to reduce the cost of labor.

Assessment Recommendation Summary Energy Cost Implementation Payback

(106Btu) Savings Cost (years) -30 $229,748 $79,349 0.3

Background

While visiting your plant, we observed that a great deal of labor was being spent on the boxing end of the production line. There were two laborers on each of five lines. Each laborer spent approximately 4 seconds building a box, then eleven seconds waiting for the other laborer before they began filling their box. We recommend cutting labor to one worker per line. For the single worker to keep up with production, we suggest the purchase of a case erecting machine for each line in order to perform the routine box assembly. A sixth worker can float between the lines to be certain that no line falls behind, and to relieve individual lines for breaks. Anticipated Savings With a semiautomatic case erector, automated box assembly can result in considerable savings on the amount of labor required. Time to set up is minimal. Each box erector can assemble more than 600 cases per hour, which is more than adequate to keep up with your production of 2000 to 3600 cases for each of the five workstations per day. Labor required for the current production system (CL) is hours of operation (H) times the number of workers (N) on the boxing end of the bagged chip line.

CL = H x N = 4,640 production hr /yr x 10 workers = 46,400 hr /yr Labor required for the new system (NL) is given by

NL = H x N = 4,640 production hr /yr x 6 workers = 27,840 hr /yr

Labor savings (LS) is the difference between the current labor requirements and the new labor requirements.

LS = CL – NL = 46,400 hr /yr – 27,840 hr /yr

= 18,560 hr /yr Labor cost savings (LCS) at an average burdened wage (AW) of $10 x 1.24 = $12.40 /hour is LCS = LS x AW = 18,560 hr /yr x $12.40 /hr = $230,144 /yr Approximate number of cases produced in a year (NC) at an average of 14,000 cases per day is given by the following

NC = 14,000 cases /day x 260 days = 3,640,000 cases /yr Each of the case erectors will require two 0.17 horsepower (HP) motors and 1.25 cubic feet per minute of compressed air (CA). The air will be supplied by a three phase, three horsepower (HP) air compressor with tank which can supply 10.9 cubic feet per minute of air when running continuously. The motors will run for an average of 6 seconds per box (BT). The total energy used (E) is the energy used to build one box multiplied by the total number of boxes built by all five case erectors.

E = BT x M# x HP x kW/HP x NC = 6 sec /case x 1 hr/ 3,600 sec x 2 motors x 1/6 HP x 0.746 kW /HP x 3,640,000 cases /yr

= 1,509 kWh /yr where M# = Number of motors per box erector: 2 HP = Size of motors in horsepower: 1/6 HP The energy use (E) associated with the compressor is calculated by the power required (HP) times hours in use (HU) x percent of the time operating (PO), which is cubic feet per minute required / compressor output in cubic feet per minute. This increased energy use is given by the following

E = HP x HU x PO = 3HP x 0.746 kW/HP x 4,640 hours /yr x 7.5 CFM / 10.9 CFM = 2.238 kW x 4,640 hr /yr x 69% of the time = 7,145 kWh /yr where CFM = cubic feet per minute of air Total energy use, then, is the sum of case erector and compressor energy use E = 1,509 kWh /yr + 7,145 kWh /yr

= 8,654 kWh /yr The demand cost associated with this increased electricity use is small, so it will be neglected for these calculations. The total annual energy cost (EC) is kilowatt hours used (E) times cost per kilowatt hour (C) plus demand cost, which is negligible. This energy cost is given by the following EC = E x C = 8,654 kWh /yr x $0.0458/kWh = $396 /yr The training cost for the new system is assumed to be negligible because case erectors are very simple to operate, and there will be 40 percent fewer workers to train. According to the manufacturer, maintenance cost is also negligible, since these machines are mechanically very simple and can operate for many years without major problems. It is assumed that current maintenance staff will be able to perform routine tasks such as lubrication and minor adjustments. The total annual cost savings (CS) is the labor cost savings (LCS) less additional energy use (E) CS = LCS – E = $230,144 /yr - $396 /yr = $229,748 /yr

The following table summarizes the savings associated with this new system

Savings Summary Energy Cost

Source Quantity Units 106Btu $ Personnel Changes 18,560 hours 0 $230,144

Electricity -8,654 kWh -30 ($396) Total -30 $229,748

Implementation Cost The implementation cost (IC) for purchasing and installing five case erecting systems (CE) and an appropriate air compressor (AC) is given by the following IC = C# x CE + AC + I

= 5 x $14,685 + $4,124 + $1,800 = $79,349

Where I = Installation cost C# = Number of case erectors The cost savings will pay for the implementation cost in 0.3 years. If the cost of implementation exceeds what is allowed in the budget, then the purchase of less than five case erectors is another option. If this option is exercised, then the savings (S) per erector purchased will be the following S = LCS x 1/5 – EC x 1/5 = $230,144 /yr x 1/5 - $396 /yr x 1/5 = $45,950 /yr And the implementation cost for each erector will be IC = CE + I x 1/5 = $14,685 + $1,800 x 1/5 = $15,045 An air compressor will be necessary no matter how many case erectors are purchased. However, for fewer case erectors, lower airflow volume, and therefore a less expensive air compressor, will be required.

If minimal capital investment is desired, various lease options are available. The implementation cost would then be the cost of installation, about $360 per case erector, plus the cost of the air compressor plus any lease inception fees.

6. OTHER MEASURES CONSIDERED These measures were considered but not recommended because: (1) they are alternatives to measures that were recommended; (2) the payback period is too long; (3) we were unable to obtain the information necessary to estimate savings or cost accurately; or (4) the measure would adversely affect production. Some measures are included in response to specific questions you raised during the plant visit, but which do not appear to be feasible at the present time. However, they may become feasible in the future as conditions change. 1. Install Metal Shavings Compactor : During the site visit, we observed waste steel shavings. These waste shavings were produced from long steel rods that are machined to make parts used in the assembly of products. The shavings are collected at each workstation in a small dumpster. Once the dumpsters are full, the borings are sold to a recycling company. Use of the metal shavings compactor will increase the value of the waste borings by approximately two times. The metal shavings compactor takes the shavings and compresses them into disc shaped pieces of metal with a diameter of three or five inches. The product can then be sold to the same recycling company as a solid, which increases the value of the steel. Approximate annual generation of funds by increasing waste metal (681,460 lb.) by two times would be $6,227. Because of the high implementation cost associated with the machine resulting in a simple payback of 14.2 years, we are not exploring this recommendation. 2. Replace Broken Windows. There is a large amount of heat escaping through the companies broken windows. We could not acquire an accurate count of the broken windows, so the amount of heat loss could not be determined. The amount of glass needed to replace the broken windows also could not be determined for this same reason. 3. Implement Coolant Management. Coolant is used in the milling machines to remove heat, dirt and metal shavings from the cutting tool. Currently, coolant is changed approximately once per week or whenever the coolant smells bad. The coolant might still have appreciable wear life left but since it smells bad or has been in the machine for a week, the coolant is changed. Implementing a coolant management team could greatly lower labor, coolant, and waste coolant costs by extending coolant life. 4. Install High Precision Laser Cutter. Currently you are using a gas torch to cut steel plate. You are using a 1 inch spacing between cuts to protect the parts from deformation caused by heating and cooling on the water table. It is possible to decrease this gap and do back to back cutting with a laser because the heat affected zone on the steel from the laser is much smaller than that of a cutting torch. This would result in materials savings in steel plate used by your company. The laser cut is also much cleaner than a gas torch, reducing finish machining. An automated CNC laser cutting system with continuous wave laser output of at least 1.6kW would be necessary to cut 1/2 inch steel. Due to the expense of operating the laser and the expense of purchasing and installing the CNC machine, we were unable to recommend this process change. We would recommend this equipment of resources if you will need high speed, high accuracy cutting for products in the future. Our calculations of the savings are shown below.

Anticipated Savings Savings occur because the amount of raw materials purchased, and steel scrap recycled, can be reduced. Labor is also reduced because fewer cuts are made per part requiring less operating time on the machine. According to company records, 3,524,100 lbs of steel is purchased annually. Waste bills show that skeleton plate and scrap steel represent 651,260 lbs annually. This waste is representative of 18% of the purchased steel. Considering the waste blown out of the kerf of the cut, the approximation of wasted steel goes to 20%. Various part shapes are cut from the steel, including squares, circles, and odd shapes. To maximize the number of parts per plate, the operator must carefully program the part layout, allowing parts to share cuts. Cutting all squares would produce little waste, while all circles would waste 14% of the steel. Approximate waste for well organized odd parts is 10%. The average waste generated cutting these various shapes is 8% of the purchased steel. This is a significant reduction from the current waste of 20%. By reducing waste, less steel will have to be purchased to produce the same number of finished parts. Currently, 80% (100%-20%) of each steel plate (CW) arrives as final product. The proposed laser cutter would allow 92% (100%-8%) of each plate (PW) to be used. Therefore, the reduction of steel plate is calculated as a percentage of current use (NS). NS = 1 - (CW / PW) = 1 - (80% / 92%) = 13% A 13% reduction of steel use will reduce the steel purchase by an amount (SA) shown below. SA = current amount of steel x NS = 3,524,100 x 13% = 458,100 lb With a purchase price of steel at $0.36 /lb of steel (RSC), the steel cost savings (SS) are shown below. SS = SA x RSC = 458,100 x $0.36 /lb = $164,900 Waste steel is also reduced by the amount SA, which will reduce the savings. Waste steel is sold at a cost of $0.03 /lb (WSC), and the reduction in scrap revenue scrap (SR) is shown below. SR = SA x WSC = 458,100 lb x $0.03 /lb = $13,750 The total savings (TS) from the reduction of steel purchase and scrap recycling will be:

TS = SS - SR = $164,900-$13,750 = $151,150 With a laser cutter and proper nesting, the amount of cuts per part will be decreased. Therefore, the production of an equal amount of parts can be accomplished in less time. Squares represent approximately a third of the parts cut, and a laser cutter will reduce the number of cuts necessary to make a square from 4 to 2 if sides are shared (1/2 less). Circles are another third of production and will still require one cut. Odd shapes are estimated to share one out of four sides. The time savings (ST) possible by reducing the number of cuts is shown below. ST = square production x 1/2 + odd shape production x 1/4 = 33% x 0.50 + 33% x 0.25 = 25% The annual Labor Savings (LS) will be incurred because the employees will spend less time manning the machines. The saving based on a wage of $15.00 /hr including benefits (W). LS = W x EH x ST = $15 .00 /hr x 4,080 hrs/yr x 25% = $15,3000 where, EH = annual operating hours: 4,080 Implementation Cost The implementation cost would be between $1-2 million, therefore the payback is too long. There is also a high energy cost associated with use of the laser.

APPENDIX A

MOTORS

A.1. MOTOR WORKSHEET DEFINITIONS The motor worksheet uses information obtained during the on-site visit to calculate electric motor energy use, as well as energy and cost savings for efficiency improvements. Motor worksheet information is also used for a variety of AR's, including refrigeration, air compressors, and turning off equipment. In addition, the information contained in the worksheet aids in determining an accurate plant energy breakdown. The worksheet calculation methods and symbols are described as follows: A.2. Motor Inventory (Nameplate) The Motor Inventory contains the manufacturer, horsepower, volts, amps and revolutions per minute (rpm), that are read directly from each motor nameplate. Standard NEMA values are used to estimate full load efficiency and power factor. Identification Number (ID#). An identification number is assigned to each motor. Manufacturer. The manufacturer of the motor. Horsepower (Hp). Nameplate horsepower. Volts. Rated voltage for the motor. If the motor can be wired for more than one voltage, the voltage closest to the operating voltage is entered. Amps. The rated full-load amperage of the motor corresponding to the voltage listed above. RPM. Rated full-load RPM. Power Factor (PF). The motor power factor at full load. Power factor is primarily taken from General Electric publications GEP-500H (11/90) and GEP-1087J (1/92). See section A.9 Motor Performance Table for data and other sources. Efficiency (EFF). The present motor efficiency at full load. Motor efficiencies for standard and energy-efficient motors are also taken from General Electric publications GEP-500H (11/90) and GEP-1087J (1/92). See section A.9 Motor Performance Table. Type. The type of motor is described in the table at the bottom of the inventory page. The purpose is to identify standard 900, 1200, 1800, and 3600 rpm motors (Type = 1) that could be replaced with energy-efficient motors. A.3. Motor Applications (Measured Operating Conditions) The Motor Applications page contains application-specific information. The same motor may be used in several applications. This information is used to calculate the annual energy consumption of each application.

Application Number (#). A number is assigned to each application described in this section. Area. A brief description of the location of the motor application. Identification Number (ID#). The identification number of the motor used in the application. The worksheet looks up the nameplate information for each motor application in section A.2 Motor Inventory. Use. Each use, such as refrigeration, is given a separate code. This allows the energy use and operating cost for each end use to be summarized in section A.7 Motor Use Summary. Description. A brief description of the motor application. Quantity (Qty). The number of motors in each application of the same horsepower and type. Horsepower (Hp). The horsepower of the motor(s) used in this application is looked up in section A.2 Motor Inventory, based on the motor ID#. Total Horsepower (Hptot). The total horsepower used in the application is the product of the quantity of motors and the motor horsepower. Power Factor (PF). For motors with no power factor correction, the operating power factor of the motor is approximated by the following equation to account for part-load conditions: PF = Nameplate PF x {0.728 + [0.4932 / (FLA%)] - [0.2249 / (FLA%)2]} The power factor correction, enclosed in ({}) brackets, has a minimum allowable value of 0.3 and a maximum value of 1.0 when FLA% is 90% or greater in the worksheet, and is shown as a curve in section A.10. If the motor has been corrected for power factor (PFC = "C"), or the motor is a synchronous type, 0.95 power factor is used. Power Factor Correction (PFC). If a motor has power factor correction capacitors and the amperage has been measured ahead of the capacitors, a "C" is input. Drive (DRV). All motors with standard V-belt drives (b) are considered for replacement with High Torque Drive (HTD) belts and sheaves. HTD Replacements are summarized in Section A.5. Volts. Measured operating voltage. Amps. Measured operating amperage. Use Factor (UF). Use Factor is the percentage of the annual operating hours the motor is actually running. Percent Full Load Amps (FLA%). The measured operating amperage divided by the motor nameplate full load amps. Efficiency (EFF). Present motor efficiency (η0) is looked up in section A.2 Motor Inventory, based on the motor ID#.

Demand. The operating power (D) of the motor in kilowatts (kW). If the operating amperage is known, the following equation is used: D = Qty x Volts x Amps x PF x 1.73 / 1,000 If operating amperage is not known, the motor load factor (LF) is estimated depending on motor application at your plant. Motor load was either modeled after similar applications at your plant or derived from averaged application specific data of over 160 previous audits. The operating power is found from D = Qty x LF x (0.746 kW/Hp) x Hp / η0 Load Factor (LF). The operating input power divided by the motor nameplate full-load input power, which is found from LF = (D x η0) / [Hp x (0.746 kW/Hp)] Hours. The annual motor operating hours (H) are entered in section A.7 Motor Use Summary for each use. Energy. The annual energy consumption (E) of the motor in kilowatt-hours (kWh) is calculated by: E = D x H x UF A.4. Motor Use Summary The Motor Use Summary summarizes motor power and energy requirements by end use. A.5. Economics The Economics Table summarizes the electrical energy and demand costs, payback criterion, and motor lifetime. Energy Cost. The electrical energy charge ($/kWh) is taken from your rate schedule. If the energy charge varies seasonally, the average cost is used. Demand Cost. The demand charge ($/kW-Month) is taken from your rate schedule. If the demand charge varies seasonally, the average cost is used. Payback Criterion. Standard motors that are candidates for replacement with energy-efficient motors are listed in section A.3 Motor Efficiency. Motors for which the payback is less than this criterion are included in the total at the bottom of the table and included in the Energy Efficient Motors AR.

A.6. Diversity Factor Diversity Factor (DF). The diversity factor is a tool to estimate the amount of demand a particular motor will contribute to measured peak demand charges. This is a function of average billed demand, found in Section 4; total lighting demand, found in Lighting Inventory Appendix B.2; and the calculated motor demand found in Motor Use Summary Appendix A.7. The diversity factor for your plant is calculated in the diversity factor table. Diversity factor (DF) is calculated from DF = (Average Billed Power - Total Lighting Power)/ Total Motor Power The diversity factor accounts for the amount that a particular motor will affect the peak demand, and is a function of billed peak, lighting, and calculated motor demand. The diversity factor is never above 100%. A.7. Motor Performance Table The Motor Performance Table contains general motor information used in the worksheet. For each motor horsepower, efficiency, motor cost, and power factor for both standard and efficient motors are listed. Information is primarily taken for totally enclosed fan cooled (TEFC) motors from General Electric publications GEP-500H (11/90) and GEP-1087J (1/92). Larger motors that are not available in TEFC configuration are Open Drip Proof (ODP), and are shown in italics. For motors not found in the General Electric publications, the values for efficiency, motor cost, and power factor were taken as averaged values of several motor manufacturers from Motor Master, a database available from Washington State Energy Office. These sections are indicated by shading in Table A.9. A.8. Power Factor Power factor is graphed as a function of operating amperage (FLA%). The curve approximates motor performance data taken from General Electric publication #GEP-500G (3/87). The graph is used to calculate power factor in section A.2 Motor Applications.

A.2. Motor Inventory (Nameplate)*

ID# Manufacturer Hp Volts Amps RPM PF EFF Type+1 Baldor 0.33 115 3.1 3600 73 68 F2 Baldor 0.5 440 0.7 3600 63 67 F3 Baldor 0.5 115 5 3600 63 67 F4 **N/A** 1 460 1.3 1800 76 72 15 Baldor 1.5 440 1.8 1800 78.5 77 16 **N/A** 2 440 3 1750 79 80 17 **N/A** 2.5 460 3.1 1800 79 80 18 **N/A** 3 440 4.3 1750 79 82.5 19 Baldor 3 440 4.2 3450 81 82.5 1

10 Baldor 5 230 6.4 1725 84 84 111 **N/A** 5 460 6.2 1800 84 84 112 Baldor 5 230 12.5 3450 82 84 113 Baldor 5 460 6 3456 88 89.5 E14 **N/A** 5 440 6.5 3475 82 84 115 **N/A** 7.5 460 9 1800 83 86.5 116 **N/A** 10 460 12.5 1800 85 87.5 117 **N/A** 10 460 12 1800 75 85 C18 Baldor 10 460 12 3450 83.5 87.5 119 **N/A** 10 460 12.5 3600 83.5 87.5 120 **N/A** 20 440 25 3500 90 87.5 121 Limitorque 25 460 31 1750 85 90.2 122 GE 25 440 31.9 1760 85 90.2 123 **N/A** 25 460 30 1800 85 90.2 124 **N/A** 30 460 36 1800 75 85 C25 **N/A** 30 460 38 3600 91.5 89.5 126 Westinghouse 40 460 47.8 3530 85.5 88.5 127 Pace Maker 50 460 67 1185 87 91 128 GE 50 230 185 1200 87 91 DC29 **N/A** 50 460 60 1800 75 85 C30 **N/A** 60 460 72 1800 75 85 C31 US Motor 65 440 73.5 1800 82.5 91.7 132 **N/A** 75 460 94 1200 79 91 133 **N/A** 75 460 90 1800 75 85 C34 **N/A** 100 460 120 1800 75 85 C35 **N/A** 100 460 125 1800 87 91.7 136 **N/A** 100 460 125 3600 89 90.2 137 **N/A** 120 460 145 1800 75 85 C38 **N/A** 125 460 150 1800 75 85 C

A.2. Motor Inventory (Nameplate)*

ID# Manufacturer Hp Volts Amps RPM PF EFF Type+39 Reliance 150 460 178 1190 87.9 93 140 **N/A** 150 460 169 1740 86.5 93 141 GE 150 440 178 1770 86.5 93 142 **N/A** 150 460 187 3600 92 91.7 143 GE 200 440 250 1165 87.8 94.1 144 Allis Chalmers 200 440 250 2200 93.9 93 HD45 US Motor 250 440 300 1200 85 94.3 146 **N/A** 250 460 312 1800 88.5 93.6 147 GE 300 440 374 700 87 94.5 R48 **N/A** 300 440 375 720 87 94.5 R49 Fair Banks Morse 300 2300 67 1175 88.5 95 HD50 GE 300 440 360 1185 88.5 95 151 Reliance 300 460 330 1800 90 94.1 152 Fair Banks Morse 300 440 342 3560 92 91 153 GE 300 440 355 3570 92 91 154 Westinghouse 300 460 334 3580 92 91 155 Westinghouse 400 460 445 3555 93 91.7 156 **N/A** 500 2300 110 1800 89 94.5 O57 GE 500 2300 113 3570 90 94.1 O58 **N/A** 500 2300 110 3600 90 94.1 O59 **N/A** 600 2300 132 1200 87 94.5 O60 Allis-Chalmers 600 2300 130 3575 90 94.1 O61 **N/A** 800 4000 96 1800 89 94.5 O62 Allis-Chalmers 1250 4000 150 3580 90 94.1 O63 **N/A** 1500 2300 331 1800 89 94.5 O64 Allis-Chalmers 1500 2300 331 3580 90 94.1 O65 **N/A** 2500 2300 550 3600 90 94.1 O66 **N/A** 3000 4160 362 3580 90 94.1 O67 Westinghouse 5000 4000 600 1789 89 94.5 O68 Westinghouse 5000 4160 600 3585 90 94.1 O

+ Type Code1=Standard E=High Efficiency HD=Heavy Duty2=Two Speed F=Fractional Horsepower O=Oversize ( >500hp)C=Composite G=Gear Motor S=SynchronousDC=Direct Current H=Hermetic U=UnknownR=Not 900, 1200, 1800 or 3600 RPM*Note: Some Nameplate Data May Be Estimated

A.3. Motor Applications (Measured Operating Conditions)

# Area ID# Use Description Qty Hp Hptot PF DRV PFC Volts Amps UF FLA% EFF Demand LF Hours Energy1 R & D 14 1 Hydrodynamic Test Motor: VM-5 1 5 5 82 2 84 2.7 60 6120 3302 Testing Area 13 1 Hydrodynamic Test Motor 2 5 10 88 10 89.5 5.8 70 6120 35503 R & D 16 1 Hydrodynamic Test Motor: HM-66 1 10 10 85 4 87.5 5.1 60 6120 12484 Testing Area 18 1 Hydrodynamic Test Motor 1 10 10 83.5 10 87.5 6 70 6120 36725 R & D 19 1 Hydrodynamic Test Motor: HM-32 1 10 10 83.5 4 87.5 5.1 60 6120 12486 R & D 20 1 Hydrodynamic Test Motor: VM-6 1 20 20 90 3 87.5 10.2 60 6120 18737 Testing Area 22 1 Hydrodynamic Test Motor 1 25 25 85 10 90.2 14.5 70 6120 88748 R & D 23 1 Hydrodynamic Test Motor: HM-8 1 25 25 85 3 90.2 12.4 60 6120 22779 Testing Area 21 1 Hydrodynamic Test Motor 1 25 25 85 10 90.2 14.5 70 6120 8874

10 R & D 25 1 Hydrodynamic Test Motor: HM-30 1 30 30 91.5 4 89.5 15 60 6120 367211 Testing Area 26 1 Hydrodynamic Test Motor 1 40 40 85.5 10 88.5 23.6 70 6120 1444312 Testing Area 27 1 Hydrodynamic Test Motor 1 50 50 87 10 91 28.7 70 6120 1756413 R & D 29 1 Hydrodynamic Test Motor: VM-12 1 50 50 75 2 85 26.3 60 6120 321914 Testing Area 31 1 Hydrodynamic Test Motor 1 65 65 82.5 10 91.7 37 70 6120 2264415 R & D 32 1 Hydrodynamic Test Motor: OHM-9 1 75 75 79 5 91 36.9 60 6120 1129116 R & D 36 1 Hydrodynamic Test Motor: VM-8 1 100 100 89 2 90.2 49.6 60 6120 607117 R & D 36 1 Hydrodynamic Test Motor: HM-31 1 100 100 89 9 90.2 49.6 60 6120 2732018 R & D 35 1 Hydrodynamic Test Motor: RD-100 1 100 100 87 8 91.7 48.8 60 6120 2389219 Testing Area 39 1 Hydrodynamic Test Motor 1 150 150 87.9 10 93 84.2 70 6120 5153020 Assembly 42 1 Hydrodynamic Test Motor: HM-19 1 150 150 92 3 91.7 73.2 60 6120 1344021 R & D 42 1 Hydrodynamic Test Motor: RD-150 1 150 150 92 13 91.7 73.2 60 6120 5823822 Testing Area 41 1 Hydrodynamic Test Motor 1 150 150 86.5 10 93 84.2 70 6120 5153023 Testing Area 43 1 Hydrodynamic Test Motor 1 200 200 87.8 10 94.1 111 70 6120 6793224 Testing Area 44 1 Hydrodynamic Test Motor 1 200 200 93.9 10 93 112.3 70 6120 6872825 Testing Area 45 1 Hydrodynamic Test Motor 1 250 250 85 10 94.3 138.4 70 6120 8470126 R & D 46 1 Hydrodynamic Test Motor: OHM-5 1 250 250 88.5 11 93.6 119.6 60 6120 8051527 Testing Area 54 1 Hydrodynamic Test Motor 2 300 600 92 10 91 344.3 70 6120 21071228 Assembly 47 1 Hydrodynamic Test Motor: HM-15 1 300 300 87 2 94.5 142.1 60 6120 1739329 Assembly 48 1 Hydrodynamic Test Motor: HM-17 1 300 300 87 2 94.5 142.1 60 6120 1739330 Assembly 53 1 Hydrodynamic Test Motor: HM-5 1 300 300 92 3 91 147.6 60 6120 2709931 Testing Area 47 1 Hydrodynamic Test Motor 1 300 300 87 10 94.5 165.8 70 6120 10147032 Testing Area 52 1 Hydrodynamic Test Motor 1 300 300 92 10 91 172.2 70 6120 10538633 Testing Area 50 1 Hydrodynamic Test Motor 1 300 300 88.5 10 95 164.9 70 6120 10091934 Testing Area 53 1 Hydrodynamic Test Motor 1 300 300 92 10 91 172.2 70 6120 10538635 Testing Area 49 1 Hydrodynamic Test Motor 1 300 300 88.5 10 95 164.9 70 6120 10091936 Testing Area 55 1 Hydrodynamic Test Motor 1 400 400 93 10 91.7 227.8 70 6120 13941437 Testing Area 57 1 Hydrodynamic Test Motor 1 500 500 90 10 94.1 277.5 70 6120 16983038 R & D 58 1 Hydrodynamic Test Motor: RD-500-2 1 500 500 90 4 94.1 237.8 60 6120 5821339 R & D 56 1 Hydrodynamic Test Motor: RD-500-1 1 500 500 89 5 94.5 236.8 60 6120 7246140 Assembly 60 1 Hydrodynamic Test Motor: HM-21 1 600 600 90 4 94.1 285.4 60 6120 6986641 Assembly 59 1 Hydrodynamic Test Motor: HM-23 1 600 600 87 2 94.5 284.2 60 6120 3478642 Assembly 61 1 Hydrodynamic Test Motor: HM-22 1 800 800 89 3 94.5 378.9 60 6120 6956643 Assembly 62 1 Hydrodynamic Test Motor: HM-6 1 1250 1250 90 4 94.1 594.6 60 6120 14555844 Assembly 63 1 Hydrodynamic Test Motor: HM-33 1 1500 1500 89 2 94.5 710.5 60 6120 8696545 Assembly 64 1 Hydrodynamic Test Motor: HM-35 1 1500 1500 90 3 94.1 713.5 60 6120 13099946 Assembly 65 1 Hydrodynamic Test Motor: HM-7 1 2500 2500 90 2 94.1 1189.2 60 6120 14555847 Assembly 66 1 Hydrodynamic Test Motor: HM-29 1 3000 3000 90 11 94.1 1427 60 6120 96065648 Assembly 67 1 Hydrodynamic Test Motor: HM-26 1 5000 5000 89 7 94.5 2368.3 60 6120 101458049 Assembly 68 1 Hydrodynamic Test Motor: CHM-9 1 5000 5000 90 3 94.1 2378.3 60 6120 43665650 Light Bay 4 2 Half Ton Crane 5 1 5 76 10 72 3.6 70 7344 264451 Medium Bay 4 2 Half Ton Crane 1 1 1 76 10 72 0.7 70 7344 51452 Plate Shop 7 2 1 ton crane 1 2.5 2.5 79 10 80 1.6 70 7344 117553 Medium Bay 7 2 1 ton crane 2 2.5 5 79 10 80 3.3 70 7344 242454 Light Bay 7 2 1 ton crane 6 2.5 15 79 10 80 9.8 70 7344 7197

A.3. Motor Applications (Measured Operating Conditions)

# Area ID# Use Description Qty Hp Hptot PF DRV PFC Volts Amps UF FLA% EFF Demand LF Hours Energy55 Light Bay 7 2 1.5 ton crane 3 2.5 7.5 79 10 80 4.9 70 7344 359956 Medium Bay 7 2 1.5 ton crane 2 2.5 5 79 10 80 3.3 70 7344 242457 Nuclear Area 11 2 2 ton crane 1 5 5 84 10 84 3.1 70 7344 227758 Heavy Bay 11 2 2 ton crane 6 5 30 84 10 84 18.7 70 7344 1373359 Light Bay 11 2 2 ton crane 2 5 10 84 10 84 6.2 70 7344 455360 Medium Bay 11 2 2 ton crane 6 5 30 84 10 84 18.7 70 7344 1373361 Plate Shop 11 2 2 ton crane 13 5 65 84 10 84 40.4 70 7344 2967062 Heavy Bay 15 2 3 ton crane 1 7.5 7.5 83 10 86.5 4.5 70 7344 330563 Medium Bay 15 2 4 ton crane 1 7.5 7.5 83 10 86.5 4.5 70 7344 330564 Medium Bay 15 2 3 ton crane 1 7.5 7.5 83 10 86.5 4.5 70 7344 330565 Testing Area 23 2 10 ton crane 1 25 25 85 10 90.2 14.5 70 7344 1064966 Heavy Bay 33 2 20 ton hoist 1 75 75 75 10 85 46.1 70 7344 3385667 Heavy Bay 34 2 35 ton hoist 1 100 100 75 10 85 61.4 70 7344 4509268 Plate Shop 34 2 35 ton hoist 1 100 100 75 10 85 61.4 70 7344 4509269 Plate Shop 38 2 50 ton hoist 1 125 125 75 10 85 76.8 70 7344 5640270 Medium Bay 17 3 Band Saw 1 10 10 75 50 85 6.1 70 6120 1866671 Medium Bay 17 3 Cut Off Saw 1 10 10 75 50 85 6.1 70 6120 1866672 Medium Bay 24 3 Lathe:Yamazaki 1 30 30 75 70 85 18.4 70 6120 7882673 Medium Bay 24 3 Lathe:American Lathe 1 30 30 75 70 85 18.4 70 6120 7882674 Medium Bay 24 3 Lathe:Landis 2 30 60 75 70 85 36.9 70 6120 15808075 Medium Bay 29 3 Vertical Lathe:Ballard 1 50 50 75 70 85 30.7 70 6120 13151976 Medium Bay 33 3 Horizontal Mill:Kearney Lewis 1 75 75 75 70 85 46.1 70 6120 19749277 Medium Bay 37 3 Machine Table:Giddings Lewis 1 120 120 75 70 85 73.7 70 6120 31573178 Medium Bay 37 3 Machine Table:Allan Bradly 1 120 120 75 70 85 73.7 70 6120 31573179 Heavy Bay 17 4 Radial Drill:Bingnam Willamette 1 10 10 75 70 85 6.1 70 7344 3135980 Heavy Bay 17 4 5 ton crane 1 10 10 75 70 85 6.1 70 7344 3135981 Heavy Bay 24 4 CNC Mill:Giddings Lewis 1 30 30 75 70 85 18.4 70 7344 9459182 Heavy Bay 24 4 NC Machining:Cincinati Milcron 2 30 60 75 70 85 36.9 70 7344 18969683 Heavy Bay 29 4 Planer Mill:Bingnam Willamette 1 50 50 75 70 85 30.7 70 7344 15782384 Heavy Bay 29 4 Plane:Shin Nippon 1 50 50 75 70 85 30.7 70 7344 15782385 Nuclear Area 28 4 Machining Table:Betts 1 50 50 87 50 91 28.7 70 7344 10538686 Nuclear Area 33 4 Horizontal Facing:Giddings Lewis 1 75 75 75 50 85 46.1 70 7344 16927987 Heavy Bay 33 4 Horizontal Boring Mill 1 75 75 75 70 85 46.1 70 7344 23699188 Heavy Bay 33 4 Horzontal Boring Mill:Bingham Willamette 2 75 150 75 70 85 92.2 70 7344 47398289 Heavy Bay 33 4 Boring Mill:Lucus 1 75 75 75 70 85 46.1 70 7344 23699190 Heavy Bay 37 4 Boring Mill:Carlton 3 120 360 75 70 85 221.2 70 7344 113714591 Plate Shop 11 5 Shears 2 5 10 84 10 84 6.2 70 6120 379492 Plate Shop 17 5 Band Saw 2 10 20 75 10 85 12.3 70 6120 752893 Plate Shop 29 5 Rotating Table:Ransom 1 50 50 75 1 85 30.7 70 6120 187994 Plate Shop 30 5 Rotating TAble:Aronson 2 60 120 75 1 85 73.7 70 6120 451095 Boiler AC Room 11 6 Boiler Fans 2 5 10 84 70 84 6.2 70 7344 3187396 Air Compressor 40 7 Gardner-Denver 1 150 150 86.5 100 93 84.2 70 7344 61836597 Air Compressor 51 7 Sullair 32-300 1 300 300 90 10 94.1 166.5 70 7344 12227898 Light Bay 2 8 Baldor Grinder 1 0.5 0.5 63 30 67 0.4 70 6120 73499 Light Bay 6 8 Cincinatti Grinder 1 2 2 79 30 80 1.3 70 6120 2387

100 Light Bay 8 8 Wagner Electric Grinder 1 3 3 79 30 82.5 1.9 70 6120 3488101 Light Bay 9 8 Baldor Saw 1 3 3 81 30 82.5 1.9 70 6120 3488102 Lignt Bay 24 8 Lathe:Bingham Willamette 1 30 30 75 30 85 18.4 70 6120 33782103 Light Bay 29 8 Vertical Mill:Kearney Trecker 1 50 50 75 30 85 30.7 70 6120 56365104 Light Bay 29 8 Power Draw Bar:Bridgeport 1 50 50 75 30 85 30.7 70 6120 56365105 Light Bay 30 8 Turning Center:Cincinnati Milacron 2 60 120 75 30 85 73.7 70 6120 135313106 Nuclear 1 9 Baldor grinder 1 0.33 0.33 73 10 68 0.3 70 4080 122107 Nuclear 3 9 Baldor Grinder 1 0.5 0.5 63 10 67 0.4 70 4080 163108 Nuclear 5 9 Baldor grinder 1 1.5 1.5 78.5 70 77 1 70 4080 2856109 Nuclear 10 9 Baldor grinder 1 5 5 84 10 84 3.1 70 4080 1265110 Nuclear 12 9 Baldor grinder 1 5 5 82 10 84 3.1 70 4080 1265111 Nuclear 11 9 2 Ton crane 13 5 65 84 10 84 40.4 70 4080 16483112 Nuclear 17 9 Drill:Bridgeport 1 10 10 75 70 85 6.1 70 4080 17422113 Nuclear 24 9 Microstatic grinding machine:Brown and Sharpe 1 30 30 75 70 85 18.4 70 4080 52550114 Nuclear 29 9 Turrel Lathe:Bingham Willamette 1 50 50 75 70 85 30.7 70 4080 87679115 Nuclear 33 9 Floor mill:Bingham Willamette 1 75 75 75 70 85 46.1 70 4080 131662

A.4. Motor Use Summary

Use Description Hours Qty Hp kW kWh kWh%1 Hydrodynamic Testing 6120 51 28900 14113.8 4960461 45.2%2 Cranes and Hoists 7344 56 628.5 388 284949 2.6%3 Medium Machining Stations 6120 10 505 310.1 1313537 12.0%4 Heavy Machining Stations 7344 16 995 609.3 3022425 27.5%5 Misc. Motors 6120 7 200 122.9 17711 0.2%6 Boiler 7344 2 10 6.2 31873 0.3%7 Air Compressors 7344 2 450 250.7 740643 6.7%8 Light Machining Stations 6120 9 258.5 159 291922 2.7%9 Nuclear Test Area 4080 22 242.33 149.6 311467 2.8%

0 0 0 0 0.0%0 0 0 0 0.0%0 0 0 0 0.0%

Total 175 32189.33 16109.6 10974988 100.0%

A.5. Economics

Energy Cost: 0.03461 /kWh Demand Cost: $4.36 /kW-month Average Electricity Cost: 0.04497 /kWh Motor Payback Criterion: 10 years High Torque Drive Payback Criterion: 10 years

A.6. Diversity Factor

Average Monthly Billed Demand: 8702 kW Lighting Demand: 119 kW Total Motor Demand: 16109.6 kW Diversity Factor: 53%

A.7. Motor Performance Table900 RPM 1200 RPM

Horsepower Motor Efficiency Motor Cost Power Factor Motor Efficiency Motor Cost Power Factor(HP) Standard Efficient Increase Standard Efficient Increase Standard Efficient Standard Efficient Increase Standard Efficient Increase Standard Efficient

1 69.4 75.5 6.1 $283 $359 $76 62.0 59.5 75.5 82.1 6.6 $241 $302 $61 60.5 65.91.5 73.0 80.0 7.0 $343 $434 $91 61.7 62.0 75.5 87.5 12.0 $193 $253 $60 77.5 72.0

2 76.4 85.5 9.1 $459 $581 $122 61.7 54.0 80.0 87.5 7.5 $213 $280 $67 74.5 74.03 79.3 86.5 7.2 $597 $755 $158 66.4 62.5 85.5 89.5 4.0 $283 $373 $90 74.5 75.55 82.0 85.5 3.5 $824 $1,043 $219 67.3 60.0 84.0 89.5 5.5 $407 $548 $141 78.5 76.0

7.5 82.8 86.5 3.7 $1,049 $1,327 $278 69.3 62.0 86.8 91.7 4.9 $550 $740 $190 88.0 72.010 85.4 91.0 5.6 $1,243 $1,573 $330 77.2 78.0 87.5 91.7 4.2 $701 $869 $168 84.5 71.515 85.8 91.0 5.2 $1,633 $2,067 $434 75.5 78.0 88.5 91.7 3.2 $946 $1,153 $207 82.5 76.520 88.0 91.7 3.7 $1,968 $2,491 $523 78.6 77.5 90.2 92.4 2.2 $1,150 $1,403 $253 85.5 76.025 87.8 91.7 3.9 $2,331 $2,950 $619 78.3 78.0 88.5 92.4 3.9 $1,396 $1,703 $307 81.0 83.530 87.5 93.6 6.1 $2,746 $3,475 $729 80.0 76.5 89.5 93.0 3.5 $1,704 $1,952 $248 82.5 83.540 89.5 93.0 3.5 $3,401 $4,305 $904 80.0 75.5 89.5 93.6 4.1 $2,229 $2,770 $541 83.5 85.550 88.5 93.6 5.1 $4,052 $5,128 $1,076 76.5 84.0 91.0 93.6 2.6 $2,603 $3,232 $629 87.0 85.560 91.0 93.6 2.6 $4,699 $5,947 $1,248 80.5 83.5 91.0 94.1 3.1 $3,008 $3,826 $818 81.0 85.575 90.2 94.1 3.9 $6,258 $7,920 $1,662 80.0 85.0 91.0 95.0 4.0 $3,615 $4,575 $960 79.0 86.0

100 91.7 94.1 2.4 $7,907 $10,007 $2,100 78.5 84.0 92.4 95.0 2.6 $5,088 $6,405 $1,317 82.5 89.0125 92.4 94.5 2.1 $9,193 $11,635 $2,442 78.0 82.5 92.4 95.0 2.6 $6,191 $7,371 $1,180 84.5 88.5150 92.4 94.5 2.1 $10,371 $13,126 $2,755 77.5 82.5 93.0 95.8 2.8 $6,818 $8,606 $1,788 87.9 86.0200 94.1 95.0 0.9 13443.0 15989.0 2546.0 86.5 87.0 94.1 95.4 1.3 $9,524 $11,733 $2,209 87.8 86.5250 94.5 95.0 0.5 15370.0 18213.0 2843.0 86.5 84.0 94.3 95.4 1.1 12140.0 14386.0 2246.0 85.0 89.0300 94.5 95.0 0.5 17411.0 20633.0 3222.0 87.0 84.0 95.0 95.4 0.4 14380.0 17042.0 2662.0 88.5 89.5350 93.6 95.0 1.4 10493.0 12922.0 2429.0 81.0 80.5 95.0 95.8 0.8 16692.0 19780.0 3088.0 89.0 89.0400 93.6 95.0 1.4 11692.0 14251.0 2559.0 81.5 84.0 95.0 95.8 0.8 18960.0 22470.0 3510.0 89.5 87.5450 93.6 95.0 1.4 12622.0 15593.0 2971.0 81.0 84.5 94.5 96.2 1.7 11465.0 14119.0 2654.0 87.5 87.0500 94.5 96.2 1.7 12626.0 15549.0 2923.0 87.0 88.0

1800 RPM 3600 RPM

Horsepower Motor Efficiency Motor Cost Power Factor Motor Efficiency Motor Cost Power Factor(HP) Standard Efficient Increase Standard Efficient Increase Standard Efficient Standard Efficient Increase Standard Efficient Increase Standard Efficient

1 72.0 84.3 12.3 $191 $237 $46 76.0 72.9 74.0 77.4 3.4 256.0 273.0 $17 81.6 81.81.5 77.0 85.4 8.4 $209 $262 $53 78.5 74.2 80.0 84.0 4.0 $149 342.0 $193 86.0 82.4

2 80.0 85.2 5.2 $219 $274 $55 86.5 78.5 81.5 85.2 3.7 $173 302.0 $129 87.5 89.93 82.5 89.5 7.0 $197 $262 $65 79.0 80.0 82.5 88.5 6.0 $203 $267 $64 81.0 87.05 84.0 90.2 6.2 $229 $299 $70 84.0 83.0 84.0 89.5 5.5 $251 $330 $79 82.0 88.0

7.5 86.5 91.7 5.2 $329 $431 $102 83.0 82.5 86.5 91.7 5.2 $329 $431 $102 82.0 88.510 87.5 91.7 4.2 $409 $520 $111 85.0 81.0 87.5 91.7 4.2 $395 $509 $114 83.5 88.515 87.5 92.4 4.9 $541 $695 $154 83.0 81.5 87.5 91.7 4.2 $533 $698 $165 83.0 88.520 89.5 93.0 3.5 $683 $845 $162 84.5 82.0 87.5 92.4 4.9 $719 $841 $122 90.0 90.025 90.2 93.6 3.4 $820 $1,028 $208 85.0 83.5 88.5 92.4 3.9 $883 $1,049 $166 90.5 91.030 91.0 93.6 2.6 $996 $1,216 $220 83.0 83.0 89.5 92.4 2.9 $974 $1,241 $267 91.5 91.040 90.2 94.1 3.9 $1,280 $1,560 $280 80.0 87.5 88.5 93.6 5.1 $1,278 $1,608 $330 85.5 92.050 91.7 94.1 2.4 $1,658 $1,921 $263 85.5 86.5 89.5 93.0 3.5 $1,772 $2,070 $298 85.0 92.060 91.7 95.0 3.3 $2,489 $2,856 $367 82.5 85.5 89.5 94.1 4.6 $2,594 $2,818 $224 90.0 92.075 91.7 95.4 3.7 $3,182 $3,680 $498 83.5 84.5 91.0 94.5 3.5 $3,089 $3,749 $660 91.5 92.0

100 91.7 95.4 3.7 $3,837 $4,517 $680 87.0 85.0 90.2 94.1 3.9 $4,167 $4,743 $576 89.0 91.5125 92.4 95.4 3.0 $4,950 $6,354 $1,404 84.5 89.0 91.0 94.5 3.5 $5,809 $6,488 $679 92.5 93.5150 93.0 95.8 2.8 $6,021 $7,415 $1,394 86.5 88.0 91.7 94.5 2.8 $6,958 $8,103 $1,145 92.0 93.5200 94.1 95.8 1.7 $7,285 $8,913 $1,628 89.5 90.0 93.0 95.0 2.0 $8,695 $10,532 $1,837 93.9 94.0250 93.6 96.2 2.6 $8,157 $11,181 $3,024 88.5 83.0 93.0 95.4 2.4 $10,246 $13,283 $3,037 92.5 89.5300 94.1 95.8 1.7 10084.0 12257.0 2173.0 90.0 84.0 91.0 95.4 4.4 13351.0 15536.0 2185.0 92.0 93.0350 94.5 95.8 1.3 11574.0 14068.0 2494.0 90.5 90.5 91.7 95.4 3.7 15335.0 19973.0 4638.0 93.0 93.0400 94.5 95.8 1.3 13528.0 16113.0 2585.0 91.0 91.0 91.7 95.4 3.7 17948.0 20279.0 2331.0 93.0 93.5450 95.0 95.8 0.8 17016.0 19023.0 2007.0 91.0 91.0 93.0 95.4 2.4 18692.0 22150.0 3458.0 93.5 93.0500 94.5 95.8 1.3 10019.0 12339.0 2320.0 89.0 90.0 94.1 95.4 1.3 10947.0 13482.0 2535.0 90.0 93.0

*Sources: Unless otherwise noted, all data is from General Electric Price From Motor Master, Washington State Energy Office. Open Drip Proof (ODP) publications GEP-500H (11/90), and GEP-1087J (1/92). Efficiency From Motor Master, Washington State Energy Office. Averaged Data. Totaly Enclosed Fan Cooled (TEFC)

A.8. Power Factor Curve

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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.

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

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. 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

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.

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

B.2 LIGHTING INVENTORY & ENERGY CONSUMPTION

Area Type FC F# L/F B/F W/L IW Hr/Yr kW kWhASSEMBLY Main Room

High Pressure Sodium 64 44 1 1 250 310 6,120 13.6 83,232Std. 8 ft. HO Fluorescent 64 1 2 1 75 158 6,120 0.2 1,224Std. 4 ft. Fluorescent 64 3 2 1 40 86 6,120 0.3 1,836Eff. 8 ft. HO Fluorescent 64 10 2 1 95 237 6,120 2.4 14,688

Break RoomEff. 8 ft. Fluorescent 64 2 2 1 60 123 6,120 0.2 1,224

PAINT SHOP Paint Booth

Std. 4 ft. Fluorescent 7 44 2 1 40 86 6,120 3.8 23,256Std. 8 ft. HO Fluorescent 7 6 2 1 75 158 6,120 0.9 5,508Metal Halide 7 6 1 1 175 215 6,120 1.3 7,956

Sandblast RoomMetal Halide 7 6 1 1 175 215 6,120 1.3 7,956

PATTERN SHOP Main Floor

Std. 8ft. T-8 Fluorescent 50 31 2 1 50 118 2,040 3.7 7,548Std. 8 ft. HO Fluorescent 50 12 2 1 75 158 2,040 1.9 3,876Metal Halide 50 11 1 1 175 215 2,040 2.4 4,896Mercury Vapor 50 11 1 1 175 205 2,040 2.3 4,692

Main StorageEff. 8 ft. HO Fluorescent 25 48 2 1 95 237 2,040 11.4 23,256

Small StorageIncandescent 40 14 1 300 2,040 4.2 8,568

Upper StorageStd. 8 ft. HO Fluorescent 22 29 2 1 75 158 2,040 4.6 9,384

RESEARCH AND DEVELOPMENT Main Floor

Metal Halide 30 35 1 1 100 129 2,040 4.5 9,180Std. 4 ft. Fluorescent 30 2 2 1 40 86 2,040 0.2 408Std. 8 ft. HO Fluorescent 7 7 2 1 110 237 2,040 1.7 3,468

Control RoomStd. 4 ft. Fluorescent 30 8 2 1 40 86 2,040 0.7 1,428

OfficeStd. 4 ft. Fluorescent 30 3 2 1 40 86 2,040 0.3 612

B.2 LIGHTING INVENTORY & ENERGY CONSUMPTION

Area Type FC F# L/F B/F W/L IW Hr/Yr kW kWhSERVICE CENTER

Std. 4 ft. Fluorescent 50 9 2 1 40 86 4,080 0.8 3,264Std. 8 ft. HO Fluorescent 50 16 2 1 75 158 4,080 2.5 10,200Incandescent 50 3 1 0 60 4,080 0.2 816Metal Halide 50 11 1 1 175 215 4,080 2.4 9,792Mercury Vapor 50 11 1 1 175 205 4,080 2.3 9,384

OFFICE BUILDINGStd. 4 ft. Fluorescent 71 378 2 1 40 86 2,040 32.5 66,300Incandescent 9 57 1 100 2,040 5.7 11,628Std. 8 ft. HO Fluorescent 30 6 2 1 75 158 2,040 0.9 1,836Incandescent 15 28 1 0 75 2,040 2.1 4,284

OUTSIDE LIGHTINGMercury Vapor 15 29 1 1 250 290 2,040 8.4 17,136

Totals 119.7 358,836

BOILER EFFICIENCY TIPS

1. Test boiler efficiency regularly, at least once per month. Recommended percentages of oxygen (O2), carbon dioxide (CO2), and excess air in the flue gases are given by: Excess Fuel O2% CO2% Air % Natural gas 4.0 9.6 21.1 Oil (#2) 4.0 12.6 22.0 Oil (#6) 4.0 13.4 22.3 Propane 4.0 11.1 21.5 Coal 4.5 14.6 26.4 Wood 8.0 12.6 61.1

The air-fuel ratio should be adjusted to obtain the recommended flue gas concentrations. More excess air reduces boiler efficiency by heating more air than is needed. You may be able to increase boiler efficiency even more if you can reduce excess air below the recommended value. However, not all boilers can operate with less than the recommended excess air and still have complete combustion. Incomplete combustion is both inefficient and dangerous, and can be determined by testing flue gases for carbon monoxide (CO), smoke or other combustibles.

If your boiler has significant air leaks such as around doors, burners, and the firebox, you will not be able to achieve these conditions without losing combustion efficiency (producing carbon monoxide and other products of incomplete combustion). In this case you will need to seal air leaks before you will be able to achieve the highest efficiency.

Install a stack thermometer with a maximum indicating hand and record both instantaneous and maximum temperatures at least once a day. Increased temperatures caused by excess combustion air, air leaks, or fire-side or water-side fouling mean lower boiler efficiency. The maximum temperature indicator might record a problem that occurred when no one was around.

2. A high flue gas temperature may indicate the existence of deposits and fouling on the fire

and/or water side(s) of the boiler. The resulting loss in boiler efficiency can be estimated by a 1% efficiency loss for every 40°F increase in stack temperature.

We recommend that you record the stack gas temperature immediately after boiler servicing and that this value be used as the optimum temperature. Record stack gas temperature readings regularly and compare with the established optimum reading at the same firing rate. A major variation in the stack gas temperature indicates a drop in efficiency and the need for either air-fuel ratio adjustment or boiler tube cleaning. In the absence of any reference temperature, it is normally expected that the stack temperature will be about 50°F to 100°F above the saturated steam temperature at a high firing rate in a saturated steam boiler.

3. Add a water meter to the make-up water line. Record meter readings at least once a week and monitor water use. Increased water use could be caused by leaking steam traps or other steam or condensate leaks.

4. Keep a boiler log. Record how your boiler is operating on a regular basis. Include stack and

maximum temperatures, pressure, boiler room temperature, condensate and feedwater temperatures, water and fuel meter readings, and any combustion efficiency or water quality tests made. Also record any maintenance, changes, adjustments, and relevant comments. Use your log to look for trends that could mean trouble.

5. After an overhaul of the boiler, run the boiler and re-examine the tubes for cleanliness after

thirty days of operation. The accumulated amount of dirt will establish the criterion as to the necessary frequency of boiler tube cleaning.

6. Check the burner head and orifice once a week and clean if necessary. 7. Check all controls frequently and keep them clean and dry. 8. For water tube boilers burning coal or heavy oil, blow the soot out once a day. The National

Bureau of Standards indicates that 8 days of operation can result in an efficiency reduction of 8%, caused solely by sooting of the boiler tubes.

9. The frequency and amount of blowdown depends upon the amount and condition of the

feedwater. Check the operation of the blowdown system and make sure that excessive blowdown does not occur.

COMBUSTION EFFICIENCY DEFINITIONS The combustion efficiency was calculated using the ASME (American Society of Mechanical Engineers) Heat Loss Method. The heat loss method subtracts calculated energy losses from 100% to obtain a percent efficiency. The following energy losses are calculated to approximate combustion performance: • Dry Gas Losses • Moisture Formation Losses • Combustible Losses STACK GAS ANALYSIS The following nomenclature is used in the equations for calculating combustion efficiency: Flue Gas %CO2 = Percent carbon dioxide measured by volume: % %O2 = Percent oxygen measured by volume: % %N2 = Percent nitrogen by volume: % = 100% - %CO2 - %O2 CO = Measured carbon monoxide in flue gas: ppm %CO = Measured carbon monoxide in flue gas: ppm x 10-4 hg = Enthalpy of water vapor at stack temperature: Btu/lb hf = Enthalpy of liquid water at combustion intake air temperature: Btu/lb Ts = Stack temperature: °F Tc = Combustion intake air temperature: °F Fuel (see FUEL PROPERTIES table below) %C = Percent carbon by weight in fuel: % %S = Percent sulfur by weight in fuel: % %H = Percent hydrogen by weight in fuel: % %M = Percent moisture by weight in fuel: % HHV = Higher heating value of fuel: Btu/lb CFF = Combustion fuel factor

FUEL PROPERTIES Fuel Type %C %S %H %M HHV CFF Natural Gas 77.0 0.00 23.0 0.0 23,500 0.00591 #2 Oil 87.0 0.48 11.9 0.0 19,410 0.00623 #6 Oil 86.6 1.53 10.8 0.0 18,990 0.00623 Propane 81.8 0.00 18.2 0.0 21,670 0.00600

COMBUSTION LOSSES Dry Gas Losses (HLDG) The percent of heat loss due to dry flue gases in the stack can be calculated by the following equation: HLDG = Pf x 0.24 x (Ts - Tc) x 100 / HHV where Pf = [44(%CO2) + 32(%O2) + 28(%CO + %N2)] / 12(%CO2 + %CO) x [(%C / 100) + (%S / 267)] The coefficients in the above equation (44, 32, 28) represent the atomic weights of the molecules they precede. The coefficient in the denominator (12) represents the atomic weight of carbon in CO2 and CO. Moisture Formation Losses (HLM) The percent of heat loss due to moisture formed during combustion from hydrogen (H) in the fuel is calculated by: HLM = 9 x %H x (hg - hf) / HHV where the coefficient (9) is the ratio of the atomic weights of water (H2O) to hydrogen (H2). Combustible Losses (HLC) Heat loss due to combustibles occurs when the combustion is incomplete and carbon monoxide ond other combustibles are produced. The percent heat loss due to carbon monoxide is calculated as follows: HLC = CFF x CO / (21 - %O2) EFFICIENCY SUMMARY Combustion Efficiency The overall combustion efficiency (_B) is calculated by: _B = 100 - HLDG - HLM - HLC - HLFM