Petaluma Final Draft Report 090504cityofpetaluma.net/pubworks/pdf/petaluma-final... · City of...

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City of Petaluma Greenhouse Gas Emissions

Reduction Action Plan Analysis

Final Report July 8, 2009

Climate Protection Campaign

Prepared by Sam Pierce PE

Principal, Tellus Applied Sciences, Inc. Under the direction of the Climate Protection Campaign,

Acknowledgements

There were many individual contributors to the success of this project. The City of Petaluma Staff provided the key information required to develop the measures in these Action Plans. The Public Works Department directly supported the data collect effort. The Petaluma Green Team, and Diane Ramirez in particular provided consistent support and clear guidance throughout the project. The support of City Staff Senior Management has ensured the active support of this project by the entire Petaluma team. Great appreciation is offered to Erika Walther of ABAG Energy Watch, and David Williard of Sustainergy Systems for their energy efficiency contributions carried forward in this work, and Ann Hancock, Executive Director of the Climate Protection Campaign whose inspiration is the driving force propelling this work forward. Finally, ultimate appreciation goes to the Petaluma City Council for their vision for a stronger, more secure future for our community, expressed in many ways, including their support for this important work. Disclaimer: The Climate Protection Campaign and its subcontractors do not imply any guarantees. The information contained in this report is intended to support the City in its efforts to understand the greenhouse gas emissions trend and opportunities for City operations and employee commutes. All results are approximations using standard engineering methodologies, based on best available information and historical energy usage.

Definition of Terms

CEC (California Energy Commission) The CEC is California’s primary energy policy agency. They are responsible for forecasting future energy needs, promoting energy efficiency through appliance and building standards, and supporting renewable energy technologies.

CNG (Compressed Natural Gas) Compressed Natural Gas is a substitute to gasoline, diesel, or propane fuel. It is made by compressed natural gas, mainly methane (CH4).

CO2e (Equivalent Carbon Dioxide) Equivalent Carbon Dioxide is the concentration of carbon dioxide that would cause the same level of radiative forcing as a given type and concentration of greenhouse gas such as methane, perfluorocarbons, and nitrous oxide.

GHG (Greenhouse Gas) Greenhouse gases are the gases in the atmosphere, which reduce the loss of heat into space and therefore increase global temperatures. Greenhouse gases include water vapour, carbon dioxide, methane, nitrous oxide, ozone, and chlorofluorocarbons.

ICLEI (International Council for Local Environmental Initiatives) ICLEI was formed in 1990 and is an international association of local governments and national and regional local government organizations that have made a commitment to sustainable development.

IRR (Internal Rate of Return) Internal Rate of Return is a budgeting metric used to decide whether to make an investment or not. It is an indicator of the efficiency of an investment. A larger IRR is a stronger investment.

kWh (kilowatt-hour) A kilowatt-hour is used to express amounts of energy delivered by electric utilities. One watt hour is the amount of energy expended by a one-watt load drawing power for one hour.

Metric Ton A metric ton equals 2,205 lbs. A short ton equals 2000 lbs.

Net Capital Cost The net capital cost is the capital cost of a project minus incentives and rebates.

NPV (Net Present Value) Net present value is a standard method for the financial appraisal of long-term projects. It measures the excess or shortfalls of cash flows, in present value terms, once financing charges are met. NPV indicated how much value an investment or project adds to the value of the business or firm.

O&M (Operations and Maintenance) Operations and maintenance refers to the maintenance and fuel cost incurred by a unit of equipment. The O&M costs in this analysis are the additional operation costs associated with the efficiency measure.

PV (Photovoltaic) Photovoltaic cells convert light energy into electricity. Also called solar power.

RPC (Renewable Portfolio Standard) Established in 2002 under Senate Bill 1078 and accelerated in 2006 under Senate Bill 107, California's Renewables Portfolio Standard (RPS) is one of the most ambitious renewable energy standards in the country. The RPS program requires electric corporations to increase procurement from eligible renewable energy resources by at least 1% of their retail sales annually, until they reach 20% by 2010.1

1 California Public Utilities Commission, http://www.cpuc.ca.gov/PUC/energy/Renewables/

Table of Contents

1.0 Executive Summary.......................................................................................................... 6

Background................................................................................................................................. 7 Methodology............................................................................................................................... 9 Results ...................................................................................................................................... 11 Summary................................................................................................................................... 22

2.0 Introduction..................................................................................................................... 23 3.0 Methodology .................................................................................................................... 24

Context...................................................................................................................................... 24 Measure Identification .............................................................................................................. 26 Measure Assumptions: General Variables................................................................................ 26 Measure Specific Variables ...................................................................................................... 28 Financial Analysis Results........................................................................................................ 28 Community Benefit................................................................................................................... 29 Measure Evaluation .................................................................................................................. 30 California Low Carbon Fuel Standard...................................................................................... 31 PG&E Power Content and City Future Action Assumptions ................................................... 31 Future Actions........................................................................................................................... 32

4.0 Results .............................................................................................................................. 32 GHG Impacts and Plan Financial Results................................................................................. 32 Action Plan Evaluations............................................................................................................ 34 Energy Rate Escalation and Associated Budget Vulnerability................................................. 35 Incremental Capital Cost of Efficiency Measures .................................................................... 39 Plan Details ............................................................................................................................... 40 Action Plan Evaluations............................................................................................................ 50

5.0 Measure Details............................................................................................................... 52 Measure Selection..................................................................................................................... 55 Measures Results ...................................................................................................................... 58

6.0 Summary and Conclusions........................................................................................... 126 7.0 Appendices..................................................................................................................... 127

7.1 Basis for 2000 GHG Inventory ................................................................................... 128 7.2 General Inputs and Assumptions ................................................................................ 130 7.3 Action Plan Evaluations.............................................................................................. 131 7.4 Kenilworth Swim Center Recommendations.............................................................. 135 7.5 Building and Swim Energy Efficiency Measures....................................................... 136 7.6 ABAG Energy Watch Lighting Recommendations.................................................... 137 7.7 Petaluma Potable Water Pumping Data...................................................................... 141 7.8 Transit Bus Replacement Costs .................................................................................. 142 7.9 Vehicle List with Measures ........................................................................................ 143 7.10 Solar Electric Production Assumptions ...................................................................... 150 7.11 Vehicle Fuel Cost Trends............................................................................................ 151

7.12 Carbon Credits ............................................................................................................ 153 7.13 Electric Vehicles ......................................................................................................... 157 7.14 Commute Programs .................................................................................................... 161 7.15 Grease to Gas Augmentation of Digester Gas ............................................................ 166

List of Tables

Table 1: Increases in Energy Consumption from 2000 to 2008 ..................................................... 7 Table 2: GHG Action Plan Financial Results ............................................................................... 12 Table 3: Measures 1 - 25............................................................................................................... 14 Table 4: Measures 26 - 50............................................................................................................. 15 Table 5: Measures 51 - 66............................................................................................................. 16 Table 6: Measures 67 – 77 (Not quantified) ................................................................................. 16 Table 7: Increases in Energy Consumption from 2000 to 2008 ................................................... 24 Table 8: General Inputs................................................................................................................. 27 Table 9: Action Plan Financial Results......................................................................................... 33 Table 10: Evaluation Criteria Weighting...................................................................................... 50 Table 11: Plan Evaluation Results ................................................................................................ 51 Table 12: Results by Measure (1-26)............................................................................................ 52 Table 13: Results by Measure (27-52).......................................................................................... 53 Table 14: Results by Measure (53 – 77) ....................................................................................... 54 Table 15: Measures 1 – 25 ............................................................................................................ 55 Table 16: Measures 26 - 50........................................................................................................... 56 Table 17: Measures 51 – 66 .......................................................................................................... 57 Table 18: Measures 67 – 77 (Not quantified) ............................................................................... 57 Table 19: 2000 Greenhouse Gas Inventory (Part 1) ................................................................... 128 Table 20: 2000 Greenhouse Gas Inventory (Part 2) ................................................................... 129 Table 21: Evaluation Criteria Weighting.................................................................................... 131 Table 22: Measure List and Evaluations A................................................................................. 132 Table 23: Measure List and Evaluations B ................................................................................. 133 Table 24: Plan Evaluation Results .............................................................................................. 134 Table 25: Vehicle List and Measures Units 2 - 76...................................................................... 143 Table 26: Vehicle List and Measures Units 77 - 201.................................................................. 144 Table 27: Vehicle List and Measures Units 202 - 301................................................................ 145 Table 28: Vehicle List and Measures Units 301 - 526................................................................ 146 Table 29: Vehicle List and Measures Units 527 - 614................................................................ 147 Table 30: Vehicle List and Measures Units 615 - 990................................................................ 148 Table 31: Vehicle List and Measures Units 991 – A3 ................................................................ 149

List of Figures Figure 1: City of Petaluma GHG Inventory as a Percentage of the 2000 Total ............................. 8 Figure 2: Energy Rate Escalation Scenarios................................................................................... 9 Figure 3: Annual Cost of Energy .................................................................................................. 13 Figure 4: City of Petaluma GHG Inventory as a Percentage of the 2000 Total ........................... 23 Figure 5: Power Content Values for Converting kWh to lbs/CO2e ............................................. 31 Figure 6: Energy Rate Escalation Scenarios................................................................................. 36 Figure 7: Annual Cost Trend of Vehicle Fuel Only ..................................................................... 37 Figure 8: Annual Cost of Energy .................................................................................................. 38

City of Petaluma Greenhouse Gas Emission Reduction Action Plan 7.8.09

Climate Protection Campaign 6 Tellus Applied Sciences, Inc.

1.0 Executive Summary Petaluma is a full service community in southern Sonoma County with a population of 54,660 in 2006. Formerly considered the “egg capitol of the world”, the surrounding pastoral landscapes and the tranquil cityscape of Petaluma have provided locations for numerous movie productions. In 1971 Petaluma gained national attention by enacting the “Petaluma Plan” to ensure orderly growth and to protect the city’s character. The community has extended its tradition of stewardship by embracing the ICLEI program to reduce the greenhouse gas (GHG) emissions from city controlled sources.2

The ICLEI program has five steps, referred to as “Milestones.” Milestone 1, creating the GHG inventory, and Milestone 2, setting a reduction target have been completed. Milestone 3 requires the creation of a plan to meet this target. This report and associated analysis provides the information necessary for addressing Milestone 2 and the roadmap to satisfy Milestone 3. This analysis provides five measure-specific plans to reduce emissions by more than 20%. Furthermore, the framework associated with this material will support the City in meeting the requirements of Milestone 4 (implementation) and Milestone 5 (monitoring and adjustment). The framework facilitates the integration of new and revised information, taking advantage of new opportunities and allowing adjustments to under performing initiatives.

The analysis, and resulting GHG emissions reduction plans, incorporates many opportunities in the various contributing sectors (Building Efficiency, Fleet, Commute, Water/Sewer, Streetlights, and Photovoltaic Systems), as identified by the City Staff utilizing the best available information at the time of research. The results provide an emissions impact estimate for five plans with the corresponding financial analysis.

The results for each plan include the GHG emissions reduction expressed in metric tons CO2e (equivalent CO2 emissions) 3 and as a percentage of the total City GHG emissions. These results are presented along with a number of other important metrics, including the Internal Rate of Return (IRR) and Net Present Value (NPV) of each plan. These are critical in the financial evaluation of the “investment”. Other information includes the budget resources not sent to the utility company and the fuel companies, and the value of the resources redirected to local investments. Plan C, for example, results in over $10 million in local investment over the 25 year life of the plan.

The intent of this work is to allow the independent plans to be considered on their merits in numerous areas. This provides the capability to compare the comprehensive costs and benefits of competing paths, and thereby allow Policy Makers the ability to select the most appropriate path to reducing global warming pollution emissions in the City of Petaluma. Five Action Plans are presented resulting in reductions from 22% to over 38% below 2000 levels by 2015. Each plan has advantages and challenges, which are described in the following sections of this report.

2 http://en.wikipedia.org/wiki/Petaluma,_California 3 CO2e: Equivalent CO2 in lbs or tons. The additional greenhouse gases such as methane are converted into the equivalent amount of CO2 for analysis and clearer presentation.



Background

North Bay public jurisdictions (cities and counties) have adopted greenhouse gas reduction targets and have committed to developing action plans to meet these targets. These initiatives coincide with aggressive actions by the State to address climate change.4 The rules and potential mandates from the State are under development. While the specific requirements are not yet determined, it is clear that all sectors including local governments will be encouraged or even required to join

the effort to reduce greenhouse gas emissions. North Bay governments are already demonstrating leadership by embracing the ICLEI program, setting reduction targets and developing GHG emissions action plans. The first step, creating the inventory of emissions produced by the internal operations has been completed for the City of Petaluma controlled equipment and operations. The total emissions for 2000 were roughly 5,400 metric tons of CO2e. In addition to this baseline, there were numerous changes in GHG emissions identified from the utility billing since the baseline year of 2000. These are consolidated and modeled in the analysis as the “End Use” entries in the table below.5 These add another 640 tons to the reduction goal. This information was also used to generate the emissions trend associated with projected city growth from 2009 to 2020. These projected additional GHG emissions are included in the calculations of each Plan. This adds 106 tons per year which is dependant on the projected population increase each year within the City.6

End Use kWh Therms Fuel (gals)2000-2008 Corporation Yard 37,762 0 0

2000-2008 Muni Pool 0 30,020 0

2000-2008 840 Hopper St Off 0 10,751 0

2000-2008 Lakeville Ag Pumps and Sm Pmps 0 126 0

2000-2008 Streetsignals -397,685 0 0

2000 to 2008 Fleet 0 0 41,990

2000-2008 Commute 0 0 10,266

Totals -359,923 40,897 52,256CO2e (metric tons) -80 229 491

Increases in Energy Consumption from 2000 to 2008

Table 1: Increases in Energy Consumption from 2000 to 2008

4 California's major initiatives for reducing climate change or greenhouse gas (GHG) emissions are outlined in the 2006 legislation Assembly Bill 32, 2005 Executive Order and a 2004 ARB regulation to reduce passenger car GHG emissions. These efforts aim at reducing GHG emissions to 1990 levels by 2020 - a reduction of about 25 percent, and then an 80 percent reduction below 1990 levels by 2050. This initiative also includes the California Renewable Portfolio Standard for the production of electricity, and the California Low Carbon Fuel Standard under development. 5 These End Uses represent 100% of the energy increases for all accounts as identified in the PG&E billing data. They are labeled as the accounts contributing most to the change and the year associated with the change. 6 Petaluma General Plan 2025 Air Quality – Greenhouse Gas Emissions Section Revised Draft Environmental Impact Report, Winzler and Kelly, November 2007.



The City of Petaluma emissions by sector are presented as a percentage of the total emissions in Figure 1 below.

Baseline GHG Emissions by Sector

Water Wastewater33%

Commute11%

Fleet26%

Streetlights11%

Buildings19%

Solid Waste0%

Figure 1: City of Petaluma GHG Inventory as a Percentage of the 2000 Total

Many of the measures available to reduce GHG emissions also will reduce the City fuel, electricity and natural gas costs. These costs are a significant element of the municipal budget, and the potential cost volatility represents a threat beyond the control of City Staff. Figure 2 below provides the trends for the annual energy costs based on four rate escalation scenarios. The 3.5% escalation rate reflects the current trend in utility energy cost. The “current” cost trend for fleet fuel is 7.8% per year based on the costs from 1987-2006.7 These values are used in the cash flow projections for each GHG reduction plan. The fuel, electricity and natural gas related measures contained in this analysis will reduce the vulnerability to rising energy costs.

7 http://tonto.eia.doe.gov/dnav/pet/hist/mg_tt_usA.htm; See the appendices for the yearly published value.



Energy Cost Escalation Scenarios

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Figure 2: Energy Rate Escalation Scenarios

Methodology The Petaluma GHG emissions inventory for 2000 was documented in 2003 and provides a reference for the baseline inventory developed for this analysis.8 The specific actions and events affecting this baseline from 2000 to 2008, either positive or negative, are factored into the inventory and the resulting trend. The 2000 baseline details used in this analysis are available in the appendices. The options for future action by the City are comprised of measures applicable to building and equipment energy efficiency, fuel efficiency, alternative fuel options, and distributed energy generation. These options have been identified and quantified within this analysis. They are evaluated and presented as individual projects (measures), and as groups of measures (plans). Each is assigned a status (completed or future) and an implementation date to enable the calculation of cash flows over the life of the plans and the creation of energy cost trend graphs. The measures are grouped to create comprehensive GHG emissions reduction plans. Each of the plans is analyzed to provide profiles enabling the evaluation of the plans individually and in comparison to the other plan options. Measures of specific data such as capital cost, year of 8 GHG Inventory Report Petaluma, Simon Wooley, September 2003.



implementation, financing, energy and cost savings were processed to provide the following information for the five action plans:

• Emissions reduction in tons CO2e avoided as a percentage of baseline • CO2e reduction by sector • Annual Cash Flow including debt service, replacement cost and incremental O&M costs • Outstanding principal and debt service by year • Simple Payback (SPB) for each plan • Internal Rate of Return (IRR) for each plan • Net Present Value (NPV) for each plan • Avoided utility company payments (NPV over life of plan) • Avoided fuel purchases (NPV over life of plan) • Value invested locally in emission reduction projects

A measure evaluation matrix was employed to quantify subjective considerations to allow their inclusion in the planning process. The evaluation scoring contributes to the understanding of the opportunities but is not intended to provide a final ranking of the measures. The decision to include measures in each plan is dependent on its role in achieving the objective of that plan, and is therefore independent of any fixed criteria or ranking. The results of the evaluation are provided in the appendices.



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Results Five plans have been created for consideration by the City of Petaluma. These plans consist of numerous measures to reduce GHG emissions, reduce energy costs, address equipment issues, and reduce the uncertainty of the City’s future annual energy costs. Summary financial information is provided in Table 2 below. The results contained in this table should be considered with the Action Plan

Evaluations provided in the Appendices to understand the relative strengths of each combination of measures populating the Action Plans. Detailed information for each measure is provided within the Measure Details section of this report. Plan Results and Comparison Tables Table 2 provides important financial information for each plan including the net annual cash flow. The “% Reduction” is the amount of CO2e reduced as a percentage of the total City emissions. Plan A provides a reduction of 23% below the year 2000 (baseline) emissions. Plan E provides a strategy to reduce the City’s emissions to 38% below 2000 emissions. These percentage reductions include the projected increased emissions from city growth from 2009 to 2020 based on emissions data from 2000 to 2006 and projected population increases. The financial analysis is provided with each plan. The critical metrics of Internal Rate of Return (IRR) and Net Present Value (NPV) provide important information to evaluate the worthiness of the investment from a cash flow perspective. It is important to note the large negative net cash flow in one of the later years of Plan A represents the replacement of the photovoltaic (PV) system inverters after 10 years.9

9 The assumption is that the cost of inverters will increase at the generally assumed inflation rate of 3.5%. However likely advances in technology, and improved economies of scale for the industry suggest this is overly conservative.



Analysis Plan A Plan B Plan C Plan D Plan E

% Reduction below 2000 by 2015 23.2% 22.3% 22.3% 28.0% 38.7%

SPB NA 5.3 0.6 1.9 6.5

IRR NA 51.4% 190.0% 82.1% 33.3%

NPV ($17,463,599) $11,193,684 $12,587,862 $13,419,544 $11,874,177

Annual Net Cash Flow Plan A Plan B Plan C Plan D Plan E

2009 ($20,000) ($44,719) ($31,675) ($31,675) ($31,675)

2010 ($1,596,983) ($49,327) ($27,162) ($86,954) ($4,477)

2011 ($1,613,670) ($34,983) ($105,547) ($108,989) ($213,113)

2012 ($1,615,524) ($51,825) ($58,803) ($164,804) ($250,293)

2013 ($1,622,008) ($51,357) ($28,170) ($81,481) ($377,731)

2014 ($2,431,370) ($46,475) ($8,601) ($58,910) ($355,745)

2015 ($3,800,958) $54,338 $264,119 $236,138 ($248,700)

2016 ($3,746,521) $303,723 $623,194 $552,701 $68,582

2017 ($3,720,353) $369,909 $714,352 $650,181 $229,188

2018 ($3,693,262) $803,707 $902,201 $1,004,090 $788,320

2019 ($3,929,665) $807,525 $906,596 $1,012,051 $952,315

2020 $851,328 $922,253 $984,066 $1,002,750 $1,024,398

2021 $881,387 $1,048,274 $1,068,013 $1,180,979 $1,203,498

2022 $912,505 $1,085,081 $1,105,455 $1,166,646 $1,190,071

2023 $363,554 $1,123,179 $1,144,210 $1,265,223 $1,289,588

2024 ($1,346,594) $1,162,615 $1,184,324 $1,309,571 $1,334,914

2025 $1,012,600 $1,203,435 $1,225,843 $1,355,474 $1,381,832

GHG Action Plan Summary

Table 2: GHG Action Plan Financial Results

Carbon Offsets Carbon offsets are available as an alternative to specific reduction actions within the City facilities and equipment. The PG&E Climate Smart program launched is available, but has not been incorporated into these plans. This and numerous other programs are available offering a less cost intensive approach to GHG reduction than local project implementation. However, the offset typically must be renewed annually, doesn’t offset energy use (and associated cost by the City), and doesn’t reduce the future energy cost vulnerability (see Figure 3 below). More information on carbon offsets is provided in the appendices, including a sample of programs available at the time of the research.



Energy Rate Escalation and Associated Budget Vulnerability There is considerable discussion about the availability of fossil fuels in the near and middle term future (5 to 20 years). The “Peak Oil” movement suggests that we are at or near the point where our increased global demand for oil cannot be supplied from new petroleum discoveries, while production from existing oil fields is waning. Similar arguments are made for natural gas supply vs. demand. If demand outstrips supply, simple economics indicates that the cost to consumers will escalate rapidly, until the global demand is sufficiently dampened and realigns with available supply. The concern is significant enough to have prompted a US government sponsored study to determine the impacts of demand exceeding supply in the near future.10 This issue has important implications for local North Bay jurisdictions. Forty percent of PG&E power is generated by natural gas11. A spike in the cost of this energy source will result in significant increases in the cost of electrical power, as well as increased volatility in the cost of natural gas used directly by the City. Energy efficiency projects and distributed generation energy systems can play a significant role in moderating this vulnerability. Figure 3 below provides potential impact of energy efficiency strategies on the associated vulnerability. For example, under the 3.5% utility cost escalation rate scenario, the City would reduce its fleet fuel and utility payments by more than $1M per year in 2015 by implementing one of the emission reduction plans detailed below.

Future Energy Cost Mitigation

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Figure 3: Annual Cost of Energy

10 Hirsch, Robert. et al. (February 2005) “Peaking of World Oil Production: Impacts, Mitigation, & Risk Management.” SAIC. 11 PG&E Power Content: Eligible Renewables: 15%, Coal: 2%, Large Hydro: 16%, Natural Gas 47%, Nuclear: 20%, Other; 1%, California Energy Commission, www.energy.ca.gov/consumer, February 2009.



Action Plan Details The measures used in this analysis are provided in the tables below. The first five columns indicate which measure is included in each Action Plan. More information on the measures is available in the Measure Details section of the report. The material that follows provides the results for each Action Plan. It is important to note that some measures are mutually exclusive. Measures 40 and 41, for example apply to the same set of equipment, the City fleet. Measure 41 is more aggressive affecting more vehicles. Therefore a plan would select only one of these measures.

A B C D E

n n y n n 1 K. Swim Center Solar Thermal Repair MCAP (Exclusive to #2,7,8,9) 2010 yes

n n n n y 2 K.Swim Center Solar Thermal Expansion MCAP (Exclusive to #1,7,8,9) 2011 yes

n n y y y 3 K.Swim Center VFD MCAP (Exclusive to 9) 2010 yes

n n y n y 4 K.Swim Center Pool Covers Repl. MCAP (Exclusive to 9) 2009 yes

n n y y y 5 K. Swim Cntr Opt. Operation Pool Pumps and Filtration EEM-1 (Exclusive to #6,9) 2009 no

n n n n n 6 K. Swim Cnter Premium Efficiency Motors EEM-2 (Exclusive to #5, 9) 2009 yes

n n n y n 7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 (Exclusive to #4 and 8, 9) 2012 yes

n n n n n 8 K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 (Exclusive to #1,2,7,9) 2009 yes

n y n n n 9 K. Swim Center Closure 50% Days (exclusive to other K.Swim pool measures) 2009 no

n y y y y 10 Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 2009 no

n y n y y 11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 (Matched to #10) 2010 yes

n n n n y 12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2011 yes

n n n y y 13 Cavn. Cntr Install Cool Roof EEM-8 2011 yes

y y y y y 14 City Hall, Com Cntr, Police Dept. SBEA Lighting Measures 2006 yes

n y y y y 15 Police Facility Energy Management System MCAP 2010 yes

n y n n y 16 Police Facility HVAC Upgrade to 16 SEER and 80% AFUE ABAGEW / HDR EEM-2 2012 yes

n y n n y 17 Luchessi Cmty Cntr Replace Gas Pcks w/ High Eff UnitsEEM-9 (Exclusive to #18) 2011 yes

n n n y n 18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 (Exclusive to #17) 2011 yes

n y y y y 19 Animal Shelter Lighting Retrofit ABAG EW 2009 yes

n y y y y 20 Corporation Yard Lighting Retrofit ABAG EW 2009 yes

n y y y y 21 Cavn. Cntr Lighting Retrofit ABAG EW 2009 yes

n y y y y 22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2009 yes

n y y y y 23 Senior Center Lighting Retrofit ABAG EW 2009 yes

n y y y y 24 Airport Lighting Retrofit ABAG EW 2009 yes

n y y y y 25 Vending Machine Controls 2009 yes

Financed (yes/no)

Action PlanMeasure Number Measure Name Implementation

Date

Table 3: Measures 1 - 25



A B C D E

n y y y y 26 Retrofit Frates Pumps (Zone 4) 2010 yes

n n n n y 27 Petaluma Aqueduct supplying Zone 4 2012 yes

n y n y y 28 SolarBeeTM (unless new facility removes need) 2009 yes

n n y y y 29 Grease to Gas Methane Program 2011 yes

n y y n y 30 Streetlighting A: 50% Conversion HPS to LED (or equiv.) 2012 yes

n n n n y 31 Streetlighting B: 50% Conversion HPS to LED (or equiv.) 2013 yes

n y n y n 32 Streetlighting C: Turn off 50% of Residential lighting (non intersection) 2010 no

n n n y n 33 Streetlighting D: Turn off 50% of Residential lighting (non intersection) 2012 no

n y y y y 34 Commute 1 2010 no

n n n y y 35 Commute 2 2011 no

y y y y y 36 4 day work week (Commute) 2009 no

y y y y y 37 4 day work week (Building) 2009 no

n n y y n 38 Bus Fleet A 2014 yes

n y n n y 39 Bus Fleet B 2014 yes

n n y n n 40 Fleet Replacement Strategy A (includes Nissan Elec) 2010 yes

n y n y y 41 Fleet Replacement Strategy B (includes Nissan Elec) 2012 yes

y n n n n 42 Nissan Electric Vehicles (Exclusive to other Fleet Measures) 2010 yes

n n n n n 43 Biodiesel 20% 2009 yes



n n n n n 46 Biodiesel 20% linked to Fleet A 2009 yes

n n n n n 47 Biodiesel 20% linked to Fleet B 2009 yes

n n y n n 48 Biodiesel 50% linked to Fleet A 2010 no

n y n y n 49 Biodiesel 50% linked to Fleet B 2010 no

n n n n n 50 Biodiesel 99% linked to Fleet A 2010 no

Financed (yes/no)


Date




A B C D E

n n n n y 51 Biodiesel 99% linked to Fleet B 2010 no

n n y n n 52 Fleet Management Software Linked to Fleet Replacement A 2010 yes

n y n y y 53 Fleet Management Software Linked to Fleet Replacement B 2010 yes

y n y y y 54 PV 1.0 MWac (PPA) 2011 no

y y n n y 55 PV 2.0 MWac (PPA) 2013 no

y n n n n 56 PV 1.0 MWac (PPA) 2012 no

y n n n n 57 PV .5 MWac (PPA) 2012 no

y n n n n 58 PV .5 MWac 2013 yes

y n n n n 59 PV 1.0 MWac 2009 yes


n n y y y 61 Community Center 41 kWac PV MCAP 2010 yes

n y n y y 62 K.Swim Center 80 kWac PV System MCAP 2010 yes

n n n y y 63 City Hall PV System 50kWac 2012 yes

n y y y y 64 Public Works PV System 25.3 kWac 2009 yes

n y y y y 65 Efficiency Coordinator (.5FTE) 2010 no

n n n y y 66 Efficiency Coordinator (.5FTE) 2012 no

Financed (yes/no)


Date


A B C D E

n n n n n 67 Swim Center Pay-per-use Showers MCAP (not quantified) NA NA

n n n n n 68 City Hall HVAC Upgrade MCAP (not quantified) NA NA

n n n n n 69 City Hall Council Chambers HVAC Upgrade MCAP (not quantified) NA NA

n n n n n 70 City Hall HVAC Upgrades West Wing Chiller, East Wing Package units MCAP (not Quantified) NA NA

n n n n n 71 City Hall HVAC Motion/ Occupancy Sensors for Lighting MCAP (not Quantified) NA NA

n n n n n 72 City Hall Daylighting MCAP (not quantified) NA NA

n n n n n 73 Community Center Energy Management System ABAG EW/HDR (not quantified) NA NA

n n n n n 74 Community Center Lighting Design and Controls MCAP (not quantified) NA NA

n n n n n 75 Cavanaugh Complex Variable Frequency Drives MCAP (not quantified) NA NA

n n n n n 76 WasteWater Treatment Plant NA NA

n n n n n 77 Reclaimed Water Initiatives NA NA

Financed (yes/no)


Date

Table 6: Measures 67 – 77 (Not quantified)



GHG Emissions Trend: Measures and External Factors

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Annual Net Cash Flow Plan A

2008 $0

2009 ($20,000)

2010 ($1,596,983)

2011 ($1,613,670)

2012 ($1,615,524)

2013 ($1,622,008)

2014 ($2,431,370)

2015 ($3,800,958)

2016 ($3,746,521)

2017 ($3,720,353)

2018 ($3,693,262)

2019 ($3,929,665)

2020 $851,328

2021 $881,387

2022 $912,505

2023 $363,554

2024 ($1,346,594)

2025 $1,012,600

Plan A: 1,263 Tons CO2e Avoided 23.2% % Reduction

$$$ Avoided Utility Company Payments $8,202,668 Jobs Created 1,095

$$$ Avoided Fuel Purchases $111,593 IRR NA

$$$ Invested Locally in GHG Projects $53,093,053 NPV ($17,463,599)

Financial MetricsCommunity Benefit (over 25 year life of plan)

Action Plan A: This plan has 10 specific actions and reduces the net GHG by 23% below 2000 levels. This plan relies primarily on the generation of electricity from photovoltaic systems. A total of 6.6 MWac of PV projects are included, roughly half utilize the power purchase agreement approach to financing. The PPA approach requires no capital or O&M expenditures. The financial metrics of this approach are very challenging where the NPV is negative $17M. The resulting annual cash flow is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The negative value in year 2024 is due to PV inverter replacement. The GHG Emissions graph below depicts the growth of emissions from 2000 to present and the reduction anticipated with this plan into the future. It includes the impact of the CA Renewable Portfolio Standard (RPS) and the CA Low Carbon Fuel Standard.12 These Standards are discussed in more detail on page 31 within the Methodology Section.

12 The reductions are obtained by reading the bottom curve on the graph. The Renewable Portfolio Standard (RPS) impacts are assumed to be 50% of the stated statewide targets.

Emission Reductions Including Utility Power Content Trend and Assumed Future Actions



Annual Net Cash Flow Plan B

2008 $0

2009 ($44,719)

2010 ($49,327)

2011 ($34,983)

2012 ($51,825)

2013 ($51,357)

2014 ($46,475)

2015 $54,338

2016 $303,723

2017 $369,909

2018 $803,707

2019 $807,525

2020 $922,253

2021 $1,048,274

2022 $1,085,081

2023 $1,123,179

2024 $1,162,615

2025 $1,203,435


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Measures andTrends

Plan B: 1,213 Tons CO2e Avoided 22.3% % Reduction

$$$ Avoided Utility Company Payments $4,490,940 Jobs Created 341

$$$ Avoided Fuel Purchases $2,816,847 IRR 51.4%

$$$ Invested Locally in GHG Projects $16,282,854 NPV $11,193,684

Community Benefit (over 25 year life of plan) Financial Metrics

Action Plan B: The plan includes a combination of 28 new measures including 2 MWac of Photovoltaic systems producing over 2.4 million kWh per year. This plan also includes a broad range of efficiency measures for the city buildings, fleet and wastewater system. The fleet measures are more aggressive including a range of gas hybrid, diesel hybrid and all electric vehicle replacements. The plan also includes reducing the Kenilworth pool schedule by 50%. All together, the measures in this plan allow the City to exceed the target of 20% GHG emissions reduction by 2015, yet realize an attractive internal rate of return of 51% and a net present value of the investment of over $11M. The resulting annual cash flow is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The Emissions Trend below illustrates the progress toward the city’s reduction goal.13





Annual Net Cash Flow Plan C

2008 $0

2009 ($31,675)

2010 ($27,162)

2011 ($105,547)

2012 ($58,803)

2013 ($28,170)

2014 ($8,601)

2015 $264,119

2016 $623,194

2017 $714,352

2018 $902,201

2019 $906,596

2020 $984,066

2021 $1,068,013

2022 $1,105,455

2023 $1,144,210

2024 $1,184,324

2025 $1,225,843


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CA LowCarbon Fuel

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Measures andTrends

Plan C: 1,210 Tons CO2e Avoided 22.3% % Reduction





Action Plan C: This plan includes 27 measures. In addition to similar measures of Plan B, Plan C replaces the fleet replacement strategy with a less aggressive strategy, and relies on a major grease to methane gas collection and processing program implemented elsewhere in California. Plan C exceeds the City target of 20% GHG emissions reduction by 2015 with very attractive financial metrics. The Internal Rate of Return is 190% and the Net Present Value exceeds $1.4 million over the term of the analysis (25 years). The annual net cash flow (energy cost savings minus project debt service, replacement costs and associated O&M) is negative for a number of years. However, the cash flow turns strongly positive in 2015. The Emissions Trend below illustrates the progress toward the city’s reduction goal.14





Annual Net Cash Flow Plan D

2008 $0

2009 ($31,675)

2010 ($86,954)

2011 ($108,989)

2012 ($164,804)

2013 ($81,481)

2014 ($58,910)

2015 $236,138

2016 $552,701

2017 $650,181

2018 $1,004,090

2019 $1,012,051

2020 $1,002,750

2021 $1,180,979

2022 $1,166,646

2023 $1,265,223

2024 $1,309,571

2025 $1,355,474


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Plan D: 1,523 Tons CO2 Avoided 28.0% % Reduction





Action Plan D: The plan includes a combination of 35 measures including two residential streetlighting reduction measures not included in previous plans. It includes a 1 MW Photovoltaic system as well as most of the energy efficiency measures that are available for each sector. An aggressive biodiesel fuel measure for the diesel powered vehicles is added to the aggressive fleet replacement program. All together, the measures in this plan allow the City to reduce emission by 28% GHG emissions below 2000 by 2015. While the cash flow is negative in the early years, financial metrics of IRR and NPV are both attractive due to the positive cash flow after 2014. The resulting annual cash flow provided below is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The Emissions Trend below illustrates the progress toward the city’s reduction goal.15





Annual Net Cash Flow Plan E

2008 $0

2009 ($31,675)

2010 ($4,477)

2011 ($213,113)

2012 ($250,293)

2013 ($377,731)

2014 ($355,745)

2015 ($248,700)

2016 $68,582

2017 $229,188

2018 $788,320

2019 $952,315

2020 $1,024,398

2021 $1,203,498

2022 $1,190,071

2023 $1,289,588

2024 $1,334,914

2025 $1,381,832

Plan E: 2,101 Tons CO2e Avoided 38.7% % Reduction





Action Plan E: This plan includes 40 new measures. In addition to most of the measures of Plan D, Plan E replaces the fleet fuel strategy with a more aggressive approach that specifies 99% biodiesel, and adds another 2 MWac PV system. This plan replaces the residential streetlighting measures with a conversion to LED streetlighting systems (or equivalent technology projected to be available by 2012). Plan E pushes the GHG emissions reduction beyond 38% by 2015, and maintains compelling financial metrics. The Internal Rate of Return is over 30% and the Net Present Value exceeds $11M. The annual net cash flow (energy cost savings minus project debt service, replacement costs and associated O&M) turns positive in 2016. The Emissions Trend below illustrates the progress toward the city’s reduction goal.16




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Summary A greenhouse gas (GHG) emissions reduction of 20% by 2015 can be achieved by a number of paths documented in this report. Each path, or Action Plan, is comprised of up to 40 individual measures. Each is evaluated for the financial costs and benefits they contribute to the overall strategy. The total “palette” of quantified opportunities includes 65 new measures to reduce energy consumption. The analysis model underpinning these results will be available for incorporating new information and technologies as they come available, as well as truing the analysis with monitored data. The comprehensive approach to addressing this goal allows the City to meet a number of related goals, including improving the long term financial health of Petaluma, reducing the budget vulnerability to future energy cost escalation, addressing the existing maintenance demands of aging equipment, and providing public demonstration of commitment and progress in the highly visible challenge of greenhouse gas emissions reduction. The information in this report allows the City to understand the challenges and opportunities available in reaching its goal. The evaluation matrix quantifies the many related issues not captured by the financial results or emissions reduction such as public visibility and the resolution of existing problems. The financial results provide information on the investment value of the various paths of action, along with the anticipated net cash flow over time. The ability to understand the complex context of greenhouse gas emissions reduction will allow policy makers to define expected outcomes and associated financial commitments to achieve those outcomes. This provides city staff the flexibility needed to effectively implement the policy. The individual measures within each plan may be delayed, modified or replaced as appropriate while remaining faithful to the policy directive. This flexibility will be essential given the dynamic nature of the regulatory environment and the rapidly evolving financial and technological opportunities in California. In summary, this analytical framework and report organizes the city’s data and documentation relating to energy efficiency and greenhouse gas emissions reduction. It is applied to the city goal of a 20% reduction of emissions below 2000 levels, presenting five strategies to meet this goal. The database and analytical framework supporting this work are available into the future as new information and opportunities (technical and financial) emerge for consideration.



2.0 Introduction Public jurisdictions (cities and counties) have adopted global warming pollution reduction targets and have committed to developing action plans. These detailed plans are required to provide a roadmap to meet the goals and a framework to track and verify the progress toward the goal over the life of the plan. This report provides these capabilities by using an analysis method developed for North Bay cities and applied to the City of Petaluma. This method incorporates all measures across the various sectors (Building Efficiency, Fleet, Commute, Water/Sewer, Streetlights, and Photovoltaic Systems), and provides an emissions impact estimate and a comprehensive financial analysis. Furthermore, this analysis allows independent plans to be analyzed, providing the capability to compare the costs and benefits of competing paths to global warming pollution emissions reduction. The first step, creating the inventory of emissions produced by the internal operations has been completed for all cities and the county. The total emissions for 2000 were roughly 5,400 tons of CO2e.

Baseline GHG Emissions by Sector

Water Wastewater33%

Commute11%

Fleet26%

Streetlights11%

Buildings19%

Solid Waste0%

Figure 4: City of Petaluma GHG Inventory as a Percentage of the 2000 Total



3.0 Methodology

Context The Petaluma GHG emissions inventory for 2000 has been completed and provides a reference for the baseline inventory developed for this analysis.17 The specific actions and events affecting this baseline, either positive or negative, are factored into the inventory and the resulting trend. The baseline inventory has been reconstructed from information made available by Staff at the initiation of this work. The total emissions for 2000 were roughly 5,400 tons of CO2e. There were numerous changes in GHG emissions identified from the utility billing since the baseline year of 2000. These are consolidated and modeled in the analysis as the “End Use” entries in the table below.18 These add another 640 tons to the reduction goal. This information was also used to generate the emissions trend associated with city growth from 2009 to 2020. These projected additional GHG emissions are included in the calculations of each Plan. This adds 106 tons per year which is dependant on the projected population increase each year within the City.19

End Use kWh Therms Fuel (gals)2000-2008 Corporation Yard 37,762 0 0

2000-2008 Muni Pool 0 30,020 0

2000-2008 840 Hopper St Off 0 10,751 0

2000-2008 Lakeville Ag Pumps and Sm Pmps 0 126 0

2000-2008 Streetsignals -397,685 0 0

2000 to 2008 Fleet 0 0 41,990

2000-2008 Commute 0 0 10,266

Totals -359,923 40,897 52,256CO2e (metric tons) -80 229 491

Increases in Energy Consumption from 2000 to 2008

Table 7: Increases in Energy Consumption from 2000 to 2008

The options for future action by the City are comprised of measures applicable to building and equipment energy efficiency, fuel efficiency, alternative fuel options, and distributed energy generation. These options have been identified and quantified within this analysis. They are evaluated and presented as individual projects (measures), and as groups of measures (plans). Each is assigned a status (completed or future) and an implementation date to enable the calculation of cash flows over the life of the plans and the creation of energy cost trend graphs. The “palette” of measures includes emerging technologies which are in the pilot project stage of

17 GHG Inventory Report Petaluma, Simon Wooley, September 2003. 18 These End Uses represent 100% of the energy increases for all accounts as identified in the PG&E billing data. They are labeled as the accounts contributing most to the change and the year associated with the change. 19 Petaluma General Plan 2025 Air Quality – Greenhouse Gas Emissions Section Revised Draft Environmental Impact Report, Winzler and Kelly, November 2007.



implementation. These are included on the assumption that they or an equivalent technology will be available by the year of implementation.20 The measures are grouped to create comprehensive GHG emissions reduction plans. Each of the plans is analyzed to provide profiles enabling the evaluation of the plans individually and in comparison to the other plan options. Measure specific data such as capital cost, year of implementation, financing, energy and cost savings were processed to provide the following information for five action plans:

• Emissions reduction in tons CO2e avoided as a percentage of baseline • CO2e reduction by sector • Annual cash flow including debt service and incremental O&M costs • Outstanding principal and debt service by year • Simple Payback (SBP) for each plan • Internal Rate of Return (IRR) for each plan • Net Present Value (NPV) for each plan • Avoided utility company payments (NPV over life of plan) • Avoided fuel purchases (NPV over life of plan) • Value invested locally in emission reduction projects

The details of each measure are provided, such as the vehicle and pump lists provided in the Measure Details section. The generally applied assumptions, such as the discount rate, interest rate, escalation rate for the cost of utility supplied power and fuel, and the CO2e conversion factors for energy and fuel have also been reviewed and approved by City Staff. The values are provided in Table 8. These general values can be overridden at the measure level if necessary. For example, the term of financing is set to 5 years as a default value. CEC loans are based on generating a net cash flow close to zero for the first year and a positive cash flow over the life of the loan with a maximum value of 10 times the annual cost savings. Where appropriate, the term of the loan is adjusted at the measure level to meet this funding criterion.

20 Example: A streetlighting measure is included which relies on LED technology. There are several pilot projects underway that utilize this technology. However, if this specific strategy does not perform as anticipated (light pattern uniformity has been a concern), this analysis assumes another streetlighting energy savings strategy of similar costs and benefits will be available by the implementation date of 2012.



Measure Identification The list of measures has been generated from document reviews, past experience of other jurisdictions, and a review of the Petaluma facilities completed by numerous energy professionals. All measures included in this analysis have been reviewed for inclusion by City Staff.

The following sources contributed to the information in this report.

• Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008.

• GHG Inventory Report Petaluma, Simon Wooley, September 2003. • Petaluma General Plan 2025 Air Quality – Greenhouse Gas Emissions Section Revised

Draft Environmental Impact Report, Winzler and Kelly, November 2007. • City of Petaluma Community Center and Police Facility HVAC Study, LGEP/Brown

Vence and Associates, December 7, 2005. • Lighting Audit and Recommendations, Animal Shelter, Cavanaugh Center, Corporation

Yard, Senior Center, Soup Kitchen, Association of Bay Area Governments Energy Watch, January 2008.

• Proposal for Solar Electric Design and Build Services at Petaluma City Hall, SPG Solar, November 16, 2007.

• Proposal for Solar Electric Design and Build Services at Petaluma Community Center, SPG Solar, October 15, 2007.

• Proposal for Design Build Services for a Solar Photovoltaic Power System for Regency Centers at the Petaluma Swim Center, SPG Solar, February 7, 2007.

• 25.3 Kilowatt Photovoltaic System Proposal, SPG Solar, March 16, 2006. • PG&E Billing Data • Supporting Data from the City of Petaluma Green Team

Measure Assumptions: General Variables This report is based on a set of general inputs for the financial analysis. Each measure utilizes these general inputs unless they are overridden at the measure level. The general inputs are provided in Table 8 below with an expanded table provided in the appendices. The values used for each measure are provided in the Appendices. These inputs include the following:

• Term of Analysis • Term of Finance • Discount Rate • Energy Inflation Rate • Energy Cost • Interest Rate • Inflation Rate



The conversions in the table below are based on the best available information. The values for natural gas, gasoline, and diesel fuel are consistent with the California Climate Action Registry values.21 The value for 100% ethanol is calculated using data from research published by Argonne Labs.22 The value used for CO2/kWh is based on the PG&E fuel mix and is different than the value specified in the Registry23 and varies with years into the future according to the CPUC required Renewable Portfolio Standard. This analysis has modified the baseline results by using the current value to ensure an appropriate comparison. The costs and benefits assumed for each of the measures is based on the best available information available at the time of research. Some measures have a highly reliable set of costs and energy reduction estimates due to the maturity of the strategy. Lighting retrofits fall into this category. Other measures rely on more vague data, such as the availability of LED streetlighting and the associated costs. The dynamic context for electric and hybrid vehicles is another example of firm possibilities with unconfirmed costs and benefits. The implementation dates of such opportunities are pushed out to 2010, 2012 or later to balance the uncertainty of the cost benefit data. The inclusion of these measures allows for a more complete set of plans and provides the framework for adjustments as more refined information becomes available. The general assumptions and conversions used in this analysis are provided in the table below.

Metric Standard Default Values

Revised Values

Default Values Used in Analysis

Term of Analysis (yrs) 25 25

Term of Financing (yrs) 10 5 5

Discount Rate 5.00% 5.00%

kWh Energy Cost Escalation Rate 3.50% 3.50%

Nat Gas Energy Cost Escalation Rate 3.50% 3.50%

Vehicle Fuel Cost Inflation Rate 7.80% 7.80%

Energy Cost ($/kWh) $0.145 $0.145

Energy Cost ($/Therm) $1.000 1.000

Interest Rate 3.95% 3.95%

Inflation Rate 3.50% 3.50%

Conversions

CO2/kWh (lbs.) 0.489 0.489

CO2/Therm (#/Therm) 12.34 12.34

CO2e Gasoline (lbs/gal) 20.7 20.7

CO2e Diesel (lbs/gal) 21.0 21.0

BioDiesel (lbs/gal) 0 5.242 5.242

Ethanol (lbs/gal) 12.23 12.23

$/gal Gasoline $3.08 $3.08

$/gal Diesel $3.08 $3.08

$/gal Biodiesel $3.38 $3.38

$/gal Ethanol (equivalent gallon) $4.00 $4.00

$/Therm CNG Vehicles $1.00 $1.00

$/kWh Electric Vehicles $0.145 $0.145

Electric Vehicle miles/kWh (subcompact) 0.3 0.3

Electric Vehicle miles/kWh (full size) 0.2 0.2

Target (% of 2000) 20.0% 20.0%

Power Purchase Agreement (PPA) Initial % Increase over Utility kWh 5.00% 5.00%

PPA Energy Cost Escalation Rate 3.50% 3.50%

Table 8: General Inputs

21 California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008. 22 Effects of Fuel Ethanol Use on Fuel-Cycle Energy and Greenhouse Gas Emissions; M. Wang, C. Saricks, and D. D. Santini; Argonne Labs; January 1999. 23 PG&E Power Content: Eligible Renewables: 13%, Coal: 2%, Large Hydro: 17%, Natural Gas 44%, Nuclear: 23%, Other; 1%, California Energy Commission, www.energy.ca.gov/consumer, May 2007.



Measure Specific Variables The general inputs can be adjusted for each individual measure as appropriate. The other key individual inputs are listed below. The values for each measure are provided in the Appendices.

• Category (Building, Fleet, Commute, Distributed Generation, Water/Sewer) • Status (Completed, Pending, and Future). Pending measures are defined as those

provided by City Staff with identified funding. • Financing: The cash flow is heavily dependent on whether or not the measures are

financed. This funding decision is defined for each measure independently. • Project Implementation Date • Net Capital Cost • Incremental Capital Cost associated with the cost premium associated with the improved

efficiency. For Example: a hybrid compact vehicle is assigned a cost premium of $4000 over an equivalent standard vehicle.

• Rebates and incentives • Annual O&M cost associated with the efficiency measure • Incremental Replacement Cost • Component Life • Time of Use factor (Photovoltaic systems)

Financial Analysis Results The analysis provides the financial information required for investment decisions. This includes the following:

• Net Cash Flow for each year of the plans • Debt load for each year of each plan • Simple Payback for each plan • Internal Rate of Return • Net Present Value • CO2e reduction for each plan

Financial Definitions24 Simple Pay Back (SPB): Simple pay back is determined by dividing the capital cost by the annual cost savings for an investment. While not effective in determining the value of the investment in terms of return on investment, it does provide the length of time before the initial investment is repaid. Given the various implementation dates for actions analyzed in each plan, the SPB for the plans is calculated by summing the net cost for each measure regardless of implementation date and comparing this value to the sum of the positive cash flows in subsequent years.

24 http://www.investopedia.com/terms, http://www.visitask.com



Net Present Value (NPV): Net Present Value (NPV) is the difference between the present value of cash inflows and the present value of cash outflows. NPV is used in capital budgeting to analyze the profitability of an investment or project. NPV analysis is sensitive to the reliability of future cash inflows that an investment or project will yield.

Where t - the time of the cash flow n - the total time of the project r - the discount rate Ct - the net cash flow (the amount of cash) at time t. C0 - the capital outlay at the beginning of the investment time ( t = 0 ) Internal Rate of Return (IRR): The Internal Rate of Return (IRR) is the discount rate that generates a zero net present value for a series of future cash flows. This essentially means that IRR is the rate of return that makes the sum of present value of future cash flows and the final market value of a project (or an investment) equal its current market value.

Generally speaking, the higher a project's internal rate of return, the more desirable it is to undertake the project. As such, IRR can be used to rank several prospective projects under consideration. Assuming all other factors are equal among the various projects, the project with the highest IRR would probably be considered the best and undertaken first.

The IRR is based on the total investment and energy cost savings over the life of the investment, independent of the financing strategy for the investment.25

Community Benefit The investments in the specific measures have positive local consequences. The community benefits are quantified and presented in the following outcomes:

1) $$$ Avoided Utility Company Payments: This is the Net Present Value (NPV) of all the avoided electricity and natural gas payments over the 25 year period of the analysis.

2) $$$ Avoided Fuel Payments: The NPV of the avoided gasoline and diesel fuel payments over the 25 year life of the analysis.

3) $$$ Invested Locally in GHG Projects: This is the total capital cost of the measures specified for the plan. This analysis does not attempt to separate labor, material, overhead or profit to more accurately identify the percentage of these investments likely to remain local. The inherent overstatement of this result is balanced to a significant degree by discounting the well-documented economic multiplier effect of local investment (no multiplier is used). Bio-diesel purchase is considered 100% local. In practice, this will depend on the supplier. Ethanol is not considered to be a local purchase.

25 The IRR and NPV for the Plans are calculated from the cash flows of the individual measures included in the respective plan, independent of the implementation date of each measure. This strategy results in a first year “investment” required for the IRR calculation and a subsequent annual cash flow (the return on investment).



4) Jobs Created: This is a simplified calculation using the methodology defined in the 2009 Federal Stimulus Package application procedures.

The formula is: $1.0 Million in Capital Expenditure = 17 jobs created

This methodology does not incorporate timing of the expenditure or duration.

Measure Evaluation The decision to include a measure in the action plan is based on a comprehensive appraisal of that measure and its impact on the overall cost/benefits of the Action Plan. To aid in the selection process, each measure has been evaluated and scored for eight metrics listed below. While informative, the scoring of the measures is not binding on the selection process. The results of the Measure Evaluation are presented in the Plan Results section. A summary of the individual measure scoring is in the appendices.

1) Cost: The measure is scored by the magnitude of the net capital cost, independent of other considerations.

2) Financial Metrics: The measure is scored by the internal rate of return (IRR) and Net Present Value (NPV). IRR and NPV are determined from the investment required for the measure (Net Capital Cost), the annual cost savings and the resulting annual cash flow.

3) Resolution of Existing Problems: This metric evaluates how the measure solves existing problems, such as a failing air conditioning system. The replacement of old mechanical units will save maintenance staff time and associated costs (maintenance savings are not calculated in the cash flows).

4) GHG Impact: The measure is scored on its impact on the reduction of GHG emissions, relative to the other measures under consideration.

5) Public Visibility: Some measures provide an additional benefit by demonstrating to the general public the actions of the jurisdiction to address global warming. Measures such as Photovoltaic systems are scored high for Public Visibility.

6) Employee Impact: The additional burden or inconvenience imposed on City Staff is a consideration for any measure under consideration. This metric evaluates this impact. A photovoltaic system has no impact and receives a neutral score. New fleet vehicles will require a change from “business as usual” and results in a lower score. The Commute measure creates transportation options for the City Staff and receives a higher score.

7) Community Impact: The additional benefit, burden or inconvenience imposed on the community is a consideration as well. This metric evaluates this impact. The improvement of public facilities, lighting or HVAC for example, would result in a favorable score. The imposition of additional fees or hardship on the community would result in an unfavorable score.

8) Energy Cost Stabilization: Energy cost variability is a concern for all jurisdictions. The price volatility of natural gas and the spike in cost for electricity in 2000-2001 give reason to address this vulnerability. This metric evaluates the impact by measure on the City’s long term energy cost volatility. The highest value is assigned to energy efficiency measures. Energy saved by efficiency has an effective cost of $0 into the future, as long as the efficiency measure is in place.



California Low Carbon Fuel Standard In the January 2007 State of the State, Governor Schwarzenegger asserted California's leadership in clean energy and environmental policy by establishing a Low-Carbon Fuel Standard (LCFS) by Executive Order. This first-in-the-world greenhouse gas (GHG) standard for transportation fuels will spark research in alternatives to oil and reduce GHG emissions.26 The target GHG reduction is 10%. This analysis assumes this goal will be met over a 12 year period. This would reduce the carbon density for gasoline from 20.968 lbs CO2e/gallons to 18.871 lbs CO2e/gallon with a similar reduction for Diesel.

PG&E Power Content and City Future Action Assumptions The sources of energy purchased by the utility determine the carbon density (lbs CO2e per kWh) of the electricity produced by the utility and used by the City. This “Power Content” is identified by the utility and reported by the CPUC on an annual basis. There is a requirement that the content rely on increasing percentages of renewable resources. The Renewable Portfolio Standard (RPS) requires electric corporations to increase procurement from eligible renewable energy resources by at least 1% of their retail sales annually, until they reach 20% by 2010.27 As the power content carbon density decreases the emissions associated with electrical energy use decreases. Also as the carbon density decreases, the CO2e reductions per kWh displaced by photovoltaic and energy efficiency measures also decreases. Therefore a kWh saved in 2009 will be more significant than a kWh saved in 2015 if the Power Content is more “green” in 2015. This dynamic is factored into the analysis which is time dependent for both the implementation date of the measure and the reporting date for the reduction below 2000 levels. This relationship is represented by the “PGE mix” portion of the area graphs provided in the “CO2e reduction 2000 – 2020” figures for each Action Plan. The values assumed for the PG&E Power Content by year are provided in the table below. An adjustment of 50% is applied to the source material to acknowledge the perceived “optimistic” nature of projected renewable content.28

Year 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014Modified Power Content used in analysis

0.566 0.558 0.551 0.543 0.535 0.528 0.520 0.512 0.504 0.497 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.480 0.470 0.461 0.451 0.442 0.432

MethodologyCPUC Target Power Content 0.566 0.558 0.551 0.543 0.535 0.528 0.520 0.512 0.504 0.497 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.489 0.470 0.451 0.432 0.413 0.394 0.375

Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035Modified Power Content used in analysis

0.423 0.413 0.404 0.395 0.387 0.378 0.370 0.362 0.354 0.346 0.338 0.331 0.324 0.316 0.309 0.303 0.296 0.290 0.283 0.277 0.271

MethodologyCPUC Target Power Content 0.356 0.338 0.321 0.305 0.289 0.275 0.261 0.247 0.235 0.223 0.212 0.201 0.191 0.181 0.172 0.163 0.155 0.147 0.140 0.133 0.126

Assumed Linear

Assumed constant % reduction based on 2014 / 2015 ratio

Assumed linear from 1990 to 2000 Constant from 2000 to 2008

Figure 5: Power Content Values for Converting kWh to lbs/CO2e

26 California Energy Commission, http://www.energy.ca.gov/low_carbon_fuel_standard, March 2009 27 California Public Utilities Commission, http://www.cpuc.ca.gov/PUC/energy/Renewables/ 28 The inclusion of the PG&E fuel mix has a significant impact on the greenhouse gas emissions of the City in future years. The California Public Utilities Commission (CPUC) has required the fuel mix to be increasingly renewable from 2008 forward. The value for lbs/kWh declines from 0.489 in 2008 to 0.356 in 2015 per calculations published by the Climate Protection Campaign in the Sonoma County Community Climate Action Plan issued in November 2008.



Future Actions This analysis provides specific information on the impacts of discreet actions to reduce greenhouse gas emissions from City controlled equipment and operations. The last of these measures is implemented in 2014 for all plans. However, the trend of greenhouse gas emissions is provided to the year 2020, including the annual increase in emissions associated with projected city growth. To balance this structural increase from 2015 to 2020, and to acknowledge that the policy of action regarding greenhouse gas emissions will likely persist at the pace established by actions from 2009 to 2015, a “Future Actions” placeholder is included in the analysis and is represented in the “CO2e Reduction 2000 – 2020 (Net)” graph provided with each Action Plan. These are based on the level of reductions from 2009 to 2015 unique to each plan. These reflect a diminishing “rate of return” on emissions reduction actions of 30% per year. There are no costs calculated for these future actions. They are not included in the financial metrics or cash flows for each plan. They also do not contribute to the GHG reduction values or percentages reported with each plan. The emissions reporting date is 2015 which is prior to impact of the “future trends” element of the analysis.

4.0 Results Five plans have been created for consideration by the City of Petaluma. These plans consist of numerous measures to reduce GHG emissions, reduce energy costs, address equipment problems, and reduce the volatility of the City’s annual energy costs. Summary information is provided below. The Action Plan Evaluation provided in the Appendices provides an analysis of the relative strengths of each combination of measures. Similar information for each measure is also provided.

GHG Impacts and Plan Financial Results Table 9 below provides a comparison of each plan. The “% Reduction” is the amount of CO2e reduced as a percentage of the total City emissions. Each plan meets the goal by a unique set of measures. Plan E identifies the measures necessary to reduce the City’s emissions by approximately 38% below year 2000 emissions by 2015. The financial analysis is provided with each plan. The IRR and NPV results are based on the 25 year term of the analysis.



Analysis Plan A Plan B Plan C Plan D Plan E

% Reduction below 2000 by 2015 23.2% 22.3% 22.3% 28.0% 38.7%

SPB NA 5.3 0.6 1.9 6.5

IRR NA 51.4% 190.0% 82.1% 33.3%

NPV ($17,463,599) $11,193,684 $12,587,862 $13,419,544 $11,874,177

Annual Net Cash Flow Plan A Plan B Plan C Plan D Plan E

2009 ($20,000) ($44,719) ($31,675) ($31,675) ($31,675)

2010 ($1,596,983) ($49,327) ($27,162) ($86,954) ($4,477)

2011 ($1,613,670) ($34,983) ($105,547) ($108,989) ($213,113)

2012 ($1,615,524) ($51,825) ($58,803) ($164,804) ($250,293)

2013 ($1,622,008) ($51,357) ($28,170) ($81,481) ($377,731)

2014 ($2,431,370) ($46,475) ($8,601) ($58,910) ($355,745)

2015 ($3,800,958) $54,338 $264,119 $236,138 ($248,700)

2016 ($3,746,521) $303,723 $623,194 $552,701 $68,582

2017 ($3,720,353) $369,909 $714,352 $650,181 $229,188

2018 ($3,693,262) $803,707 $902,201 $1,004,090 $788,320

2019 ($3,929,665) $807,525 $906,596 $1,012,051 $952,315

2020 $851,328 $922,253 $984,066 $1,002,750 $1,024,398

2021 $881,387 $1,048,274 $1,068,013 $1,180,979 $1,203,498

2022 $912,505 $1,085,081 $1,105,455 $1,166,646 $1,190,071

2023 $363,554 $1,123,179 $1,144,210 $1,265,223 $1,289,588

2024 ($1,346,594) $1,162,615 $1,184,324 $1,309,571 $1,334,914

2025 $1,012,600 $1,203,435 $1,225,843 $1,355,474 $1,381,832

GHG Action Plan Summary

Table 9: Action Plan Financial Results

The financial analysis is provided with each plan. The critical metrics of Internal Rate of Return (IRR), and Net Present Value (NPV) provide important information to evaluate the worthiness of the investment from a cash flow perspective. It is important to note the large negative net cash flows for Plan A in 2024. These are incurred by substantial reinvestments in large photovoltaic (PV) systems (replacement of the associated inverters after 10 years). The assumption is that the cost of inverters will increase at the generally assumed inflation rate of 3%. However, likely advances in technology and improved economies of scale for the industry suggest this is overly conservative. The other plans utilize power purchase agreements where the cost of the inverter replacement is included in the agreement.



Finally, the actual net cash flow is also provided for each plan in Table 9. An expanded cash flow table is provided with each plan that breaks out the gross cash flow, annual debt service payment and outstanding principal for each year of the plan. This presentation allows a clear understanding of the impacts of a “financial decision” in 2009 over the life of the plan.

Action Plan Evaluations The GHG Emission Reduction Action Plans involve more than CO2e reduction and cash flow. There are critical concerns that should be factored into the decision making process. These include the financial metrics of Internal Rate of Return (IRR) and Net Present Value (NPV) to evaluate the worthiness of the investment; the cost of implementing the measure, some measures come with a large price tag which will challenge liquidity; the degree to which the plan resolves existing problems, such as old, high maintenance air conditioning units; the visibility of the measures to the public, for example the photovoltaic systems are a physical example of actions taken the City and communicate action and commitment to the community. Other key considerations include the employee impacts of new equipment or procedures, which may generate internal opposition; and the impact on the variability of future energy costs and the associated budgetary vulnerability.

Each measure and the plans as a whole are evaluated by the following considerations:

• Net Capital Cost • Financial Metrics (IRR and NPV) • Resolution of Existing Problems • GHG Impact • Public Visibility • Employee Impact • Community Impact • Energy Cost Stabilization

The results of the evaluation are provided in the Appendices. The individual scores for each category (cost, financial metrics, etc.) are aggregated to provide an overall score for that measure. While the results provide important information to be considered when selecting measures, the scores are advisory only. A relatively low score does not preclude a measure, nor should a high score guarantee inclusion of the measure in the Action Plans. There will always be additional considerations that are not reflected in the evaluation process.



Energy Rate Escalation and Associated Budget Vulnerability There is considerable discussion about the availability of fossil fuels in the near and middle term future (5 to 20 years). The “Peak Oil” movement suggests that we are at or near the point where our increased global demand for oil cannot be supplied from new petroleum discoveries while production from existing oil fields is waning. Similar arguments are made for natural gas supply vs. demand. If demand outstrips supply, simple economics indicate that the cost to consumers will escalate rapidly, until the global demand is sufficiently dampened and realigns with available supply. The concern is significant enough to have prompted a US government sponsored study to determine the impacts of demand exceeding supply in the near future.29 This issue has important implications for North Bay jurisdictions. Forty percent of PG&E power is generated by natural gas.30 A spike in the cost of this energy source will result in significant increases in the cost of electrical power, as well as increased volatility in the cost of natural gas and fleet fuel used directly by the City.

29 Hirsch, Robert. et al. (February 2005) “Peaking of World Oil Production: Impacts, Mitigation, & Risk Management.” SAIC. 30 PG&E Power Content: Eligible Renewables: 15%, Coal: 2%, Large Hydro: 16%, Natural Gas 47%, Nuclear: 20%, Other; 1%, California Energy Commission, www.energy.ca.gov/consumer, February 2009.



All of the measures available to reduce GHG emissions also will reduce the City energy costs. These costs are a significant element of the municipal budget, and the potential volatility of their costs represents a threat beyond the control of City Staff. Figure 6 below provides the trends for the annual cost of fleet fuel and utility supplied electricity and natural gas based on four rate escalation scenarios. The bottom most trend line indicates the annual cost of energy from 2000 to 2020 if the cost of energy increases at 1.7% per year.31 The other trend lines represent costs to the city if the escalation rate is 3.5%, 6.0% and 12%. The measures contained in this analysis will reduce the vulnerability to energy price increases. These trend lines assume that the City takes no further action to reduce or increase its reliance on fleet fuel, and utility supplied electricity and natural gas.

Energy Cost Escalation Scenarios

$2,901,041

$3,990,025

$4,768,401

$9,232,486

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Ann

ual E

nerg

y C

ost (

Fuel

, NG

, Ele

c.)

Town annual energy cost with no future energy conservation actions

12%

3.5%

Annual Energy Cost

EnergyEscalation

Rate

6.0%

1.7%

Figure 6: Energy Rate Escalation Scenarios

31 An annual increase of 1.7% is considered very optimistic. This value was used in the Community Choice Aggregation analysis for Marin County in 2007.



The future cost of vehicle fuel (gasoline and diesel) is much more volatile than the other energy sources. The cost of this resource has increased by 7.8% a year on average since 1987 (see the Appendices for further discussion on the cost trends of vehicle fuel). If fuel increases continue at the 7.8% rate the future cost will follow the 8% line in Figure 7 below. However, if prices increase at twice the past rate (represented by the 16% line) then the annual cost of vehicle fuel will approach $2M by 2020. This trend is discussed in greater detail in the appendices.

Vehicle Fuel Cost Escalation Scenarios

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Ann

ual T

otal

Cos

t of V

ehic

le F

uel

Gasoline and Diesel Annual Escalation Rates (Historical trend 8% since 1987)

20%

16%

12%

4%

8%

Uni

t Cos

t Ann

ual P

erce

ntag

e In

crea

se

Figure 7: Annual Cost Trend of Vehicle Fuel Only



Energy efficiency projects and distributed generation energy systems can play a significant role in moderating this vulnerability. Figure 8 below provides potential impact of energy efficiency strategies on the associated vulnerability. For example, under the 3.5% escalation rate scenario, the City is projected to reduce its fleet fuel and utility payments by roughly $1.5M per year in 2020 by implementing the efficiency measures in Action Plan D.

Future Energy Cost Mitigation

$2,247,226

$2,810,172

$2,913,041

$2,616,326$2,506,618

$4,112,005

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Annu

al E

nerg

y C

osts

: Fue

l, N

G, E

lect

ricity

Annual Energy Cost

Escal. Rate N.Gas and Elec.= 3.5%Diesel and Gas = 8%

No Action

Plan C

Plan BPlan DPlan EPlan A

Figure 8: Annual Cost of Energy

The trend lines compare the outcomes for different approaches to energy savings with a 3.5% annual escalation of energy rates:

• No Action, $4,112,000 annual energy cost in 2020 (at a utility energy escalation rate of 3.5%) approximates the annual cost to the City if no actions are pursued to reduce energy consumption in the future.

• Plan B: $2,810,000 annual energy cost in 2020 at a utility energy escalation rate of 3.5% based on the actions contained in Action Plan B.

• Plan E: $2,507,000 annual energy cost in 2020 using the same escalation rate as above if the more aggressive measures contained in Action Plan E are pursued. This is a reduction of $1,500,000 in energy budgeting uncertainty between Plan E and the “No Action” scenario for the annual utility escalation rate of 3.5%.

In summary, an aggressive energy strategy could significantly reduce the City’s exposure to the rapidly escalating costs. The investments in energy efficiency and distributed generation will reduce the uncertainty in future energy cost supporting long term budget planning.



Incremental Capital Cost of Efficiency Measures Many of the opportunities to reduce energy consumption, and thereby reduce greenhouse gas emissions, involve the replacement of old, poorly performing equipment. In many cases this equipment is at the end of its useful life and is scheduled to be replaced independently of this analysis. In these situations this analysis includes only the incremental cost for exceeding the efficiency of a standard unit or approach. There are two common examples where this issue comes into play. The cost associated with replacing the package HVAC units is the additional cost incurred for purchasing SEER 15 units over the purchase of the standard SEER 13 units. This incremental cost depends on the cooling capacity of the unit, but is in the range of 3-10% of the cost of the unit. “Cool Roof” reflective coatings add an incremental cost of roughly $1.5 per sqft to the overall reproofing project cost. This incremental value is utilized in the analysis. The cost assumed for the fleet replacement strategies are another example of the use of incremental capital cost. It should be noted that many of the energy efficiency packages identified in these plans can be financed using California Energy Commission energy efficiency loans, including the non-incremental costs. These loan packages are typically structured to have a net zero cash flow (energy savings = loan payment). The replacement of air conditioning equipment that is beyond its useful life would be one application of this opportunity.



Year Cash Flow (Capital and

Savings)

Annual Debt Service

PaymentsNet Cash Flow Outstanding

Principal

2009 ($20,000) $0 ($20,000) $8,002,843

2010 $198,149 ($1,795,131) ($1,596,983) $6,653,824

2011 $210,622 ($1,824,292) ($1,613,670) $5,092,358

2012 $208,768 ($1,824,292) ($1,615,524) $3,469,215

2013 $202,284 ($1,824,292) ($1,622,008) $5,784,800

2014 $290,806 ($2,722,176) ($2,431,370) $19,293,966

2015 $715,712 ($4,516,670) ($3,800,958) $15,539,408

2016 $740,989 ($4,487,509) ($3,746,521) $11,665,705

2017 $767,156 ($4,487,509) ($3,720,353) $7,638,992

2018 $794,247 ($4,487,509) ($3,693,262) $3,453,222

2019 ($340,041) ($3,589,625) ($3,929,665) $0

2020 $851,328 $0 $851,328 $0

2021 $881,387 $0 $881,387 $0

2022 $912,505 $0 $912,505 $0

2023 $363,554 $0 $363,554 $0

2024 ($1,346,594) $0 ($1,346,594) $0

2025 $1,012,600 $0 $1,012,600 $0

CO2e %Reductions by Sector

PV95%

Commute 1%

Water Wastewater

0%

Fleet1%

Streetlighting0%

Building3%

Plan Details

Plan A: 1,263 Tons CO2e Avoided 23.2% % Reduction

$$$ Avoided Utility Company Payments $8,202,668 Jobs Created 1,095

$$$ Avoided Fuel Purchases $111,593 IRR NA

$$$ Invested Locally in GHG Projects $53,093,053 NPV ($17,463,599)

Financial MetricsCommunity Benefit (over 25 year life of plan)

Action Plan A: This plan has 10 specific actions and reduces the net GHG by 23% below 2000 levels. This plan relies primarily on the generation of electricity from photovoltaic systems. A total of 6.6 MWac of PV projects are included, roughly half utilize the power purchase agreement approach to financing. The PPA approach requires no capital or O&M expenditure. The financial metrics of this approach are very challenging where the NPV is negative $17M. The resulting annual cash flow is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The negative value in year 2024 is due to PV inverter replacement. The GHG Emissions graph below depicts the growth of emissions from 2000 to present and the reduction anticipated with this plan into the future. It includes the impact of the CA Renewable Portfolio Standard (RPS) and the CA Low Carbon Fuel Standard.32

32 The reductions are obtained by reading the bottom curve on the graph on the next page. The Renewable Portfolio Standard (RPS) impacts are assumed to be 50% of the stated statewide targets.



Selected Measure Number Measure Name Implementation

DateFinanced (yes/no)

y 36 4 day work week (Commute) 2009 no

y 37 4 day work week (Building) 2009 no

y 42 Nissan Electric Vehicles (Exclusive to other Fleet Measures) 2010 yes

y 54 PV 1.0 MWac (PPA) 2011 no



y 57 PV .5 MWac (PPA) 2012 no

y 58 PV .5 MWac 2013 yes

y 59 PV 1.0 MWac 2009 yes

y 60 PV 2.0 MWac 2014 yes

Plan A Measure List

GHG Emissions Trend by Sector

-4,800

-4,000

-3,200

-2,400

-1,600

-800

0

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

CO

2e R

educ

tion

(tons

)

-100%

-80%

-60%

-40%

-20%

0%

Future Actions

Power Content

CA Low CarbonFuel

WaterWastewater

Commute

Streetlighting

PV

Fleet

Building




Building22%

Streetlighting9%

Fleet35%

Commute 5%

Water Wastewater

3%

PV26%

Plan B: 1,213 Tons CO2e Avoided 22.3% % Reduction





Action Plan B: The plan includes a combination of 28 new measures including 2 MWac of Photovoltaic systems producing over 2.4 million kWh per year. This plan also includes a broad range of efficiency measures for the city buildings, fleet and wastewater system. The fleet measures are more aggressive including a range of gas hybrid, diesel hybrid and all electric vehicle replacements. The plan also includes reducing the Kenilworth pool schedule by 50%. All together, the measures in this plan allow the City to exceed the target of 20% GHG emissions reduction by 2015, yet realize an attractive internal rate of return of 51% and a net present value of the investment of over $11M. The resulting annual cash flow is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The Emissions Trend below illustrates the progress toward the city’s reduction goal.33


Year Cash Flow (Capital and Savings)

Annual Debt Service Payments Net Cash Flow Outstanding

Principal

2009 ($44,719) $0 ($44,719) $274,651

2010 $12,280 ($61,607) ($49,327) $1,202,260

2011 $246,083 ($281,067) ($34,983) $1,125,653

2012 $264,452 ($316,277) ($51,825) $2,644,808

2013 $666,656 ($718,012) ($51,357) $2,031,266

2014 $671,537 ($718,012) ($46,475) $2,024,155

2015 $852,208 ($797,871) $54,338 $1,306,239

2016 $882,134 ($578,411) $303,723 $779,423

2017 $913,110 ($543,201) $369,909 $267,009

2018 $945,173 ($141,466) $803,707 $136,090

2019 $948,991 ($141,466) $807,525 $0

2020 $922,253 $0 $922,253 $0

2021 $1,048,274 $0 $1,048,274 $0

2022 $1,085,081 $0 $1,085,081 $0

2023 $1,123,179 $0 $1,123,179 $0

2024 $1,162,615 $0 $1,162,615 $0

2025 $1,203,435 $0 $1,203,435 $0




-4,800

-4,000

-3,200

-2,400

-1,600

-800

0

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

CO

2e R

educ

tion

(tons

)

-100%

-80%

-60%

-40%

-20%

0%

Future Actions

Power Content

CA Low CarbonFuel

PV

Fleet

WaterWastewater

Commute

Streetlighting

Building

Emission Reductions Including Utility Power Content Trend

and Assumed Future Actions



y 9 K. Swim Center Closure 50% Days (exclusive to other K. Swim pool measures) 2009 no

y 10 Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 2009 no

y 11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 (Matched to #10) 2010 yes

y 14 City Hall, Com Cntr, Police Dept. SBEA Lighting Measures 2006 yes

y 15 Police Facility Energy Management System MCAP 2010 yes

y 16 Police Facility HVAC Upgrade to 16 SEER and 80% AFUE ABAGEW / HDR EEM-2 2012 yes

y 17 Luchessi Cmty Cntr Replace Gas Pcks w/ High Eff UnitsEEM-9 (Exclusive to #18) 2011 yes

y 19 Animal Shelter Lighting Retrofit ABAG EW 2009 yes

y 20 Corporation Yard Lighting Retrofit ABAG EW 2009 yes

y 21 Cavn. Cntr Lighting Retrofit ABAG EW 2009 yes

y 22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2009 yes

y 23 Senior Center Lighting Retrofit ABAG EW 2009 yes

y 24 Airport Lighting Retrofit ABAG EW 2009 yes

y 25 Vending Machine Controls 2009 yes

y 26 Retrofit Frates Pumps (Zone 4) 2010 yes

y 28 SolarBeeTM (unless new facility removes need)

2009 yes

y 30 Streetlighting A: 50% Conversion HPS to LED (or equiv.) 2012 yes

Plan B Measure List



y 32 Streetlighting C: Turn off 50% of Residential lighting (non intersection) 2010 no

y 34 Commute 1 2010 no



y 39 Bus Fleet B 2014 yes

y 41 Fleet Replacement Strategy B (includes Nissan Elec) 2012 yes

y 49 Biodiesel 50% linked to Fleet B 2010 no

y 53 Fleet Management Software Linked to Fleet Replacement B 2010 yes


y 62 K.Swim Center 80 kWac PV System MCAP 2010 yes

y 64 Public Works PV System 25.3 kWac 2009 yes

y 65 Efficiency Coordinator (.5FTE) 2010 no

Plan B Measure List (continued)




Building21%

Streetlighting2%

Fleet32%

Commute 5%

Water Wastewater

27%

PV13%

Plan C: 1,210 Tons CO2e Avoided 22.3% % Reduction





Action Plan C: This plan includes 27 measures. In addition to similar measures of Plan B, Plan C replaces the fleet replacement strategy with a less aggressive strategy, and relies on a major grease to methane gas collection34 and processing program implemented elsewhere in California. Plan C exceeds the City target of 20% GHG emissions reduction by 2015 with very attractive financial metrics. The Internal Rate of Return is 190% and the Net Present Value exceeds $1.4 million over the term of the analysis (25 years). The annual net cash flow (energy cost savings minus project debt service, replacement costs and associated O&M) is negative for a number of years. However, the cash flow turns strongly positive in 2015. The Emissions Trend below illustrates the progress toward the city’s reduction goal.35

34 See Appendix 7.8 “Grease to Gas Augmentation of Digester Gas” which describes the Riverside CA experience with a restaurant trap grease program. 35 The reductions are obtained by reading the bottom curve on the graph on the next page. The Renewable Portfolio Standard (RPS) impacts are assumed to be 50% of the stated statewide targets.



Principal

2009 ($31,675) $0 ($31,675) $188,965

2010 $15,225 ($42,387) ($27,162) $1,619,073

2011 $265,464 ($371,011) ($105,547) $1,577,896

2012 $371,848 ($430,651) ($58,803) $1,901,582

2013 $557,707 ($585,877) ($28,170) $1,390,818

2014 $577,276 ($585,877) ($8,601) $1,131,472

2015 $868,530 ($604,411) $264,119 $571,754

2016 $898,981 ($275,788) $623,194 $318,551

2017 $930,499 ($216,148) $714,352 $114,986

2018 $963,122 ($60,921) $902,201 $58,607

2019 $967,517 ($60,921) $906,596 $0

2020 $984,066 $0 $984,066 $0

2021 $1,068,013 $0 $1,068,013 $0

2022 $1,105,455 $0 $1,105,455 $0

2023 $1,144,210 $0 $1,144,210 $0

2024 $1,184,324 $0 $1,184,324 $0

2025 $1,225,843 $0 $1,225,843 $0




-4,800

-4,000

-3,200

-2,400

-1,600

-800

0

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

CO

2e R

educ

tion

(tons

)

-100%

-80%

-60%

-40%

-20%

0%

Future Actions

Power Content

CA Low CarbonFuel

PV

Fleet

WaterWastewater

Commute

Streetlighting

Building




y 1 K. Swim Center Solar Thermal Repair MCAP (Exclusive to #2,7,8,9) 2010 yes

y 3 K.Swim Center VFD MCAP (Exclusive to #9) 2010 yes

y 4 K.Swim Center Pool Covers Repl. MCAP (Exclusive to #9) 2009 yes

y 5 K. Swim Cntr Opt. Operation Pool Pumps and Filtration EEM-1 (Exclusive to #6,9) 2009 no












y 29 Grease to Gas Methane Program 2011 yes


Plan C Measure List






y 38 Bus Fleet A 2014 yes

y 40 Fleet Replacement Strategy A (includes Nissan Elec) 2010 yes

y 48 Biodiesel 50% linked to Fleet A 2010 no

y 52 Fleet Management Software Linked to Fleet Replacement A 2010 yes


y 61 Community Center 41 kWac PV MCAP 2010 yes



Plan C Measure List (continued)




Building13%

Streetlighting12%

Fleet30%

Commute 7%

Water Wastewater

25%

PV13%

Plan D: 1,523 Tons CO2 Avoided 28.0% % Reduction





Action Plan D: The plan includes a combination of 35 measures including two residential streetlighting reduction measures not included in previous plans. It includes a 1 MW Photovoltaic system as well as most of the energy efficiency measures that are available for each sector. An aggressive biodiesel fuel measure for the diesel powered vehicles is added to the aggressive fleet replacement program. All together, the measures in this plan allow the City to reduce emission by 28% GHG emissions below 2000 by 2015. While the cash flow is negative in the early years, financial metrics of IRR and NPV are both attractive due to the positive cash flow after 2014. The resulting annual cash flow provided below is the net income to the City (energy cost savings minus project debt service, replacement costs and associated O&M). The Emissions Trend below illustrates the progress toward the city’s reduction goal.36




Principal

2009 ($31,675) $0 ($31,675) $274,651

2010 ($25,346) ($61,607) ($86,954) $1,485,063

2011 $235,514 ($344,503) ($108,989) $1,478,442

2012 $242,332 ($407,135) ($164,804) $2,546,665

2013 $643,495 ($724,976) ($81,481) $1,922,282

2014 $666,066 ($724,976) ($58,910) $1,544,829

2015 $960,429 ($724,290) $236,138 $881,560

2016 $994,096 ($441,395) $552,701 $474,986

2017 $1,028,943 ($378,762) $650,181 $114,986

2018 $1,065,011 ($60,921) $1,004,090 $58,607

2019 $1,072,973 ($60,921) $1,012,051 $0

2020 $1,002,750 $0 $1,002,750 $0

2021 $1,180,979 $0 $1,180,979 $0

2022 $1,166,646 $0 $1,166,646 $0

2023 $1,265,223 $0 $1,265,223 $0

2024 $1,309,571 $0 $1,309,571 $0

2025 $1,355,474 $0 $1,355,474 $0




-4,800

-4,000

-3,200

-2,400

-1,600

-800

0

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

CO

2e R

educ

tion

(tons

)

-100%

-80%

-60%

-40%

-20%

0%

Future Actions

Power Content

CA Low CarbonFuel

PV

Fleet

WaterWastewater

Commute

Streetlighting

Building






y 7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 (Exclusive to #4 and 8,9) 2012 yes



y 13 Cavn. Cntr Install Cool Roof EEM-8 2011 yes



y 18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 (Exclusive to #17) 2011 yes










2009 yes

Plan D Measure List




y 32 Streetlighting C: Turn off 50% of Residential lighting (non intersection) 2010 no

y 33 Streetlighting D: Turn off 50% of Residential lighting (non intersection) 2012 no





y 38 Bus Fleet A 2014 yes







y 63 City Hall PV System 50kWac 2012 yes




Plan D Measure List (continued)




Building19%

Streetlighting3%

Fleet25%

Commute 6%

Water Wastewater

21%

PV26%

Plan E: 2,101 Tons CO2e Avoided 38.7% % Reduction





Action Plan E: This plan includes 40 new measures. In addition to most of the measures of Plan D, Plan E replaces the fleet fuel strategy with a more aggressive approach that specifies 99% biodiesel, and adds another 2 MWac PV system. This plan replaces the residential streetlighting measures with a conversion to LED streetlighting systems (or equivalent technology projected to be available by 2012). Plan E pushes the GHG emissions reduction beyond 38% by 2015, and maintains compelling financial metrics. The Internal Rate of Return is over 30% and the Net Present Value exceeds $11M. The annual net cash flow (energy cost savings minus project debt service, replacement costs and associated O&M) turns positive in 2016. The Emissions Trend below illustrates the progress toward the city’s reduction goal.37




Principal

2009 ($31,675) $0 ($31,675) $283,222

2010 $59,053 ($63,530) ($4,477) $1,492,050

2011 $133,313 ($346,425) ($213,113) $1,761,869

2012 $221,144 ($471,436) ($250,293) $3,688,425

2013 $615,992 ($993,723) ($377,731) $3,532,405

2014 $793,205 ($1,148,949) ($355,745) $3,153,653

2015 $978,185 ($1,226,885) ($248,700) $2,051,337

2016 $1,012,572 ($943,990) $68,582 $1,188,375

2017 $1,048,167 ($818,979) $229,188 $416,337

2018 $1,085,012 ($296,692) $788,320 $136,090

2019 $1,093,781 ($141,466) $952,315 $0

2020 $1,024,398 $0 $1,024,398 $0

2021 $1,203,498 $0 $1,203,498 $0

2022 $1,190,071 $0 $1,190,071 $0

2023 $1,289,588 $0 $1,289,588 $0

2024 $1,334,914 $0 $1,334,914 $0

2025 $1,381,832 $0 $1,381,832 $0






y 2 K.Swim Center Solar Thermal Expansion MCAP (Exclusive to #1,7,8,9) 2011 yes


y 4 K.Swim Center Pool Covers Repl. MCAP (Exclusive to #9) 2009 yes




y 12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2011 yes

y 13 Cavn. Cntr Install Cool Roof EEM-8 2011 yes



y 16 Police Facility HVAC Upgrade to 16 SEER and 80% AFUE ABAGEW / HDR EEM-2 2012 yes

y 17 Luchessi Cmty Cntr Replace Gas Pcks w/ High Eff UnitsEEM-9 (Exclusive to #18) 2011 yes









Plan E Measure List


-4,800

-4,000

-3,200

-2,400

-1,600

-800

0

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

CO

2e R

educ

tion

(tons

)

-100%

-80%

-60%

-40%

-20%

0%

Future Actions

Power Content

CA Low CarbonFuel

PV

Fleet

WaterWastewater

Commute

Streetlighting

Building



y 27 Petaluma Aqueduct supplying Zone 4 2012 yes


2009 yes



y 31 Streetlighting B: 50% Conversion HPS to LED (or equiv.) 2013 yes





y 39 Bus Fleet B 2014 yes








y 63 City Hall PV System 50kWac 2012 yes




Plan E Measure List (continued)



Action Plan Evaluations The GHG Emission Reduction Action Plans involve more than CO2e reduction and cash flow. There are critical concerns that should be factored into the decision making process. These include the financial metrics of internal rate of return (IRR) and net present value (NPV) used to evaluate the worthiness of the investment; the cost of implementing the measure, some measures come with a large price tag which will challenge liquidity; the degree to which the plan resolves existing problems, such as old, high maintenance air conditioning units; the visibility of the measures to the public, for example the photovoltaic systems are a physical example of actions taken the City and communicate action and commitment to the community. Other key considerations include the employee impacts of new equipment or procedures, which may generate internal opposition; and the impact on the variability of future energy costs and the associated budgetary vulnerability.


• Measure Capital Cost: • Financial Metrics (IRR and NPV) • Resolution of Existing Problems • GHG Impact • Public Visibility • Employee Impact • Community Impact • Energy Cost Stabilization

The “adjusted measure score” reflects the relative weighting of the evaluation criteria as presented in Table 10 below.

Cost (relative) -3 to 3

Financial Metrics

(relative)

Resolution of Existing Problem

(cumulative) 0 to 6

GHG Impact (cumulative)

Positive Public Visibility

(cumulative)

Employee Impact

(relative)

Community Impact

(relative)

Energy Cost Stabilization (cumulative)

total=24

2 5 2 3 4 2 2 4 24

Table 10: Evaluation Criteria Weighting

The scoring for the plans is derived from the evaluations of each measure included in the plan. Each of the measures received a score for each of the criteria listed above. These measure level evaluations are provided in the appendices.



The table below compiles the scoring for each measure included in each plan and yields a relative score for each criteria. As with the previous table, a higher score indicate more a more favorable evaluation for that criteria. Plan C, for example scores high on “Financial Metrics” but scores relatively low on “Public Visibility”. Plan C scores below Plans D and E overall. The category weighting has been integrated into these numbers as well as an integration factor to allow the aggregation of the relative and comprehensive scoring values.38

Metric \ Plan A B C D E

Cost -13.7 24.8 38.6 42.0 25.1

Financial Metrics -88.6 147.9 145.5 126.7 115.4

Resolution of Existing Problem 4.5 17.4 22.6 22.6 22.6

GHG Impact 47.7 51.9 47.9 60.5 64.4

Public Visibility 81.5 99.6 81.5 125.2 147.9

Employee Impact 2.0 12.0 20.0 18.0 26.0

Community Impact -8.0 -18.0 -4.0 -12.0 -4.0

Energy Cost Stabilization 53.7 78.6 64.4 83.5 94.6

Total 79.2 414.1 416.5 466.6 492.0

Plan Scoring

Table 11: Plan Evaluation Results

This analysis is intended to provide an overview of the effectiveness of each plan as a whole and by each evaluation criteria. While it should encourage a more comprehensive review of the cost/benefits of each strategy, these quantitative results are based on subjective judgments and are advisory only. They should be only one consideration in the selection of the most appropriate plan for the City of Petaluma.

38 A factor of 0.38 was applied to the results of the “cumulative” metrics to equalize the scale of results for the two types of scoring (relative and cumulative).



5.0 Measure Details The tables below provide a complete list of the measures considered in this analysis along with the financial data and results for each. The individual measures are described in the Measure Results section of this report.

No. Measure Name Measure Category

Measure Status Impl. Date Financed

(yes/no)

Power Purchase Agreement

(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings

Annual CO2e Reduction

(metric tons)

Simple Payback

Internal Rate of Return (IRR)

Net Present Value (NPV)

1 K. Swim Center Solar Thermal Repair MCAP Building Future 2010 yes no $124,000 $0 $7,820 45.04 12.8 9.7% $60,020

2 K.Swim Center Solar Thermal Expansion MCAP Building Future 2011 yes no $124,000 $0 $8,094 45.04 15.3 7.8% $42,596

3 K.Swim Center VFD MCAP Building Future 2010 yes no $9,900 $0 $20,348 30.79 0.5 216.2% $394,561

4 K.Swim Center Pool Covers Repl. MCAP Building Future 2009 yes no $8,571 $0 $16,792 100.10 0.5 206.3% $325,218

5K. Swim Cntr Opt. Operation

Pool Pumps and Filtration EEM-1

Building Future 2009 no no $6,956 $0 $13,040 20.83 0.5 197.5% $252,267

6 K. Swim Cnter Premium Efficiency Motors EEM-2 Building Future 2009 yes no $2,734 $0 $4,099 6.55 0.7 158.7% $78,784

7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 Building Future 2012 yes no $80,900 $0 $9,602 51.63 8.4 14.9% $113,601

8 K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 Building Future 2009 yes no $11,197 $0 $2,780 16.57 4.0 29.1% $44,529

9 K. Swim Center Closure 50% Days Building Future 2009 no no $20,000 $0 $49,394 213.83 0.4 259.1% $961,621

10 Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 Building Future 2009 no no $4,719 $0 $1,324 2.12 3.6 32.5% $21,793

11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 Building Future 2010 yes no $672 $0 $45 0.07 15.1 8.0% $245

12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 Building Future 2011 yes no $4,320 $0 $532 2.96 8.1 15.4% $6,451

13 Cavn. Cntr Install Cool Roof EEM-8 Building Future 2011 yes no $6,139 $0 $992 1.42 6.2 19.8% $13,840

14 City Hall, Com Cntr, Police Dept. SBEA Lighting Measures Building completed 2006 yes no $43,961 $0 $16,661 30.10 2.6 NA NA

15 Police Facility Energy Management System MCAP Building Future 2010 yes no $38,386 $0 $2,838 7.50 13.5 9.1% $19,785

16 Police Facility HVAC Upgrade ABAGEW / HDR EEM-2 Building Future 2012 yes no $104,959 $0 $5,527 8.93 19.0 5.8% $9,765

17 Luchessi Cmty Cntr HVAC Upgrade EEM-9 Building Future 2011 yes no $156,970 $0 $9,426 14.38 16.7 7.0% $37,651

18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 Building Future 2011 yes no $7,203 $0 $1,077 1.54 6.7 18.4% $14,520

19 Animal Shelter Lighting Retrofit ABAG EW Building Future 2009 yes no $2,409 $0 $583 0.93 4.1 28.4% $9,275

20 Corporation Yard Lighting Retrofit ABAG EW Building Future 2009 yes no $3,450 $0 $1,293 2.07 2.7 42.3% $22,378

21 Cavn. Cntr Lighting Retrofit ABAG EW Building Future 2009 yes no $4,156 $0 $934 1.49 4.5 26.6% $14,576

22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW Building Future 2009 yes no $845 $0 $631 1.01 1.3 80.8% $11,727

23 Senior Center Lighting Retrofit ABAG EW Building Future 2009 yes no $2,518 $0 $1,059 1.69 2.4 47.0% $18,636

24 Airport Lighting Retrofit ABAG EW Building Future 2009 yes no $7,420 $0 $2,063 3.30 3.6 32.2% $33,897

25 Vending Machine Controls Building Future 2009 yes no $2,548 $0 $5,259 8.40 0.5 217.1% $101,979

26 Retrofit Frates Pumps (Zone 4) Water Wastewater Future 2010 yes no $13,842 $0 $3,597 5.44 3.8 30.3% $58,234

Table 12: Results by Measure (1-26)





(yes/no)


(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


(metric tons)

Simple Payback



27 Petaluma Aqueduct supplying Zone 4

Water Wastewater Future 2012 yes no $195,368 $0 $15,413 20.89 12.7 9.8% $119,951

28 SolarBeeTM (unless new facility removes need)

Water Wastewater Future 2009 yes no $94,257 $0 $40,897 65.33 2.3 48.4% $722,199

29 Grease to Gas Methane Program

Water Wastewater Future 2011 yes no $265,880 $0 $102,723 571.65 2.6 43.5% $1,786,245

30Streetlighting A: 50%

Conversion HPS to LED (or equiv.)

Streetlighting Future 2012 yes no $692,010 ($132,212) $34,741 47.08 4.1 28.4% $2,655,649

31Streetlighting B: 50%


Streetlighting Future 2013 yes no $692,010 ($132,212) $35,957 46.09 4.1 28.5% $2,679,791

32Streetlighting C: Turn off 50% of

Residential (non intersection) lighting

Streetlighting Future 2010 no no $67,020 $0 $108,899 164.76 0.6 171.7% $2,098,255

33Streetlighting D: Turn off 50% of

Residential (non intersection) lighting

Streetlighting Future 2012 no no $67,020 $0 $116,655 158.10 0.6 183.7% $2,252,250

34 Commute 1 Commute Future 2010 no no $0 $22,500 $0 75.53 0.0 NA ($446,717)

35 Commute 2 Commute Future 2011 no no $0 $32,500 $0 75.53 0.0 NA ($645,257)

36 4 day work week (Commute) Commute Future 2009 no no $0 $0 $0 32.26 NA NA $0

37 4 day work week (Building) Building Future 2009 no no $20,000 $0 $26,007 63.66 0.8 138.1% $497,298

38 Bus Fleet A Fleet Future 2014 yes no $271,593 $0 $261,835 244.93 1.0 103.3% $4,939,834

39 Bus Fleet B Fleet Future 2014 yes no $630,667 $0 $151,760 259.12 4.2 28.3% $2,412,429

40 Fleet Replacement Strategy A (includes Nissan Elec) Fleet Future 2010 yes no $730,000 $0 $168,301 490.96 4.3 27.2% $2,646,226

41 Fleet Replacement Strategy B (includes Nissan Elec) Fleet Future 2012 yes no $994,000 $0 $207,179 531.43 4.8 24.9% $3,166,685

42Electric Vehicles (Nissan 28 Vehicles Excl to other Fleet

Measures)Fleet Future 2010 yes no $130,000 $0 $5,351 21.70 24.3 3.7% ($17,580)

43 Biodiesel 20% Fleet Future 2009 yes no $0 $0 ($1,646) 39.02 0.0 NA ($32,671)

44 Biodiesel 50% Fleet Future 2010 yes no $50,000 $0 ($4,435) 97.55 -11.3 NA ($135,670)

45 Biodiesel 99% Fleet Future 2010 yes no $50,000 $0 ($8,781) 193.15 -5.7 NA ($221,960)

46 Biodiesel 20% linked to Fleet A Fleet Future 2009 yes no $0 $0 ($3,046) 72.22 0.0 NA ($60,467)

47 Biodiesel 20% linked to Fleet B Fleet Future 2009 yes no $0 $0 ($2,736) 64.87 0.0 NA ($54,314)

48 Biodiesel 50% linked to Fleet A Building Future 2010 no no $60,500 $0 ($8,208) 180.54 -7.4 NA ($220,585)

49 Biodiesel 50% linked to Fleet B Building Future 2010 no no $59,000 $0 ($7,373) 162.17 -8.0 NA ($202,571)

50 Biodiesel 99% linked to Fleet A Building Future 2010 no no $60,500 $0 ($16,252) 357.48 -3.7 NA ($380,291)

51 Biodiesel 99% linked to Fleet B Building Future 2010 no no $59,000 $0 ($14,598) 321.10 -4.0 NA ($346,025)

52 Fleet Management Software Linked to Fleet Replacement A Fleet Future 2010 yes no $300,000 ($20,000) $11,500 33.61 9.5 13.2% $339,684

Table 13: Results by Measure (27-52)





(yes/no)


(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


(metric tons)

Simple Payback



53 Fleet Management Software Linked to Fleet Replacement B Fleet Future 2010 yes no $300,000 ($20,000) $10,575 30.90 9.8 12.8% $321,318

54 PV 1.0 MWac (PPA) PV Future 2011 no yes $50,000 $0 ($13,424) 284.51 -3.7 NA ($167,375)

55 PV 2 MWac (PPA) PV Future 2013 no yes $50,000 $0 ($26,847) 545.54 -1.9 NA ($334,751)

56 PV 1.0 MWac (PPA) PV Future 2012 no yes $50,000 $0 ($13,424) 278.64 -3.7 NA ($167,375)

57 PV .5 MWac (PPA) PV Future 2012 no yes $50,000 $0 ($6,712) 139.32 -7.4 NA ($83,688)

58 PV .5 MWac PV Future 2013 yes no $4,002,843 $10,000 $106,399 136.39 41.5 NA ($2,532,377)

59 PV 1.0 MWac PV Future 2009 yes no $8,002,843 $20,000 $185,441 296.25 48.4 NA ($5,605,190)

60 PV 2.0 MWac PV Future 2014 yes no $16,002,843 $40,000 $440,491 533.80 40.0 -2.7% ($9,825,642)

61 Community Center 41 kWac PV MCAP PV Future 2010 yes no $272,903 $822 $7,888 11.93 38.6 NA ($171,731)

62 K.Swim Center 80 kWac PV System MCAP PV Future 2010 yes no $625,468 $1,557 $14,938 22.60 46.7 NA ($428,709)

63 City Hall PV System 50kWac PV Future 2012 yes no $342,060 $959 $9,858 13.36 38.4 -2.8% ($209,894)

64 Public Works PV System 25.3 kWac PV Future 2009 yes no $157,047 $505 $4,686 7.49 37.6 NA ($98,612)

65 Efficiency Coordinator (.5FTE) Building Future 2010 no no $0 $30,000 $0 0.00 0.0 NA ($595,622)

66 Efficiency Coordinator (.5FTE) Building Future 2012 no no $0 $30,000 $0 0.00 0.0 NA ($595,622)

67 Swim Center Pay-per-use Showers MCAP (not quantified) Building Future NA NA NA NA NA NA NA NA NA NA

68 City Hall HVAC Upgrade MCAP (not quantified) Building Future NA NA NA NA NA NA NA NA NA NA

69City Hall Council Chambers HVAC Upgrade MCAP (not

Quantified)Building Future NA NA NA NA NA NA NA NA NA NA

70

City Hall HVAC Upgrades West Wing Chiller, East Wing

Package units MCAP (not Quantified)

Building Future NA NA NA NA NA NA NA NA NA NA

71City Hall HVAC Motion/

Occupancy Sensors for Lighting MCAP (not Quantified)


72 City Hall Daylighting MCAP (not quantified) Building Future NA NA NA NA NA NA NA NA NA NA

73Community Center Energy

Management System ABAG EW/HDR (not quantified)


74Community Center Lighting

Design and Controls MCAP (not quantified)


75Cavanaugh Complex Variable Frequency Drives MCAP (not

quantified)Building Future NA NA NA NA NA NA NA NA NA NA

76 WasteWater Treatment Plant Water Wastewater Future NA NA NA NA NA NA NA NA NA NA

77 Reclaimed Water Initiatives Water Wastewater Future NA NA NA NA NA NA NA NA NA NA

Table 14: Results by Measure (53 – 77)



Measure Selection Each Plan is comprised of measures from the tables above. The makeup of each plan is provided in the table below. A “y” in the column under the Action Plan (A –E) in the first five columns indicates that the measure is included in that plan. Action Plan A contains 10 new measure and one completed measure. Action Plan E is comprised of 40 individual new measures.

A B C D E

n n y n n 1 K. Swim Center Solar Thermal Repair MCAP (Exclusive to #2,7,8,9) 2010 yes

n n n n y 2 K.Swim Center Solar Thermal Expansion MCAP (Exclusive to #1,7,8,9) 2011 yes

n n y y y 3 K.Swim Center VFD MCAP (Exclusive to 9) 2010 yes

n n y n y 4 K.Swim Center Pool Covers Repl. MCAP (Exclusive to 9) 2009 yes

n n y y y 5 K. Swim Cntr Opt. Operation Pool Pumps and Filtration EEM-1 (Exclusive to #6,9) 2009 no

n n n n n 6 K. Swim Cnter Premium Efficiency Motors EEM-2 (Exclusive to #5, 9) 2009 yes

n n n y n 7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 (Exclusive to #4 and 8, 9) 2012 yes

n n n n n 8 K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 (Exclusive to #1,2,7,9) 2009 yes

n y n n n 9 K. Swim Center Closure 50% Days (exclusive to other K.Swim pool measures) 2009 no

n y y y y 10 Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 2009 no

n y n y y 11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 (Matched to #10) 2010 yes

n n n n y 12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2011 yes

n n n y y 13 Cavn. Cntr Install Cool Roof EEM-8 2011 yes

y y y y y 14 City Hall, Com Cntr, Police Dept. SBEA Lighting Measures 2006 yes

n y y y y 15 Police Facility Energy Management System MCAP 2010 yes

n y n n y 16 Police Facility HVAC Upgrade to 16 SEER and 80% AFUE ABAGEW / HDR EEM-2 2012 yes

n y n n y 17 Luchessi Cmty Cntr Replace Gas Pcks w/ High Eff UnitsEEM-9 (Exclusive to #18) 2011 yes

n n n y n 18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 (Exclusive to #17) 2011 yes

n y y y y 19 Animal Shelter Lighting Retrofit ABAG EW 2009 yes

n y y y y 20 Corporation Yard Lighting Retrofit ABAG EW 2009 yes

n y y y y 21 Cavn. Cntr Lighting Retrofit ABAG EW 2009 yes

n y y y y 22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2009 yes

n y y y y 23 Senior Center Lighting Retrofit ABAG EW 2009 yes

n y y y y 24 Airport Lighting Retrofit ABAG EW 2009 yes

n y y y y 25 Vending Machine Controls 2009 yes

Financed (yes/no)


Date

Table 15: Measures 1 – 25



A B C D E

n y y y y 26 Retrofit Frates Pumps (Zone 4) 2010 yes

n n n n y 27 Petaluma Aqueduct supplying Zone 4 2012 yes

n y n y y 28 SolarBeeTM (unless new facility removes need) 2009 yes

n n y y y 29 Grease to Gas Methane Program 2011 yes

n y y n y 30 Streetlighting A: 50% Conversion HPS to LED (or equiv.) 2012 yes

n n n n y 31 Streetlighting B: 50% Conversion HPS to LED (or equiv.) 2013 yes

n y n y n 32 Streetlighting C: Turn off 50% of Residential lighting (non intersection) 2010 no

n n n y n 33 Streetlighting D: Turn off 50% of Residential lighting (non intersection) 2012 no

n y y y y 34 Commute 1 2010 no

n n n y y 35 Commute 2 2011 no

y y y y y 36 4 day work week (Commute) 2009 no

y y y y y 37 4 day work week (Building) 2009 no

n n y y n 38 Bus Fleet A 2014 yes

n y n n y 39 Bus Fleet B 2014 yes

n n y n n 40 Fleet Replacement Strategy A (includes Nissan Elec) 2010 yes

n y n y y 41 Fleet Replacement Strategy B (includes Nissan Elec) 2012 yes

y n n n n 42 Nissan Electric Vehicles (Exclusive to other Fleet Measures) 2010 yes




n n n n n 46 Biodiesel 20% linked to Fleet A 2009 yes

n n n n n 47 Biodiesel 20% linked to Fleet B 2009 yes

n n y n n 48 Biodiesel 50% linked to Fleet A 2010 no

n y n y n 49 Biodiesel 50% linked to Fleet B 2010 no

n n n n n 50 Biodiesel 99% linked to Fleet A 2010 no

Financed (yes/no)


Date




A B C D E

n n n n y 51 Biodiesel 99% linked to Fleet B 2010 no

n n y n n 52 Fleet Management Software Linked to Fleet Replacement A 2010 yes

n y n y y 53 Fleet Management Software Linked to Fleet Replacement B 2010 yes

y n y y y 54 PV 1.0 MWac (PPA) 2011 no

y y n n y 55 PV 2.0 MWac (PPA) 2013 no

y n n n n 56 PV 1.0 MWac (PPA) 2012 no

y n n n n 57 PV .5 MWac (PPA) 2012 no

y n n n n 58 PV .5 MWac 2013 yes



n n y y y 61 Community Center 41 kWac PV MCAP 2010 yes

n y n y y 62 K.Swim Center 80 kWac PV System MCAP 2010 yes

n n n y y 63 City Hall PV System 50kWac 2012 yes

n y y y y 64 Public Works PV System 25.3 kWac 2009 yes

n y y y y 65 Efficiency Coordinator (.5FTE) 2010 no

n n n y y 66 Efficiency Coordinator (.5FTE) 2012 no

Financed (yes/no)


Date

Table 17: Measures 51 – 66

A B C D E

n n n n n 67 Swim Center Pay-per-use Showers MCAP (not quantified) NA NA

n n n n n 68 City Hall HVAC Upgrade MCAP (not quantified) NA NA

n n n n n 69 City Hall Council Chambers HVAC Upgrade MCAP (not quantified) NA NA

n n n n n 70 City Hall HVAC Upgrades West Wing Chiller, East Wing Package units MCAP (not Quantified) NA NA

n n n n n 71 City Hall HVAC Motion/ Occupancy Sensors for Lighting MCAP (not Quantified) NA NA

n n n n n 72 City Hall Daylighting MCAP (not quantified) NA NA

n n n n n 73 Community Center Energy Management System ABAG EW/HDR (not quantified) NA NA

n n n n n 74 Community Center Lighting Design and Controls MCAP (not quantified) NA NA

n n n n n 75 Cavanaugh Complex Variable Frequency Drives MCAP (not quantified) NA NA

n n n n n 76 WasteWater Treatment Plant NA NA

n n n n n 77 Reclaimed Water Initiatives NA NA

Financed (yes/no)


Date

Table 18: Measures 67 – 77 (Not quantified)



Measures Results The measures considered for inclusion in the plans are described below. Each measure includes a table indicating which Action Plans include that measure. For example, Measure 4 K.Swim Center Pool Covers is included in Plans C, and E as indicated by “y” under each plan (“n” indicating not included in the plan).

A B C D E

n n y n y

Action Plan

The description of each measure also includes a table listing the results of the measure: the cost of implementation, the annual savings, the GHG impact and the financial metrics of Simple Payback, Internal Rate of Return (IRR) and Net Present Value (NPV). Again using Measure 4 as an example:

No. Measure Name Impl. Date Financed (yes/no)

Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings

Annual CO2 Reduction

Simple Payback



4 K.Swim Center Pool Covers Repl. MCAP (Excl to 16) 2009 yes no $8,571 $0 $16,792 100.10 0.5 206.3% $325,218

Finally, each measure description includes the Selection Evaluation table to enable a comprehensive appraisal and relational comparison of the benefits of each opportunity. The measure is scored for each evaluation metric. This score is totaled under “Measure Score”. This measure score is modified by the metric weighting and results in the “Adjusted Measure Score”. The complete table of measure evaluations is provided in the appendices.

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)


Measure Score Adjusted Measure Score

K.Swim Center Pool Covers Repl. MCAP 2.5 3.0 0.00 2.9 3.0 0.0 0.0 2.0 13.32 48.44

The metric weighting below is applied to each measure scoring.

Cost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)


total=24

2 5 2 3 4 2 2 4 24

The measures considered in this analysis are listed in the following pages, with a brief description of each. The background information for many of the measures is provided in the Appendices.



A B C D E

n n y n n

Action Plan 1-Kenilworth Swim Center Solar Thermal System Repair

Measure Name Impl. Date Financed (yes/no)

Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



K. Swim Center Solar Thermal Repair MCAP 2010 yes no $124,000 $0 $7,820 45.04 12.8 9.7% $60,020

This measure addresses the repair of the inactive 50 panel solar hot water system for the swim center. The project was included in the Building Energy Efficiency Draft Report completed in November 200839.

The resurrection of the old solar thermal arrays will be a sound investment, especially since the plumbing is already in place.40

Completed Measures

Date Implemented

Savings $/Year

SavingskWh/yr

GHG Reduction Description / Status / Cost

50 panel Solar Thermal 1990 n/a n/a n/a System non functional: completely dismantledProposed Measures

Repair Solar Thermal $10,220 7,300

therms 45 tons

Replace missing panels. Install all racks at 10’ above ground to create shade structures and increase security. Estimated cost: $100,000 rehab

Expand Solar Thermal $10,220 7,300

Therm 45 tons Add 50 more solar thermal 4x8 panels in samefashion as measure above. Estimated cost: $124,000

80 kW Photovoltaic System $12,233 138,600 50 tons 70 kW ground mount, 10 kW roof mount specified by SPG Solar Proposal. Estimated cost: $438,000

Variable frequency drives (VFD) $16,500 131,000 48 tons Pool pump motors regulators, 0.6 yr payback

Other Opportunities Lighting upgrades Lighting retrofit throughout. Boiler upgrade $15,400 11,000 67 tons Economizers and high efficiency replacementPay-per-use showers Reduces wasteful hot water use in locker room

Pool Cover Reduces heat loss at night. Old ones “saturateand beyond serviceability.

Table of Measures Specified in the Building Energy Efficiency Draft Report41

Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Center Solar Thermal Repair MCAP (Excl to #2,7,8,16) -3.0 0.7 2.00 6.0 0.00 -1.00 0.00 0.0 4.73 17.64

39 Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008. 40 Ibid. 41 Ibid.



A B C D E

n n n n y

Action Plan 2-Kenilworth Swim Center Solar Thermal System Expansion


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



2 K.Swim Center Solar Thermal Expansion MCAP 2011 yes no $124,000 $0 $8,094 45.04 15.3 7.8% $42,596

Expansion of the solar hot water system is also an option detailed in the Building Energy Efficiency Draft Report.42

The expanded system could be installed on raised racks to serve a dual purpose of added security against panel vandalism/theft, and add much needed shade structures with extended grass areas underneath.43

Completed Measures

Date Implemented

Savings $/Year

SavingskWh/yr




therms 45 tons










Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K.Swim Center Solar Thermal Expansion MCAP -3.0 0.6 2.00 6.0 1.00 2.00 0.00 0.9 9.53 30.71

42 Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008. 43 Ibid. 44 Ibid.



A B C D E

n n y y y

Action Plan 3-Kenilworth Swim Center Pool Pump Variable Frequency Drives


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



3 K.Swim Center VFD MCAP 2010 yes no $9,900 $0 $20,348 30.79 0.5 216.2% $394,561

There are several measures available to reduce the energy consumption of the pools. These include limiting the filtration pumping to meet public health regulatory requirements and adding VFDs on the pumps.

The most lucrative investment is in variable frequency drives (VFD) for the circulation pumps. An ABAG Energy Watch audit of the Finley Aquatic Center, in Santa Rosa, specified a payback of 0.6 years for a similar sized retrofit.45

Completed Measures

Date Implemented

Savings $/Year

SavingskWh/yr




therms 45 tons










Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K.Swim Center VFD MCAP 2.4 3.0 0.00 4.4 0.0 0.0 0.0 2.4 12.21 42.59

45 Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008. 46 Ibid.



A B C D E

n n y n y

Action Plan 4-Kenilworth Swim Center Pool Cover Replacement


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



4 K.Swim Center Pool Covers Repl. MCAP 2009 yes no $8,571 $0 $16,792 100.10 0.5 206.3% $325,218

Pools lose heat energy in a variety of ways, but evaporation is by far the largest source of energy loss for swimming pools. When compared to evaporation, all other losses are small. The reason evaporation has such an impact is that evaporating water requires large amounts of energy. Evaporation is approximately 70% of the heat loss from a pool. Pool covers will reduce energy consumption by 40 to 60%, reduce make-up water by 30-50% and reduce the pool’s chemical consumption by 35-60%. The report referenced in the table below includes replacement of the pool covers:

Pool covers Reduce heat loss at night. The old ones are “saturated” and are beyond serviceability.47

Completed Measures

Date Implemented

Savings $/Year

SavingskWh/yr


50 panel Solar Thermal 1990 n/a n/a n/a System non functional: completely dismantlProposed Measures


therms 45 tons

Replace missing panels. Install all racks at 10’ above ground to create shadestructures and increase security. Estimated cost: $100,000 rehab


Therm 45 tons Add 50 more solar thermal 4x8 panels in samfashion as measure above. Estimated cost: $124,000

80 kW Photovoltaic Syste $12,233 138,600 50 tons 70 kW ground mount, 10 kW roof mount specified by SPG Solar Proposal. Estimated cost: $438,000

Variable frequency drives (VFD) $16,500 131,000 48 tons Pool pump motors regulators, 0.6 yr paybac

Other Opportunities Lighting upgrades Lighting retrofit throughout. Boiler upgrade $15,400 11,000 67 tons Economizers and high efficiency replacemePay-per-use showers Reduces wasteful hot water use in locker ro

Pool Cover Reduces heat loss at night. Old ones “saturaand beyond serviceability.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K.Swim Center Pool Covers Repl. MCAP 2.5 3.0 0.00 2.9 3.0 0.0 0.0 2.0 13.32 48.44




A B C D E

n n y y y

Action Plan

5-Kenilworth Swim Center Pool Pump and Filter Optimization


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



5K. Swim Cntr Opt. Operation

Pool Pumps and Filtration EEM-1

2009 no no $6,956 $0 $13,040 20.83 0.5 197.5% $252,267

The Swim Center pool pumps operation can be optimized to reduce energy consumption and still meet the health and operation requirements. The full text of the recommendation is provided in the appendices.

The circulation pump runs continuously at full speed for 24 hours a day, 365 days a year even though the pools are in use from March through October during the hours from about 5:00 a.m. to roughly 9:00 p.m. It is possible to reduce the flow rates during non-peak use and unoccupied hours and still maintain water quality and clarity.49

Completed Measures

Date Implemented

Savings $/Year

SavingskWh/yr




therms 45 tons










Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Cntr Opt. Operation Pool Pumps and Filtration EEM-1 2.6 3.0 1.00 0.6 0.0 1.0 0.0 1.5 9.70 32.04




A B C D E

n n n n n

Action Plan

EEM DescriptionDemand Savings

(kW)

Annual Electricity Savings (kWh)

Annual Natural

Gas Savings (therms)

Annual Cost

Savings ($)

Estimated Installed Cost ($)

Simple Payback

(yrs)

Title 24 Applicable?

Kenilworth Swim Center

EEM-1 Optimize Operation of Pool Filtration/Circulation Pump 5.3 86,888 $10,479 $6,956 0.7 N

EEM-2 Replace Pump Motors with Premium Efficiency Motors 3.1 27,315 $3,294 $2,734 0.8 Y

EEM-3 Replace Pool Heating Boilers with High Efficiency Boilers 8,368 $8,730 $80,900 9.3 Y

EEM-4 Install New Solar Pool Heating System 2,686 $3,374 $13,346 4.0 NCavanagh Center

EEM-5 Optimize Operation of Pool Filtration/Circulation Pumps 0.5 8,822 $1,538 $5,161 3.4 N

EEM-6 Replace Pump Motors with Premium Efficiency Motors 0.1 883 $154 $686 4.5 Y

EEM-7 Install New Solar Pool Heating System 480 $603 $4,704 7.8 NEEM-8 Install Cool Roof 6.5 6,168 $979 $47,718 48.7 NLuchessi Community Center

EEM-9 Replace Existing Gas Packs with New High-Efficiency Units 19.8 57,309 192 $8,800 $159,989 18.2 Y

EEM-10 Install Cool Roof 2.1 1,969 $295 $15,235 51.7 NTOTAL 37.4 189,355 11,726 $38,246 $337,428 8.8

Summary of Energy Efficiency MeasuresTable 1

6- Kenilworth Swim Center Premium Efficiency Motors


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



6 K. Swim Cnter Premium Efficiency Motors EEM-2 2009 yes no $2,734 $0 $4,099 6.55 0.7 158.7% $78,784

The upgrade to more efficiency pool pump motors was included in the recommendations in the referenced report.

EEM-2: Replace Existing Pool Pump Motors with Premium Efficiency Motors

The motors for the circulation and gutter surge tank pumps have efficiencies far lower than premium efficiency levels. Both motors are at or very near the end of their useful service life.

We recommend replacing these motors with premium efficiency motors.51


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Cnter Premium Efficiency Motors EEM-2 2.8 3.0 0.00 0.2 0.0 0.0 0.0 0.5 6.50 23.15

51 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008.



A B C D E

n n n y n

Action Plan 7-Kenilworth Swim Center High Efficiency Condensing Boilers


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 2012 yes no $80,900 $0 $9,602 51.63 8.4 14.9% $113,601

Energy efficiency rebates can be applied to address the aging boilers for the Swim Center reducing maintenance concerns and significantly reducing energy costs.52 The summary tables are available in the appendices.

EEM-3: Replace Pool Heating Boilers with High Efficiency Condensing Boilers

The two natural gas boilers for heating the swimming pools are old and inefficient, and have estimated thermal efficiencies of 76%. Additionally, the boiler for the smaller pool is estimated to be grossly oversized.

We recommend replacing the boiler for the larger pool with a condensing boiler of similar capacity and a much higher thermal efficiency. We also recommend replacing the boiler for the smaller pool with a smaller condensing boiler with a much higher thermal efficiency.53


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Cnter High Eff. Condensing Boilers EEM-3 -1.9 1.1 0.00 1.5 6.0 0.0 0.0 1.1 7.87 34.81

52 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008 53 Ibid.



A B C D E

n n n n n

Action Plan

8- Kenilworth Swim Center Supplemental Solar Water Heating


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



8 K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 2009 yes no $11,197 $0 $2,780 16.57 4.0 29.1% $44,529

The referenced report includes an expanded solar thermal system to provide hot water and significantly reduce energy consumption.54 The summary tables are available in the appendices.

EEM-4: Install Solar Thermal Hot Water System to Supplement Pool Heating NOTE – this recommendation is proposed as an alternative to EEM-3 The pools are currently heated by natural gas-fired boilers. The facility had a solar thermal system in the past to supplement pool heating. The system is decommissioned at the present time. We recommend installing a new solar pool heating system with flat-plate collectors, and integrating it with the existing pool heating systems. The solar heating system would meet a portion of the pool heating load; the rest would be met by the existing pool heating systems. This would result in natural gas savings.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 (Excl to #1,2,7,16) 2.3 2.2 0.00 0.5 0.0 0.0 0.0 0.3 5.31 18.29

54 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008



A B C D E

n y n n n

Action Plan

9-Kenilworth Swim Center Closure for Half of the Year


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



9 K. Swim Center Closure 50% Days 2009 no no $20,000 $0 $49,394 213.83 0.4 259.1% $961,621

The closure of the Kenilworth Swim Center for 50% of its current operating schedule would save roughly 123,000 kWh and 29,872 based on the utility billing data for that facility assuming energy consumption is reduced by 50% due to the reduced schedule. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K. Swim Center Closure 50% Days 1.8 3.0 0.00 6.0 3.00 -3.00 -3.00 5.8 13.55 59.61



A B C D E

n y y y y

Action Plan 10- Cavanaugh Swim Center Pool Pump and Filter Optimization


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



10Cavn. Cntr Opt. Operation Pool Pumps and Filtration

EEM-52009 no no $4,719 $0 $1,324 2.12 3.6 32.5% $21,793

The referenced report includes pool recommendations similar to those specified for the Kenilworth Swim Center.55

EEM-5: Optimize Operation of Pool Filtration/Circulation Pumps The two circulation pumps run continuously at full speed for 24 hours a day, 365 days a year even though the pool is in use from April through October during the hours from 7:00 a.m. to roughly 8:00 p.m. It is possible to reduce the flow rates during non-peak use and unoccupied hours and still maintain water quality and clarity.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 2.7 2.4 1.00 0.1 0.0 1.0 0.0 0.2 7.37 22.41




A B C D E

n y n y y

Action Plan 11- Cavanaugh Swim Center Premium Efficiency Pool Pumps


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 2010 yes no $672 $0 $45 0.07 15.1 8.0% $245

This measure is applied subsequent to measure 10 (operation optimization) which reduces the projected energy savings. The financial calculations are based on $.145/kWh (rather than the $.17/kWh in the referenced report), and the utility incentive is assumed to be the minimum $.05/kWh saved (the revised incentive levels for the 2009-2011 program are not currently available).56 The summary tables are available in the appendices.

EEM-6: Replace Existing Pool Pump Motors with Premium Efficiency Motors The motors for the circulation pumps have efficiencies far lower than premium efficiency levels. It is estimated that the motors have about five years of useful service life left. We recommend replacing these motors with premium efficiency motors.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 3.0 0.6 0.00 0.0 0.0 0.0 0.0 0.0 3.57 8.94




A B C D E

n n n n y

Action Plan 12- Cavanaugh Swim Center Supplemental Solar Water Heating


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2011 yes no $4,320 $0 $532 2.96 8.1 15.4% $6,451

The referenced report includes solar water heating recommendations similar to those specified for the Kenilworth Swim Center.57 The summary tables are available in the appendices.

EEM-7: Install Solar Thermal Hot Water System to Supplement Pool Heating The pool is currently heated by a natural gas-fired boiler. The facility had a solar thermal system in the past to supplement pool heating. The system is decommissioned at the present time. We recommend installing a new solar pool heating system with flat-plate collectors, and integrating it with the existing pool heating system. The solar heating system would meet a portion of the pool heating load; the rest would be met by the existing pool heating system. This would result in natural gas savings.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2.7 1.2 0.00 0.1 6.0 0.0 0.0 0.1 10.04 35.77




A B C D E

n n n y y

Action Plan 13- Cavanaugh Swim Center Cool Roof


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



13 Cavn. Cntr Install Cool Roof EEM-8 2011 yes no $6,139 $0 $992 1.42 6.2 19.8% $13,840

The Cool Roof measure will reduce the energy needed to cool the facility by using light colored materials on the roof that reflect the sun, and reduce the heat transferred to the building. Incentive funding for this measure is available through the CPUC58 funded efficiency programs implemented by PG&E. The measure is included in the HDR efficiency report which provides the description and summary table below.59 The costs are based on the incremental cost of including the cool roof membrane when the roof undergoes replacement.

EEM-8: Install Cool Roof The roofs of the gymnasium and the club are in very poor shape and are in need of immediate replacement.

The summary tables are available in the appendices. Details of the measure and calculations are available in the HDR report.60 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Cavn. Cntr Install Cool Roof EEM-8 2.6 1.5 0.00 0.0 0.0 0.0 0.0 0.1 4.27 13.27

58 California Public Utilities Commission 59 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008 60 Ibid



A B C D E

y y y y y

Action Plan 14-Building Lighting Retrofits for City Hall, Community Center and the Police Facility


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



14City Hall, Com Cntr, Police

Dept. SBEA Lighting Measures

2006 yes no $43,961 $0 $16,661 30.10 2.6 NA NA

These lighting retrofits were completed by the Small Business Energy Alliance (SBEA) in 2006. The associated energy savings are included in this analysis. The associated costs and benefits are not included as the financial results are intended to reflect the results of future actions.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



City Hall, Com Cntr, Police Dept. SBEA Lighting Measures 0.4 0.0 2.00 0.9 0.0 0.0 0.0 1.9 5.17 15.09



A B C D E

n y y y y

Action Plan 15-Police Facility Energy Management System


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



15 Police Facility Energy Management System MCAP 2010 yes no $38,386 $0 $2,838 7.50 13.5 9.1% $19,785

In 2005, the building was audited and an HVAC Energy Efficiency Study was prepared by HDR/ Brown, Vence and Associates and presented to the City by LGEP. The figures in the table below for the energy management system and the HVAC upgrade come from this report.61

Completed Date Savings Savings GHG

Measures Implemented $/Year kWh/yr Reduction

Lighting retrofit 2007 T-8 retrofit

Proposed Measures

Energy Management System 13,408 kWh Install EMS for building controls.

(EMS) 705 therms Total cost: $38,386

31,063 kWh Full HVAC upgrade to 16 SEER, 80% AFUE

312 therms Gas-electric units. Total cost: $94,667

Description / Status/ Cost

-2005 $3,489 9 tons

Full HVAC Upgrade -2005 $4,764 13 tons


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Police Facility Energy Management System MCAP 0.7 0.7 0.00 0.2 0.0 0.0 0.0 0.3 1.93 6.78

61 Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008.



A B C D E

n y n n y

Action Plan 16-Police Facility HVAC Upgrade


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



16 Police Facility HVAC Upgrade ABAGEW / HDR EEM-2 2012 yes no $104,959 $0 $5,527 8.93 19.0 5.8% $9,765

In 2005, the building was audited and an HVAC Energy Efficiency Study was prepared by HDR/ Brown, Vence and Associates and presented to the City by LGEP. The figures in the table below for the energy management system and the HVAC upgrade come from this report.62

Completed Date Savings Savings GHG

Measures Implemented $/Year kWh/yr Reduction

Lighting retrofit 2007 T-8 retrofit

Proposed Measures

Energy Management System 13,408 kWh Install EMS for building controls.

(EMS) 705 therms Total cost: $38,386

31,063 kWh Full HVAC upgrade to 16 SEER, 80% AFUE

312 therms Gas-electric units. Total cost: $94,667

Description / Status/ Cost

-2005 $3,489 9 tons

Full HVAC Upgrade -2005 $4,764 13 tons


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Police Facility HVAC Upgrade ABAGEW / HDR EEM-2 -3.0 0.4 0.00 0.3 3.00 0.00 0.00 0.6 1.34 11.53




A B C D E

n y n n y

Action Plan 17-Luchessi Community Center HVAC Upgrade


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



17 Luchessi Cmty Cntr HVAC Upgrade EEM-9 2011 yes no $156,970 $0 $9,426 14.38 16.7 7.0% $37,651

In 2005, the building was audited and an HVAC Energy Efficiency Study was prepared by HDR/ Brown, Vence and Associates and presented to the City by LGEP. The summary table is provided in the appendices. The financial calculations are based on the full cost of the upgrade (rather than the incremental cost of choosing the higher efficient model). The utility incentive is assumed to be the minimum $.05/kWh and $.80/Therm saved (the revised incentive levels for the 2009-2011 program are not currently available). The summary tables are available in the appendices.

EEM-9: Replace Existing Gas Packs with New High-Efficiency Units The building has fifteen roof-top gas packs with direct expansion (DX) cooling and natural gas furnace for heating. The units range in size from 3 to 15 tons, and were installed at the time the building was commissioned. They have come to the end of their useful service life. We recommend replacing these gas packs with new units with higher cooling and heating efficiencies.63


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Luchessi Cmty Cntr HVAC Upgrade EEM-9 (Excl to 18) -3.0 0.5 0.00 0.4 0.00 0.00 0.00 1.1 -0.96 2.27




A B C D E

n n n y n

Action Plan 18- Luchessi Community Center Cool Roof


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 2011 yes no $7,203 $0 $1,077 1.54 6.7 18.4% $14,520

The Cool Roof measure will reduce the energy needed to cool the facility by using light colored materials on the roof that reflect the sun, and reduce the heat transferred to the building. Incentive funding for this measure is available through the CPUC64 funded efficiency programs implemented by PG&E. The measure is included in the HDR efficiency report which provides the description and summary table (available in the appendices).65 The costs are based on the incremental cost of including the cool roof membrane when the roof undergoes replacement.

EEM-8: Install Cool Roof The roofs of the gymnasium and the club are in very poor shape and are in need of immediate replacement.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Luchessi Cmnty Cntr Install Cool Roof EEM-10 (Excl to 17) 2.6 1.4 0.00 0.0 0.00 0.00 0.00 0.1 4.12 12.69

64 California Public Utilities Commission 65 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008



A B C D E

n y y y y

Action Plan 19-Animal Shelter Lighting Retrofit


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



19 Animal Shelter Lighting Retrofit ABAG EW 2009 yes no $2,409 $0 $583 0.93 4.1 28.4% $9,275

ABAG Energy Watch performed a lighting audit of the facility. The detailed findings for the facility are provided in the appendices.66 Due to the expiration of the ABAG EW program incentives ($.20/kWh), the financial analysis used the incentive numbers for the Small Business Energy Alliance ($.13/kWh). The reduced heat gain (HVAC) savings specified in the ABAG EW results were not included in this cash benefit analysis. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Animal Shelter Lighting Retrofit ABAG EW 2.9 2.1 2.00 0.0 0.00 1.00 0.00 0.1 8.08 22.72




A B C D E

n y y y y

Action Plan 20-Corporation Yard Lighting Retrofit ABAG EW


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



20 Corporation Yard Lighting Retrofit ABAG EW 2009 yes no $3,450 $0 $1,293 2.07 2.7 42.3% $22,378


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Corporation Yard Lighting Retrofit ABAG EW 2.8 3.0 2.00 0.1 1.00 1.00 0.00 0.2 10.00 31.37




A B C D E

n y y y y

Action Plan 21-Cavanaugh Center Lighting Retrofit ABAG EW


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



21 Cavn. Cntr Lighting Retrofit ABAG EW 2009 yes no $4,156 $0 $934 1.49 4.5 26.6% $14,576

ABAG Energy Watch performed a lighting audit of the facility. The detailed findings for the facility are provided in the appendices.68 Due to the expiration of the ABAG EW program incentives ($.20/kWh), the financial analysis used the incentive numbers for the Small Business Energy Alliance ($.13/kWh). The reduced heat gain (HVAC) savings specified in the ABAG EW results were not included in this cash benefit analysis.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Cavn. Cntr Lighting Retrofit ABAG EW 2.8 2.0 2.00 0.0 0.00 1.00 0.00 0.1 7.90 22.04




A B C D E

n y y y y

Action Plan 22-Elwood Center Soup Kitchen Lighting Retrofit ABAG EW


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2009 yes no $845 $0 $631 1.01 1.3 80.8% $11,727

ABAG Energy Watch performed a lighting audit of the facility. The detailed findings for the facility are provided in the appendices.69 Due to the expiration of the ABAG EW program incentives ($.20/kWh), the financial analysis used the incentive numbers for the Small Business Energy Alliance ($.13/kWh). The reduced heat gain (HVAC) savings specified in the ABAG EW results were not included in this cash benefit analysis.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2.9 3.0 2.00 0.0 0.00 1.00 0.00 0.1 9.05 27.28




A B C D E

n y y y y

Action Plan 23-Senior Center Lighting Retrofit ABAG EW


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



23 Senior Center Lighting Retrofit ABAG EW 2009 yes no $2,518 $0 $1,059 1.69 2.4 47.0% $18,636


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Senior Center Lighting Retrofit ABAG EW 2.8 3.0 2.00 0.0 0.00 1.00 0.00 0.1 9.02 27.34




A B C D E

n y y y y

Action Plan

24-Airport Lighting Retrofit ABAG EW


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



24 Airport Lighting Retrofit ABAG EW 2009 yes no $7,420 $0 $2,063 3.30 3.6 32.2% $33,897


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Airport Lighting Retrofit ABAG EW 2.6 2.4 2.00 0.1 0.00 1.00 0.00 0.2 8.31 24.44




A B C D E

n y y y y

Action Plan 25-Vending Machine Controls


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



25 Vending Machine Controls 2009 yes no $2,548 $0 $5,259 8.40 0.5 217.1% $101,979

The Vending Miser measure will reduce the energy used by 20 vending machines by a total of roughly 35,000 kWh annually. The Vending Miser works by turning the vending machine’s cooling system off when the machines are not being utilized. Incentive funding for this measure is available through the CPUC funded efficiency programs implemented by PG&E. This measure was specified in the referenced report.72 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Vending Machine Controls 2.8 3.0 0.00 0.2 0.00 0.00 0.00 0.6 6.70 23.87




A B C D E

n y y y y

Action Plan 26- Frates Pump Retrofit


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



26 Retrofit Frates Pumps (Zone 4) 2010 yes no $13,842 $0 $3,597 5.44 3.8 30.3% $58,234

The possible extension of reclaimed water to Zone 5 to serve the Petaluma Golf and Country Club will save pumping energy if implemented. That demand is shown as an option in the Reclamation Master Plan. The Corona Pump Station is not used. At that location water flows through the station from the SCWA aqueduct without having to be pumped due to high pressures. Therefore it is not included in the flow into zone 4. Zones 2, 3 and 5 will continue to use more energy as build out occurs in each pressure zone. Zone 1 is not pumped. The work at Frates Pump Station will reduce power use there by approximately 20%.73 The power consumption values by station are provided in the appendices.


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Retrofit Frates Pumps (Zone 4) 2.2 2.3 1.00 0.2 6.00 0.00 0.00 0.4 12.02 43.85

73 Email from Department of Water Resources and Conservation Staff containing energy consumption by zone and projected energy savings and cost per station, September 7, 2007.



A B C D E

n n n n y

Action Plan 27- Petaluma Aqueduct Supplying Zone 4


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



27 Petaluma Aqueduct supplying Zone 4 2012 yes no $195,368 $0 $15,413 20.89 12.7 9.8% $119,951

The new Petaluma Aqueduct (east side alignment) when constructed (estimated to be 2015) will allow the elimination of pumping into zone 4 (Frates Pump Station and Corona Pump Station).74 The saving for this measure are applied after the savings are applied for the previous measure. The power consumption values by station are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Petaluma Aqueduct supplying Zone 4 -3.0 0.7 0.00 0.6 6.00 0.00 0.00 1.8 6.13 30.66

74 Email from Department of Water Resources and Conservation Staff containing energy consumption by zone and projected energy savings and cost per station, September 7, 2007.



A B C D E

n y n y y

Action Plan

28- Waste Water Pond Solar BeeTM


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback




2009 yes no $94,257 $0 $40,897 65.33 2.3 48.4% $722,199

The SolarBEETM wastewater lagoon aeration system significantly reduces the size of the pump motor combinations while providing equivalent results. This yields very large energy and cost savings. This measure has been evaluated by the Sonoma County Energy Watch for municipal applications in Sonoma County. The costs and benefits of this measure are based on a municipal application scaled by waste water energy consumption of the jurisdictions. The relative savings numbers are reduced by a factor of 2 to provide a significant margin of conservatism in the financial results. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



SolarBeeTM (unless new facility removes need)

-2.7 3.0 0.00 1.9 6.00 0.00 0.00 4.8 12.99 58.38



A B C D E

n n y y y

Action Plan 29- Commercial Kitchen Grease to Gas Methane Program


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



29 Grease to Gas Methane Program 2011 yes no $265,880 $0 $102,723 571.65 2.6 43.5% $1,786,245

This measure applies the success of the City of Riverside in its well documented program to redirect restaurant trap grease to the wastewater methane digesters to displace the natural gas usage of the facility. The costs and benefits of this program as applied to the City of Petaluma are scaled down based on relative populations. Furthermore, the costs of the Riverside program ($85k) have been increased by a factor of 4. The benefits are reduced also reduced by 50%. These conservative adjustments are applied to account for the many unknowns involved in translating this program to a different community and wastewater treatment facility. The numbers used in the cost / benefit analysis are provided in the table below. Further information on the City of Riverside Grease to Gas program is available from the City of Riverside.75

Base Population Data

Riverside Population 300,000Petaluma 54,500

Population % 18%

Adjustments for Conservatism

Capital Costs 400% Percentage Increase

Energy Savings 50% Per capita percentage decrease

O&M 50% Per capita percentage decrease

Savings Riverside Petaluma

Therms Natural Gas Displa 1,020,000 92,650 Therms

Capital Cost $85,000 $340,000 Petaluma Adjusted

Disposal Fees $21,000 $1,908 $0.03/gallon

Wet Solids Reduction $48,000 $4,360 $48/ton disposal fee

Cost per Therm $1.000


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Grease to Gas Methane Program -3.0 3.0 6.00 6.0 3.00 -1.00 2.00 6.0 22.00 77.00

75 See the Appendices for a summary of material from the City of Riverside



A B C D E

n y y n y

Action Plan 30- Streetlighting A: 50% Conversion from HPS to LED (or equiv)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



30Streetlighting A: 50%


2012 yes no $692,010 ($132,212) $34,741 47.08 4.1 28.4% $2,655,649

Streetlighting consumes over 2,000,000 kWh per year, representing a significant portion of the City total. This measure addresses 50% of the fixtures and assumes a 20% reduction in energy consumption for the fixtures affected. The broad demand for greater efficiencies in this sector is driving aggressive efforts to bring a new generation of streetlighting options to the market. The cities of Raleigh, NC, Ontario, Canada, Ann Arbor, Michigan, and Oakland, CA have pilot installations to test efficient products currently available. The analysis for this measure is based on the assumptions in the table below. A key step in the adoption of this measure will be the negotiation of a PG&E tariff that reflects this new technology. The implementation of this measure is delayed until 2012 to allowing for the maturation of this new technology.

Streetlight Retrofit Assumptions

2,087,920

208,792

4683

50%

2342

$300

20%

50%

$50 Maintenance Savings per Fixture (Annual)

$117,075

Lamp Life

24,000

4380

5.5

70,000

4380

16.0 years of operation

annual hours of operation per year

hours (LED)

years of operation


hours (HPS)

(for implementation schedule, reduced maintenance)

Maintenance Savings

Energy Savings and Reduction in PG&E billing rate

Energy Cost Savings as percentage of $/kWh (tariff negotiation require

Number of fixtures

Percentage of fixtures in this measure

Number of fixtures affected

Incremental cost per fixture

kWh: Streetlight usage from Petaluma 2006 billing data

kWh saved with this measure


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Streetlighting A: 50% Conversion HPS to LED (or equiv.) -3.0 2.1 0.00 1.4 3.00 1.00 0.00 6.0 10.48 46.70



A B C D E

n n n n y

Action Plan 31- Streetlighting B: 50% Conversion from HPS to LED (or equiv)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



31Streetlighting B: 50%


2013 yes no $692,010 ($132,212) $35,957 46.09 4.1 28.5% $2,679,791

This measure addresses the remaining 50% of the fixtures and assumes a 20% reduction in energy consumption for the fixtures affected. The broad demand for greater efficiencies in this sector is driving aggressive efforts to bring a new generation of streetlighting options to the market. The cities of Raleigh, NC, Ontario, Canada, Ann Arbor, Michigan, and Oakland, CA have pilot installations to test efficient products currently available. The analysis for this measure is based on the assumptions in the table below. A key step in the adoption of this measure will be the negotiation of a PG&E tariff that reflects this new technology. The implementation of this measure is delayed until 2013 to allowing for the maturation of this new technology.

Streetlight Retrofit Assumptions

2,087,920

208,792

4683

50%

2342

$300

20%

50%


$117,075

Lamp Life

24,000

4380

5.5

70,000

4380

16.0 years of operation


hours (LED)

years of operation


hours (HPS)

(for implementation schedule, reduced maintenance)

Maintenance Savings

Energy Savings and Reduction in PG&E billing rate

Energy Cost Savings as percentage of $/kWh (tariff negotiation require

Number of fixtures




kWh: Streetlight usage from Petaluma 2006 billing data



Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Streetlighting B: 50% Conversion HPS to LED (or equiv.) -3.0 2.1 0.00 1.3 3.00 1.00 0.00 6.0 10.47 46.69



A B C D E

n y n y n

Action Plan

1,402,182

701,091

4083

50%

2042

$50

100%


$0

kWh: Residential Streetlight usage from billing data


Number of residential fixtures




Reduction in PG&E billing rate

Maintenance Savings

4083 Residential Streetlights installed wattage 308,250 67%

70w - 90% - 3675 257,250

100w - 5% - 204 20,400

150w - 5% - 204 30,600

600 Intersection/Arterial Streetlights installed wattage 150,750 33%

200w - 42.5% - 255 51,000

250w - 42.5% - 255 63,750

400w - 15% - 90 36,000

459,000

32- Streetlighting C: Turn Off 50% of Residential (non intersection) Lighting


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



32Streetlighting C: Turn off 50%

of Residential (non intersection) lighting

2010 no no $67,020 $0 $108,899 164.76 0.6 171.7% $2,098,255

This measure “turns off” half of the residential streetlighting saving over 700,000 kWh annually. The large NPV for this measure is due to reduced annual tariff payment to the utility which would need to be negotiated. This measure can also be modified to reflect availability of devices designed to switch streetlights off for a portion of the early morning hours. The assumptions behind the costs and benefits calculation are provided in the tables below.76 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Streetlighting C: Turn off 50% of Residential (non intersection) lighting -1.0 3.0 0.00 4.7 5.00 -1.00 -2.00 6.0 14.72 65.19

76 Streetlighting date provided by email from Public Works Staff, May 19th 2008.



A B C D E

n n n y n

Action Plan

1,402,182

701,091

4083

50%

2042

$50

100%


$0

kWh: Residential Streetlight usage from billing data


Number of residential fixtures




Reduction in PG&E billing rate

Maintenance Savings

4083 Residential Streetlights installed wattage 308,250 67%

70w - 90% - 3675 257,250

100w - 5% - 204 20,400

150w - 5% - 204 30,600

600 Intersection/Arterial Streetlights installed wattage 150,750 33%

200w - 42.5% - 255 51,000

250w - 42.5% - 255 63,750

400w - 15% - 90 36,000

459,000

33- Streetlighting D: Turn Off 50% of Residential (non intersection) Lighting


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



33Streetlighting D: Turn off 50%

of Residential (non intersection) lighting

2012 no no $67,020 $0 $116,655 158.10 0.6 183.7% $2,252,250

This measure “turns off” the second half of the residential streetlighting also saving over 700,000 kWh annually. The large NPV for this measure is due to reduced annual tariff payment to the utility which would need to be negotiated. This measure can also be modified to reflect availability of devices designed to switch streetlights off for a portion of the early morning hours. The assumptions behind the costs and benefits calculation are provided in the tables below.77 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Streetlighting D: Turn off 50% of Residential (non intersection) lighting -1.0 3.0 0.00 4.6 5.00 -1.00 -2.00 6.0 14.53 64.62

77 Streetlighting date provided by email from Public Works Staff, May 19th 2008.



A B C D E

n y y y y

Action Plan 34- Commute 1


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



34 Commute 1 2010 no no $0 $22,500 $0 75.53 0.0 NA ($446,717)

The general assumptions of a transit demand management (TDM) program are based on the documented cost and impact of successful programs under similar circumstances provided in published case studies. This analysis assumes an increased commute investment of $22.5k per year resulting in an impact of 25% on the commuting patterns of city employees. The cost is based on a 0.25 FTE position (entry level admin, 1FTE=$50,000) and $10,000 per year in program costs. A general summary of commute programs is provided in the appendices. Further study is recommended to allow a more aggressive analysis of commute program impacts. Additional support for commute program development, implementation and evaluation is available from the 511 Regional Rideshare Program.78 There is was an effective TDM program in place serving Napa and Solano counties at the time of this analysis. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Commute 1 2.5 -3.0 0.00 2.2 0.00 2.00 0.00 0.0 3.68 0.53

78 511 Regional Rideshare Program, 70 Washington Street, Oakland, CA 94607, (510) 273-3628



A B C D E

n n n y y

Action Plan

35- Commute 2


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



35 Commute 2 2011 no no $0 $32,500 $0 75.53 0.0 NA ($645,257)

This is a second commute measure essentially doubling the effort in this area. As with the previous measure, the analysis assumes an increased commute investment of $22.5k per year resulting in an impact of 25% on the commuting patterns of city employees. The cost is based on a 0.25 FTE position (entry level admin, 1FTE=$50,000) and $10,000 per year in program costs. A general summary of commute programs is provided in the appendices. Additional support for commute program development, implementation and evaluation is available from the 511 Regional Rideshare Program.79 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Commute 2 2.5 -3.0 0.00 2.2 0.00 2.00 0.00 0.0 3.68 0.53

79 511 Regional Rideshare Program, 70 Washington Street, Oakland, CA 94607, (510) 273-3628



A B C D E

y y y y y

Action Plan 36- 4 Day Work Week (Commute Impacts)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



36 4 day work week (Commute) 2009 no no $0 $0 $0 32.26 NA NA $0

A reduced work week would also reduce the greenhouse gas emissions associated with employee commuting. City staff completed an analysis of the number of employees that would be included in the 4 day work week program. It is assumed the 88 employees working a 4 day work week projected by that analysis would experience a 20% reduction in commute fuel consumption. This yields over 3,000 gallons of fuel saved and over 29 tons Co2e avoided per year.80 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



4 day work week (Commute) 3.0 3.0 2.00 0.9 3.00 1.00 -2.00 0.0 10.93 37.79

80 PGE Cost Analysis pre 2007 version, spreadsheet calculation provided by staff, December 30, 2008.



A B C D E

y y y y y

Action Plan 37- 4 Day Work Week (Building Impacts)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



37 4 day work week (Building) 2009 no no $20,000 $0 $26,007 63.66 0.8 138.1% $497,298

The reduced work week analysis completed by City Staff yields a projected a savings of 139,533 kWh and 4,895 Therms annually based on the billing data for the identified facilities.81 An investment of $20,000 is assumed to be required to complete the transition to the new schedule. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



4 day work week (Building) 1.8 3.0 2.00 1.8 3.00 1.00 -2.00 3.0 13.66 50.21

81 PGE Cost Analysis pre 2007 version, spreadsheet calculation provided by staff, December 30, 2008.



A B C D E

n n y y n

Action Plan 38- Petaluma Transit Fleet Replacement Strategy A


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



38 Bus Fleet A 2014 yes no $271,593 $0 $261,835 244.93 1.0 103.3% $4,939,834

The compressed natural gas (CNG) replacements specified in the table below will save over 240 metric tons of CO2e and result in considerable gasoline and diesel fuel savings annually. The costs are based on the cost data provided by the Metropolitan Transportation Commission (MTC) and assume an 80% cost sharing by the federal government. The table of values provided by MTC is provided in the appendices. The analysis assumes this measure would be fully implemented by 2014. Vehicle

No. Make Year Model Description Fuel Type MPG Replacement Vehicle Incr. Cost Fuel Annual Miles

MPG/ MPkWh

MPTherm

CNG (Therms) projected

Electric (equiv.kWh)

projected

Gasoline Savings

(gal)

Diesel Savings

(gal)

CNG Savings

(Therms)

7 Ford 2003 E350 ParaTransit Gas 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 12368 8.3 1736 0 1484 0 -1736

10 Ford 1997 Candidate ParaTransit Diesel 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 16201 8.3 2275 0 0 1944 -2275

30 Ford 2000 Bus ParaTransit Gas 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 22286 8.3 3129 0 2674 0 -3129

31 Ford 2001 Bus ParaTransit Gas 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3633 0 3105 0 -3633

AA Ford 2001 Bus ParaTransit Gas 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3633 0 3105 0 -3633

BB Ford 2001 Bus ParaTransit Gas 8.3 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3633 0 3105 0 -3633

4 Braun 2003 Transporter PPSC Gas 3.6 Transit Bus 40' CNG $11,045 CNG 7038 3.6 2264 0 1935 0 -2264

5 Ford 1997 Aerotech PPSC Diesel 3.6 Transit Bus 40' CNG $11,045 CNG 13298 3.6 4277 0 0 3656 -4277

11 Orion 1969 Orion II Fixed Route Diesel 3.6 Transit Bus 40' CNG $11,045 CNG 9961 3.6 3204 0 0 2738 -3204

21 Chevy 2003 Cut-a-way Fixed Route Gas 3.6 Transit Bus 40' CNG $11,045 CNG 17094 3.6 5498 0 4699 0 -5498






27 Ford 2000 Cut-a-way Fixed Route Gas 3.6 Transit Bus 40' CNG $11,045 CNG 26781 3.6 8613 0 7362 0 -8613

28 Ford 2000 Cut-a-way Fixed Route Gas 3.6 Transit Bus 40' CNG $11,045 CNG 29200 3.6 9391 0 8027 0 -9391

29 Ford 2000 Cut-a-way Fixed Route Diesel 3.6 Transit Bus 40' CNG $11,045 CNG 22321 3.6 7179 0 0 6136 -7179

32 Ford 2000 Cut-a-way Fixed Route Diesel 3.6 Transit Bus 40' CNG $11,045 CNG 24020 3.6 7725 0 0 6603 -7725

33 Gillig 2007 Transit Bus Fixed Route Diesel 3.6 Transit Bus 40' CNG $11,045 CNG 150 3.6 48 0 0 41 -48





Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Bus Fleet A -3.0 3.0 0.00 6.0 5.00 0.00 0.00 6.0 17.00 71.00



A B C D E

n y n n y

Action Plan

39- Petaluma Transit Fleet Replacement Strategy B


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



39 Bus Fleet B 2014 yes no $630,667 $0 $151,760 259.12 4.2 28.3% $2,412,429

The hybrid compressed natural gas (CNG) replacements specified in the table below will save almost 260 metric tons of CO2e and result in considerable gasoline and diesel fuel savings annually. The costs are based on the cost data provided by the Metropolitan Transportation Commission (MTC) and assume an 80% cost sharing by the federal government. The table of values provided by MTC is provided in the appendices. The analysis assumes this measure would be fully implemented by 2014.

Vehicle No. Make Year Model Description Fuel Type MPG Miles/Year Replacement Vehicle Incr. Cost Fuel Annual Miles

MPG/ MPkWh

MPTherm

Gasoline Savings

(gal)

Diesel Savings

(gal)

CNG Savings

(Therms)

7 Ford 2003 E350 ParaTransit Gas 8.3 12,368 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 12368 8.3 1484 0 -1736

10 Ford 1997 Candidate ParaTransit Diesel 8.3 16,201 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 16201 8.3 0 1944 -2275

30 Ford 2000 Bus ParaTransit Gas 8.3 22,286 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 22286 8.3 2674 0 -3129

31 Ford 2001 Bus ParaTransit Gas 8.3 25,877 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3105 0 -3633

AA Ford 2001 Bus ParaTransit Gas 8.3 25,877 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3105 0 -3633

BB Ford 2001 Bus ParaTransit Gas 8.3 25,877 Cut-Away/Van 26'+, 7-Year, CNG $13,970 CNG 25877 8.3 3105 0 -3633

4 Braun 2003 Transporter PPSC Gas 3.6 7,038 Transit Bus 40' Hybrid $32,167 Diesel 7038 5.5 1935 -1290 0

5 Ford 1997 Aerotech PPSC Diesel 3.6 13,298 Transit Bus 40' Hybrid $32,167 Diesel 13298 5.5 0 1219 0

11 Orion 1969 Orion II Fixed Route Diesel 3.6 9,961 Transit Bus 40' Hybrid $32,167 Diesel 9961 5.5 0 913 0

21 Chevy 2003 Cut-a-way Fixed Route Gas 3.6 17,094 Transit Bus 40' Hybrid $32,167 Diesel 17094 5.5 4699 -3133 0






27 Ford 2000 Cut-a-way Fixed Route Gas 3.6 26,781 Transit Bus 40' Hybrid $32,167 Diesel 26781 5.5 7362 -4908 0

28 Ford 2000 Cut-a-way Fixed Route Gas 3.6 29,200 Transit Bus 40' Hybrid $32,167 Diesel 29200 5.5 8027 -5351 0

29 Ford 2000 Cut-a-way Fixed Route Diesel 3.6 22,321 Transit Bus 40' Hybrid $32,167 Diesel 22321 5.5 0 2045 0

32 Ford 2000 Cut-a-way Fixed Route Diesel 3.6 24,020 Transit Bus 40' Hybrid $32,167 Diesel 24020 5.5 0 2201 0

33 Gillig 2007 Transit Bus Fixed Route Diesel 3.6 150 Transit Bus 40' Hybrid $32,167 Diesel 150 5.5 0 14 0



36 Gillig 2007 Transit Bus Fixed Route Diesel 3.6 145 Transit Bus 40' Hybrid $32,167 Diesel 145 5.5 0 13 0 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Bus Fleet B -3.0 2.1 0.00 6.0 5.00 0.00 0.00 6.0 16.12 66.61



A B C D E

n n y n n

Action Plan 40- Fleet Replacement Strategy A (Including Nissan Electric)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



40 Fleet Replacement Strategy A (includes Nissan Elec) 2010 yes no $730,000 $0 $168,301 490.96 4.3 27.2% $2,646,226

The fleet changes specified in the table below will save over 490 metric tons of CO2e annually and result in considerable gasoline and diesel fuel savings. The costs are based on the estimated incremental cost of purchasing the more efficient alternative rather than the current model or equivalent. The analysis assumes this measure would be fully implemented by 2010. A later completion date would delay the greenhouse gas reductions by the portion not completed. A complete list of specific vehicles, their classification and the associated strategies is provided in the appendices.

Original Replacement Fuel MPG MPkWh

Incremental Cost

COMPACT CARS Nissan Electric Sedan Electric 2.10 $10,000

MIDSIZE CARS None in fleet NA NA NA

LARGE CARS Nissan Electric Sedan Electric 2.10 $10,000

SMALL PU TRUCKS 2WD Diesel hybrid Pickup diesel 21.00 $6,000

SUV-2WD Hybrid SUV gas 30.00 $4,000

STD PU TRUCKS 2WD Diesel hybrid Pickup diesel 21.00 $6,000


POLICE CRUISER 1 Impala gas 20.80 $0


LARGE TRUCK Diesel hybrid Lg Truck diesel 9.00 $6,000

Strategy


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Fleet Replacement Strategy A (includes Nissan Elec) -3.0 2.0 0.00 6.0 4.00 -1.00 0.00 6.0 14.04 60.21



A B C D E

n y n y y

Action Plan 41- Fleet Replacement Strategy B (Including Nissan Electric)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



41 Fleet Replacement Strategy B (includes Nissan Elec) 2012 yes no $994,000 $0 $207,179 531.43 4.8 24.9% $3,166,685

The fleet changes specified in the table below will save over 530 metric tons of CO2e annually and result in considerable gasoline and diesel fuel savings. The costs are based on the estimated incremental cost of purchasing the more efficient alternative rather than the current model or equivalent. The analysis assumes this measure would be fully implemented by 2012. A later completion date would delay the greenhouse gas reductions by the portion not completed. A complete list of specific vehicles, their classification and the associated strategies is provided in the appendices.


Incremental Cost


None in Fleet Electric Compact NA NA NA


SMALL PU TRUCKS 2WD Diesel hybrid Pickup diesel 21.00 $6,000

MINIVAN-2WD Electric Van Electric 2.13 $15,000

SUV-2WD Electric SUV Electric 2.13 $15,000

STD PU TRUCKS 2WD Electric SUT Electric 2.13 $15,000


VANS, CARGO Electric Van Electric 2.13 $15,000



LARGE TRUCK Diesel hybrid Lg Truck diesel 9.00 $6,000

Strategy


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Fleet Replacement Strategy B (includes Nissan Elec) -3.0 1.9 0.00 6.0 4.00 -1.00 0.00 6.0 13.87 59.33



A B C D E

y n n n n

Action Plan 42- Nissan Electric Vehicles


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



42Electric Vehicles (Nissan 28 Vehicles Excl to other Fleet

Measures)2010 yes no $130,000 $0 $5,351 21.70 24.3 3.7% ($17,580)

The opportunity developing with the Nissan Electric Vehicle program has not been made fully public at the time of this analysis. Therefore the costs and fuel economy are assumed per the table below. The implementation cost does not include the cost of charging stations (if required as part of the program). There are 13 compact and large cars in the fleet that are assumed to be replaced by this opportunity. A similar strategy is incorporated into the Fleet Replacement Strategy A and B. A complete list of specific vehicles, their classification and the associated strategies is provided in the appendices.


Incremental Cost


MIDSIZE CARS Nissan Electric Sedan Electric 2.10 $10,000


Strategy


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Electric Vehicles (Nissan 28 Vehicles) -3.0 -2.7 0.00 0.6 6.00 -1.00 0.00 0.6 0.53 6.77



A B C D E

n n n n n

Action Plan 43- Biodiesel 20%


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



43 Biodiesel 20% 2009 yes no $0 $0 ($1,646) 39.02 0.0 NA ($32,671)

This measure changes the fuel mix for all diesel vehicles to a 20/80% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and no infrastructure improvements (tanks, etc). Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 20% 3.0 -3.0 0.00 1.1 1.00 -1.00 0.00 0.0 1.12 -3.63



A B C D E

n n n n n



Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



44 Biodiesel 50% 2010 yes no $50,000 $0 ($4,435) 97.55 -11.3 NA ($135,670)

This measure changes the fuel mix for all diesel vehicles to a 50/50% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel.82 Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 50% 0.0 -3.0 0.00 2.8 2.00 -1.00 0.00 0.0 0.81 -0.57

82 The use of high percentage biodiesel must be coordinated with California Air Resource Board (CARB) requirements and vehicle warranty considerations.



A B C D E

n n n n n



Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



45 Biodiesel 99% 2010 yes no $50,000 $0 ($8,781) 193.15 -5.7 NA ($221,960)

This measure changes the fuel mix for all diesel vehicles to a 99/1% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product.83 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 99% 0.0 -3.0 0.00 5.6 3.00 -1.00 0.00 0.0 4.56 11.69




A B C D E

n n n n n

Action Plan 46- Biodiesel 20% (linked to Fleet Replacement Strategy A)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



46 Biodiesel 20% linked to Fleet A 2009 yes no $0 $0 ($3,046) 72.22 0.0 NA ($60,467)

This measure, applied after Fleet Replacement A, changes the fuel mix for all diesel vehicles to a 20/80% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and no cost for infrastructure improvements (tanks, etc). Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 20% linked to Fleet A 3.0 -3.0 0.00 2.1 1.00 -1.00 0.00 0.0 2.08 -0.76



A B C D E

n n n n n

Action Plan 47- Biodiesel 20% (linked to Fleet Replacement Strategy B)


Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



47 Biodiesel 20% linked to Fleet B 2009 yes no $0 $0 ($2,736) 64.87 0.0 NA ($54,314)

This measure, applied after Fleet Replacement B, changes the fuel mix for all diesel vehicles to a 20/80% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and no cost for infrastructure improvements (tanks, etc). Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 20% linked to Fleet B 3.0 -3.0 0.00 1.9 1.00 -1.00 0.00 0.0 1.87 -1.39



A B C D E

n n y n n



Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



48 Biodiesel 50% linked to Fleet A 2010 no no $60,500 $0 ($8,208) 180.54 -7.4 NA ($220,585)

This measure, applied after Fleet Replacement A changes the fuel mix for all diesel vehicles to a 50/50% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel.84 Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 50% linked to Fleet A -0.6 -3.0 0.00 5.2 1.00 -1.00 0.00 0.0 1.57 1.34




A B C D E

n y n y n



Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



49 Biodiesel 50% linked to Fleet B 2010 no no $59,000 $0 ($7,373) 162.17 -8.0 NA ($202,571)

This measure, applied after Fleet Replacement B changes the fuel mix for all diesel vehicles to a 50/50% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel.85 Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 50% linked to Fleet B -0.5 -3.0 0.00 4.7 2.00 -1.00 0.00 0.0 2.13 3.93




A B C D E

n n n n n



Power Purchase

Agreement (yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



50 Biodiesel 99% linked to Fleet A 2010 no no $60,500 $0 ($16,252) 357.48 -3.7 NA ($380,291)

This measure, applied after Fleet Replacement A changes the fuel mix for all diesel vehicles to a 99/1% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product.86 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 99% linked to Fleet A -0.6 -3.0 0.00 6.0 3.00 -1.00 0.00 0.0 4.37 11.74




A B C D E

n n n n y




(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



51 Biodiesel 99% linked to Fleet B 2010 no no $59,000 $0 ($14,598) 321.10 -4.0 NA ($346,025)

This measure, applied after Fleet Replacement B changes the fuel mix for all diesel vehicles to a 99/1% (biodiesel/diesel) blend for all fleet vehicles currently using diesel fuel. Biodiesel is now readily available at a reasonable price allowing rapid implementation of this GHG reduction strategy. This analysis assumes $3.38 per gallon and $50,000 for infrastructure improvements (tanks, etc) and a conversion cost of $500 for any unit older than 1995. Prices are assumed to escalate at the same rate as petroleum based diesel fuel (8% per year). This analysis also uses the coefficient of 5.24 lbs CO2e per gallon of 100% biodiesel. While the use of biodiesel fuel created from waste oil (assumed to be available locally) would have close to zero emissions for the feedstock. The process requires that 20% of the feed stock is methanol, a petroleum product.87 Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Biodiesel 99% linked to Fleet B -0.5 -3.0 0.00 6.0 3.00 -1.00 0.00 0.0 4.46 11.92




A B C D E

n n y n n

Action Plan 52- Fleet Management Software (Linked to Fleet Strategy A)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



52Fleet Management Software Linked to Fleet Replacement

A2010 yes no $300,000 ($20,000) $11,500 33.61 9.5 13.2% $339,684

Fleet management Software is available to track information on each specific vehicle in the City fleet and coordinate maintenance efforts. The mileage and fueling documentation typically available provides information to reduce of unnecessary or inefficient travel patterns. In addition to the fuel savings from enhance maintenance scheduling, the performance data from each vehicle can provide early indications of mechanical issues that reduce fuel efficiency. The assumptions used in determining the costs and benefits of this measure are provided in the table below. The savings are calculated after the savings associated with Fleet Strategy A.

Savings

Cost Estimate $300,000

Fuel Savings Estimate 5%

Original Gal.Gas (2008) 18,415 921

Original Gal. Diesel (2008) 45,923 2,296

O&M Cost Savings 10%

O&M Original Costs $200,000 $20,000

Fleet Management Software


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Fleet Management Software Linked to Fleet Replacement A -3.0 1.0 3.00 1.0 4.00 0.00 0.00 3.7 9.63 38.53



A B C D E

n y n y y

Action Plan 53- Fleet Management Software (Linked to Fleet Strategy B)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



53Fleet Management Software Linked to Fleet Replacement

B2010 yes no $300,000 ($20,000) $10,575 30.90 9.8 12.8% $321,318

Fleet management Software is available to track information on each specific vehicle in the City fleet and coordinate maintenance efforts. The mileage and fueling documentation typically available provides information to reduce of unnecessary or inefficient travel patterns. In addition to the fuel savings from enhance maintenance scheduling, the performance data from each vehicle can provide early indications of mechanical issues that reduce fuel efficiency. The assumptions used in determining the costs and benefits of this measure are provided in the table below. The savings are calculated after the savings associated with Fleet Strategy B.

Savings

Cost Estimate $300,000

Fuel Savings Estimate 5%

Original Gal.Gas (2008) 18,415 921

Original Gal. Diesel (2008) 45,923 2,296

O&M Cost Savings 10%

O&M Original Costs $200,000 $20,000

Fleet Management Software


Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Fleet Management Software Linked to Fleet Replacement B -3.0 1.0 3.00 0.9 4.00 0.00 0.00 3.6 9.41 37.72



A B C D E

y n y y y

Action Plan

54- Photovoltaic System 1.0 MWac (PPA)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



54 PV 1.0 MWac (PPA) 2011 no yes $50,000 $0 ($13,424) 284.51 -3.7 NA ($167,375)

Photovoltaic (PV) systems are available for electricity generation to offset the energy consumption of buildings, water pumping, wastewater treatment and other uses of significant electrical energy. The application of PV systems to water supply pumping situations is particularly attractive if the jurisdiction has the ability to schedule the majority of the pumping at night when energy rates are low (utilizing the capacity of the storage tanks). In this case the PV system generates electricity during the day when the energy is most valuable, and the pumps draw energy from the utility grid at night when it is least costly. Therefore the energy produced is much more valuable than the energy purchased from the utility for that meter. This measure specifies a 1.0 MW system producing an average of roughly 1,235,000 kWh per year. The negative “Annual Cost Savings” reflects the additional cost of power over PG&E supplied power ($.145/kWh) and is dependant on the contract negotiated with the provider. The general assumptions underlying the PV production calculations are provided in the appendices. The financial metrics reflect the assumption that a power purchase agreement (PPA) will be utilized to implement the system. A power purchase agreement is a long-term agreement between a power provider (the solar company) and a customer. The customer agrees to purchase energy from the provider at a fixed rate for the term of the agreement. This rate increases every year by an agreed percentage. The life of the agreement may be in the range of 20 years. At the end of the contract period the customer typically has the option to purchase the system at its value at that time. This analysis assumes the cost of energy would be 5% more than the current PG&E rate, and would escalate at 3.5% per year. The analysis also assumes the city retains ownership of the Renewable Energy Credits (REC). The cost of energy specified in the contract will have significant influence over the financial metrics of the measure. The value used in this analysis (5% above PG&E rates) should be considered reasonably conservative. The capital cost for this measure assumes $50,000 of staff and legal time invested in the contracting process. The assumed term of the contract matches the term of this analysis, 25 years. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV 1.0 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00



A B C D E

y y n n y

Action Plan 55- Photovoltaic System 2.0 MWac (PPA)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



55 PV 2 MWac (PPA) 2013 no yes $50,000 $0 ($26,847) 545.54 -1.9 NA ($334,751)

This measure specifies a 2.0 MW system producing an average of roughly 2,470,000 kWh per year. The Net Capital Cost reflects $50,000 expended to negotiate the PPA contract. The costs reflect the assumption that a power purchase agreement (PPA) will be utilized to implement the system. A power purchase agreement is a long-term agreement between a power provider (the solar company) and a customer. The customer agrees to purchase energy from the provider at a fixed rate for the term of the agreement. This rate increases every year by an agreed percentage. The life of the agreement may be in the range of 20 years. At the end of the contract period the customer typically has the option to purchase the system at its value at that time. This analysis assumes the cost of energy would be 5% more than the current PG&E rate, and would escalate at 3.5% per year. The analysis also assumes the city retains ownership of the Renewable Energy Credits (REC), and the provider pays all maintenance costs including replacement of the inverters which have a life of roughly 10 years. The cost of energy specified in the contract will have significant influence over the financial metrics of the measure. The value used in this analysis (5% over present PG&E rates) is based on a large contract proposal presented to a public agency in Sonoma County in 2008. The assumed term of the contract matches the term of this analysis, 25 years. The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV 2 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00



A B C D E

y n n n n

Action Plan 56- Photovoltaic System 1.0 MWac (PPA)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



56 PV 1.0 MWac (PPA) 2012 no yes $50,000 $0 ($13,424) 278.64 -3.7 NA ($167,375)

This measure specifies a 1.0 MW system producing an average of roughly 1,235,000 kWh per year. The Net Capital Cost reflects $50,000 expended to negotiate the PPA contract. The costs reflect the assumption that a power purchase agreement (PPA) will be utilized to implement the system. A power purchase agreement is a long-term agreement between a power provider (the solar company) and a customer. The customer agrees to purchase energy from the provider at a fixed rate for the term of the agreement. This rate increases every year by an agreed percentage. The life of the agreement may be in the range of 20 years. At the end of the contract period the customer typically has the option to purchase the system at its value at that time. This analysis assumes the cost of energy would be 5% more than the current PG&E rate, and would escalate at 3.5% per year. The analysis also assumes the city retains ownership of the Renewable Energy Credits (REC), and the provider pays all maintenance costs including replacement of the inverters which have a life of roughly 10 years. The cost of energy specified in the contract will have significant influence over the financial metrics of the measure. The value used in this analysis (5% over present PG&E rates) is based on a large contract proposal presented to a public agency in Sonoma County in 2008. The assumed term of the contract matches the term of this analysis, 25 years. The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV 1.0 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00



A B C D E

y n n n n

Action Plan 57 Photovoltaic System 0.5 MWac (PPA)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



57 PV .5 MWac (PPA) 2012 no yes $50,000 $0 ($6,712) 139.32 -7.4 NA ($83,688)

This measure specifies a 0.5 MW system producing an average of roughly 615,000 kWh per year. The Net Capital Cost reflects $50,000 expended to negotiate the PPA contract. The costs reflect the assumption that a power purchase agreement (PPA) will be utilized to implement the system. A power purchase agreement is a long-term agreement between a power provider (the solar company) and a customer. The customer agrees to purchase energy from the provider at a fixed rate for the term of the agreement. This rate increases every year by an agreed percentage. The life of the agreement may be in the range of 20 years. At the end of the contract period the customer typically has the option to purchase the system at its value at that time. This analysis assumes the cost of energy would be 5% more than the current PG&E rate, and would escalate at 3.5% per year. The analysis also assumes the city retains ownership of the Renewable Energy Credits (REC), and the provider pays all maintenance costs including replacement of the inverters which have a life of roughly 10 years. The cost of energy specified in the contract will have significant influence over the financial metrics of the measure. The value used in this analysis (5% over present PG&E rates) is based on a large contract proposal presented to a public agency in Sonoma County in 2008. The assumed term of the contract matches the term of this analysis, 25 years. The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV .5 MWac (PPA) 0.0 -3.0 0.00 4.0 6.00 0.00 0.00 3.0 7.01 33.04



A B C D E

y n n n n

Action Plan 58- Photovoltaic System 0.5 MWac (City Owned)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



58 PV .5 MWac 2013 yes no $4,002,843 $10,000 $106,399 136.39 41.5 NA ($2,532,377)

This measure specifies a 500 kW system producing an average of 615,000 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 88 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV .5 MWac -3.0 -3.0 0.00 3.9 6.00 0.00 0.00 6.0 9.93 38.78

88 California Solar Initiative / Self-Generation Incentive Program Statewide Trigger Point Tracker, www.sjip-ca.com.



A B C D E

y n n n n




(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



59 PV 1.0 MWac 2009 yes no $8,002,843 $20,000 $185,441 296.25 48.4 NA ($5,605,190)

This measure specifies a 1.0 MW system producing an average of 1,235,000 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 89 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV 1.0 MWac -3.0 -3.0 0.00 6.0 6.00 0.00 0.00 6.0 12.00 45.00




A B C D E

y n n n n




(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



60 PV 2.0 MWac 2014 yes no $16,002,843 $40,000 $440,491 533.80 40.0 -2.7% ($9,825,642)

This measure specifies a 2.0 MW system producing an average of 2,470,000 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 90 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



PV 2.0 MWac -3.0 -3.0 0.00 6.0 6.00 0.00 0.00 6.0 12.00 45.00




A B C D E

n n y y y

Action Plan 61- Photovoltaic System 41 kWac (City Owned)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



61 Community Center 41 kWac PV MCAP 2010 yes no $272,903 $822 $7,888 11.93 38.6 NA ($171,731)

This measure specifies a 41 kW system producing an average of 50,000 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 91 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Community Center 41 kWac PV MCAP -3.0 -3.0 0.00 0.3 6.00 0.00 0.00 0.8 1.17 7.32




A B C D E

n y n y y

Action Plan 62- Kenilworth Center Photovoltaic System 80 kWac (City Owned)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



62 K.Swim Center 80 kWac PV System MCAP 2010 yes no $625,468 $1,557 $14,938 22.60 46.7 NA ($428,709)

This measure specifies a 77.8 kWac system (96 kWdc) producing an average of 96,000 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 92 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



K.Swim Center 80 kWac PV System MCAP -3.0 -3.0 0.00 0.7 6.00 0.00 0.00 1.6 2.21 11.19




A B C D E

n n n y y

Action Plan 63- City Hall Photovoltaic System 50 kWac (City Owned)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



63 City Hall PV System 50kWac 2012 yes no $342,060 $959 $9,858 13.36 38.4 -2.8% ($209,894)

This measure specifies a 47.9 kWac system (59.2 kWdc) producing an average of 59,200 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity. 93 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



City Hall PV System 50kWac -3.0 -3.0 0.00 0.4 6.00 0.00 0.00 1.0 1.42 8.30




A B C D E

n y y y y

Action Plan 64- Photovoltaic System 25.3 kWac (City Owned)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



64 Public Works PV System 25.3 kWac 2009 yes no $157,047 $505 $4,686 7.49 37.6 NA ($98,612)

This measure specifies a 25.3 kWac system producing an average of 31,200 kWh per year similar to the previous measure. However, this measure assumes ownership by the City. The low IRR and negative NPV reflect the diminishing CPUC incentives over the next few years. However, the CPUC may refund the PV incentive programs, which would improve the financial metrics of this opportunity.94 The general assumptions underlying the PV production calculations are provided in the appendices. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Public Works PV System 25.3 kWac -3.0 -3.0 0.00 0.2 6.00 0.00 0.00 0.5 0.70 5.59




A B C D E

n y y y y

Action Plan 65- Efficiency Coordinator (.5FTE)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



65 Efficiency Coordinator (.5FTE) 2010 no no $0 $30,000 $0 0.00 0.0 NA ($595,622)

The implementation and monitoring of an aggressive GHG emissions reduction program, and the associated energy cost savings, will be greatly enhanced with the dedicated time of a City Staff member. All plans include a 0.5 FTE position (1.0 FTE cost estimated to be $60k per year). The expense for this position is included in the financial analyses, and the net cash flow for each plan. Essentially, the cost savings for the added fulltime position are funded by the plans with a positive cash flow. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Efficiency Coordinator (.5FTE) 3.0 -3.0 0.00 0.0 0.00 0.00 0.00 0.0 0.00 -9.00



A B C D E

n n n y y

Action Plan 66- Efficiency Coordinator (.5FTE)



(yes/no)

Net Capital Cost

O&M incremental

Cost

Annual Cost Savings


Simple Payback



66 Efficiency Coordinator (.5FTE) 2012 no no $0 $30,000 $0 0.00 0.0 NA ($595,622)

The implementation and monitoring of an aggressive GHG emissions reduction program, and the associated energy cost savings, will be greatly enhanced with the dedicated time of a City Staff member. All plans include a 0.5 FTE position (1.0 FTE cost estimated to be $60k per year). The expense for this position is included in the financial analyses, and the net cash flow for each plan. Essentially, the cost savings for the added fulltime position are funded by the plans with a positive cash flow. Measure Evaluation Scores

Measure NameCost

(relative) -3 to 3

Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



Efficiency Coordinator (.5FTE) 3.0 -3.0 0.00 0.0 0.00 0.00 0.00 0.0 0.00 -9.00



The follow measures have been identified as potential opportunities. However cost benefit data was not available at the time of this analysis. They are included for consideration in the future.

67- Swim Center Pay-per-use Showers (MCAP95) 68- City Hall HVAC Upgrade (MCAP) 69- City Hall Council Chambers HVAC Upgrade (MCAP) 70- City Hall West and East Wing HVAC Upgrades (MCAP) 71- City Hall HVAC and Lighting Occupancy Sensors (MCAP) 72- City Hall Daylighting (MCAP) 73- Community Center Energy Management System (ABAG EW/ HDR96) 74- Community Center Lighting Design and Controls (MCAP) 75- Cavanaugh Complex HVAC Variable Frequency Drives (MCAP) 76- Wastewater Treatment Plant and Partial Decommissioning of Existing Facility (Staff) 77- Reclaimed Water Initiatives (Staff)

95 Draft Plan: City of Petaluma Building Energy Efficiency and Greenhouse Gas Emission Reduction, David Williard, Sustainergy Systems, ABAG Energy Watch, Climate Protection Campaign, November 2008. 96 Petaluma ABAG EW Audit Report: Energy Audit Draft Report: City of Petaluma, HDR/Brown, Vence and Assocates and Energy Solutions, April 15, 2008



6.0 Summary and Conclusions A greenhouse gas (GHG) emissions reduction of 20% by 2015 can be achieved by a number of paths documented in this report. Each path, or Action Plan, is comprised of up to 40 individual measures. Each is evaluated for the financial costs and benefits they contribute to the overall strategy. The total “palette” of quantified opportunities includes 65 new measures to reduce energy consumption. The analysis model underpinning these results will be available for incorporating new information and technologies as they come available, as well as truing the analysis with monitored data. The comprehensive approach to addressing this goal allows the City to meet a number of related goals, including improving the long term financial health of Petaluma, reducing the budget vulnerability to future energy cost escalation, addressing the existing maintenance demands of aging equipment, and providing public demonstration of commitment and progress in the highly visible challenge of greenhouse gas emissions reduction. The information in this report allows the City to understand the challenges and opportunities available in reaching its goal. The evaluation matrix quantifies the many related issues not captured by the financial results or emissions reduction such as public visibility and the resolution of existing problems. The financial results provide information on the investment value of the various paths of action, along with the anticipated net cash flow over time. The ability to understand the complex context of greenhouse gas emissions reduction will allow policy makers to define expected outcomes and associated financial commitments to achieve those outcomes. This provides city staff the flexibility needed to effectively implement the policy. The individual measures within each plan may be delayed, modified or replaced as appropriate while remaining faithful to the policy directive. This flexibility will be essential given the dynamic nature of the regulatory environment and the rapidly evolving financial and technological opportunities in California. In summary, this analytical framework and report organizes the city’s data and documentation relating to energy efficiency and greenhouse gas emissions reduction. It is applied to the city goal of a 20% reduction of emissions below 2000 levels, presenting five strategies to meet this goal. The database and analytical framework supporting this work are available into the future as new information and opportunities (technical and financial) emerge for consideration.



7.0 Appendices 7.1 Basis for 2000 GHG Inventory

7.2 General Inputs and Assumptions

7.3 Action Plan Evaluations

7.4 Kenilworth Swim Center Recommendations

7.5 Building and Swim Center Efficiency Measures

7.6 ABAG Energy Watch Lighting Recommendations

7.7 Potable Water Pumping Data

7.8 Transit Bus Replacement Costs

7.9 Vehicle Lists with Measures

7.10 Solar Electric Production Assumptions

7.11 Fleet Fuel Cost Trend

7.12 Carbon Credits

7.13 Electric Vehicles

7.14 Commute Programs

7.15 Grease to Gas Augmentation of Digester Gas



7.1 Basis for 2000 GHG Inventory

kWh Therms Energy CostGasoline (gals/yr) Diesel eCO2 (tons)

BuildingsPT - City Hall & Engr Ofc & Lighting 677,296 14,684 112,892 256.2PT - Community Center 405,903 3,733 62,589 122.3PT - Airport 285,921 0 41,459 69.9PT - Police Facility 276,913 603 40,755 71.4PT - Muni Swim Pool 262,686 34,875 72,964 279.4PT - Corporation Yard 19,621 0 2,845 4.8PT - Marina Docks 188,001 0 27,260 46.0PT - Park Lights 14,189 0 2,057 3.5PT - Senior Citizen Center 56,617 778 8,987 18.6PT - Lucchesi Soccer Field 25,105 0 3,640 6.1PT - Elwood Center 65,379 3,911 13,391 40.1PT - Fire Station#1 47,572 2,273 9,171 25.7PT - Public Works and Transit Servic 0 0 0 0.0PT - Pedestrian Walkway 4,923 0 714 1.2PT - Cavanagh Complex 61,802 5,838 14,799 51.1PT - 690 Sonoma Mtn. Pkwy 0 0 0 0.0PT - Park 25,509 0 3,699 6.2PT - Tennis Courts 31,822 0 4,614 7.8PT - Fire Station#3 28,884 1,439 5,627 15.9PT - Fire Station#2 20,139 1,994 4,914 17.2PT - Concession Building 22,210 0 3,220 5.4PT - Museum 24,699 1,911 5,492 17.8PT - Boat Dock 23,381 0 3,390 5.7PT - McKenzie Ctr 4,722 0 685 1.2PT - Kenilworth Teen Center 7,732 0 1,121 1.9PT - Training Facility 28,108 892 4,968 12.4PT - Draw Bridge Office 7,988 0 1,158 2.0PT - Harbor Master's Building 11,358 541 2,188 6.1PT - Grandstand 15 0 2 0.0PT - Walnut Park Ctr 3,705 0 537 0.9PT - Draw Bridge 3,756 0 545 0.9PT - Carter Ballfield 9,839 0 1,427 2.4PT - Restrooms 3,096 263 712 2.4PT - 601 HAYES LN 0 0 0 0.0PT - 199 1st ST. 0 0 0 0.0PT - 212 LAVENDER LANE 0 0 0 0.0PT - REMOTE TELE EQUIP 860 0 125 0.2PT - Anode Rectifier 2100 Marina Ave 1,979 0 287 0.5PT - S/W CORNER E WASHINGTON & MCDOW 0 0 0 0.0PT - Polly Klaas Performing Arts Cen 8,703 631 1,893 6.0PT - Town Clock 1,260 0 183 0.3PT - Flood Control Monitor 0 0 0 0.0PT - Ball Park 619 0 90 0.2PT - 1853 INGRAM WAY 0 0 0 0.0PT - 1827 SLEEPY HOLLOW LN 0 0 0 0.0PT - Bus Stop 0 0 0 0.0PT - Cajun moon restaraunt 0 0 0 0.0PT - VISIT CNTR 0 0 0PT - SHOP MC DOWELL 6170 18,630 97 2,798 5.2PT - 202 N MCDOWELL BLVD 0 0 0 0.0PT - Office - 840 Hopper St. 0 0 0 0.0PT - 8 JESS AVE 0 0 0 0.0Total 2,680,942 74,463 $360,960 1,114.9

City of Petaluma Greenhouse Gas Inventory(Based on PG&E billing information and data received from City Staff

Baseline Year 2000

Table 19: 2000 Greenhouse Gas Inventory (Part 1)



kWh Therms Energy CostGasoline (gals/yr) Diesel eCO2 (tons)

StreetlightsPT - Streetlights 1,951,695 0 282,996 477.2PT - Traffic Signal 699,963 0 101,495 171.1Total 2,651,658 0 $299,624 648.3

Water/SewerPT - Hopper St. Sewer 2,189,139 0 317,425 535.2PT - Small Pumps 2,312,927 20 335,394 565.6PT - Waste Water 0 0 0 0.0PT - Lakeville Hwy Ag Pump 2,978,212 0 431,841 728.2PT - Booster pmp 0 0 0 0.0PT - City Pumping Plant @ 2 C St. 102,223 0 14,822 25.0PT - Pump Control Station 3,222 0 467 0.8PT - City Sewer Pump @ Wilmington 68,302 0 9,904 16.7PT - Irrigation 36,558 0 5,301 8.9PT - Flood Control 40 0 6 0.0PT - Sewer Pump Station@Petaluma Blv 3,045 0 442 0.7PT - City Water Storage Manor Ln. 1,180 0 171 0.3PT - Sewer Treatment Plan 0 0 0 0.0Total 7,694,848 20 $869,479 1,881.5

CommuteGasoline and Diesel 55,263 6,140 636.6Total 0 55,263 6,140 636.6FleetGasoline 319,877 103,993 1,076.8Diesel 116,007 37,714 395.4Total 246,800 103,993 37,714 1,472.0WastePaper Products -154.0Food Waste 39.0Plant Debris -151.0Wood/Textiles -55.0Total -321.0Grand Total 13,027,448 74,483 1,776,863 159,256 43,855 5,433.0

City of Petaluma Greenhouse Gas Inventory(Based on PG&E billing information and data received from City Staff

Baseline Year 2000

Table 20: 2000 Greenhouse Gas Inventory (Part 2)



7.2 General Inputs and Assumptions City of Petaluma Report Data

Base year: 2008 Baseline year: 2000 Results

Year 2015 Last Action Year 2015

Positive Action Margin

6

Diminishing Potential

Assumption (% per year)

30%

Gasoline CA Low Carbon

Goal: Reduction by

2020

10%

MetricStandard Default Values

Revised Values

Default Values Used in Analysis

Include Power Mix Changes

(Y/N)

y

Include Vehicle

Gasoline CO2e

Changes

y

Include Vehicle

Diesel CO2e Changes

y

Diesel CA Low Carbon Fuel Goal:

Reduction by 2020

10%

Power Mix

Coeffient

Used in Analysis 50% % of

Projected

Vehicle Gasoline

CO2e Coefficient


Projected

Vehicle Diesel CO2e Coefficient


Projected

Term of Analysis (yrs) 25 25 1990 0.566 0.566 1990 20.709 20.709 1990 20.968 20.968

Term of Financing (yrs) 10 5 5 1991 0.558 0.558 1991 20.709 20.709 1991 20.968 20.968

Discount Rate 5.00% 5.00% 1992 0.551 0.551 1992 20.709 20.709 1992 20.968 20.968

kWh Energy Cost Escalation Rate 3.50% 3.50% 1993 0.543 0.543 1993 20.709 20.709 1993 20.968 20.968

Nat Gas Energy Cost Escalation Rate 3.50% 3.50% 1994 0.535 0.535 1994 20.709 20.709 1994 20.968 20.968

Vehicle Fuel Cost Inflation Rate 7.80% 7.80% 1995 0.528 0.528 1995 20.709 20.709 1995 20.968 20.968

Energy Cost ($/kWh) $0.145 $0.145 1996 0.520 0.520 1996 20.709 20.709 1996 20.968 20.968

Energy Cost ($/Therm) $1.000 1.000 1997 0.512 0.512 1997 20.709 20.709 1997 20.968 20.968

Interest Rate 3.95% 3.95% 1998 0.504 0.504 1998 20.709 20.709 1998 20.968 20.968

Inflation Rate 3.50% 3.50% 1999 0.497 0.497 1999 20.709 20.709 1999 20.968 20.968

2000 0.489 0.489 2000 20.709 20.709 2000 20.968 20.968

Conversions 2001 0.489 0.489 2001 20.709 20.709 2001 20.968 20.968

CO2/kWh (lbs.) 0.489 0.489 2002 0.489 0.489 2002 20.709 20.709 2002 20.968 20.968

CO2/Therm (#/Therm) 12.34 12.34 2003 0.489 0.489 2003 20.709 20.709 2003 20.968 20.968

CO2e Gasoline 20.7 20.7 lbs/gal 2004 0.489 0.489 2004 20.709 20.709 2004 20.968 20.968

CO2e Diesel 21.0 21.0 lbs/gal 2005 0.489 0.489 2005 20.709 20.709 2005 20.968 20.968

BioDiesel 0 5.242 5.242 lbs/gal (recycled stock) 2006 0.489 0.489 2006 20.709 20.709 2006 20.968 20.968

Ethanol 12.23 12.23 lb/gal for 100% ethanol 2007 0.489 0.489 2007 20.709 20.709 2007 20.968 20.968

2008 0.489 0.489 2008 20.709 20.709 2008 20.968 20.968

$/gal Gasoline $3.08 $3.08 2009 0.480 0.470 2009 20.536 20.536 2009 20.793 20.793

$/gal Diesel $3.08 $3.08 2010 0.470 0.451 2010 20.364 20.364 2010 20.619 20.619

$/gal Biodiesel $3.38 $3.38 2011 0.461 0.432 2011 20.191 20.191 2011 20.444 20.444

$/gal Ethanol (equivalent gallon) $4.00 $4.00 2012 0.451 0.413 2012 20.019 20.019 2012 20.269 20.269

$/Therm CNG Vehicles $1.00 $1.00 2013 0.442 0.394 2013 19.846 19.846 2013 20.094 20.094

$/kWh Electric Vehicles $0.145 $0.145 2014 0.432 0.375 2014 19.674 19.674 2014 19.920 19.920

Electric Vehicle Mileage 0.3 0.3 kWh/mile mid size 2015 0.423 0.356 2015 19.501 19.501 2015 19.745 19.745

Electric Vehicle Mileage 0.2 0.2 kWh/mile subcompact 2016 0.413 0.338 2016 19.328 19.328 2016 19.570 19.570

Target (% of 2000) 20.0% 20.0% 2017 0.404 0.321 2017 19.156 19.156 2017 19.395 19.395

2018 0.395 0.305 2018 18.983 18.983 2018 19.221 19.221

PPA Initial % Increase over Utility kWh 5.00% 5.00% 2019 0.387 0.289 2019 18.811 18.811 2019 19.046 19.046

PPA Energy Cost Escalation Rate 3.50% 3.50% 2020 0.378 0.275 2020 18.638 18.638 2020 18.871 18.871

2021 0.370 0.261 2021 18.638 18.638 2021 18.871 18.871

2022 0.362 0.247 2022 18.638 18.638 2022 18.871 18.871

Additional Factors 2023 0.354 0.235 2023 18.638 18.638 2023 18.871 18.871

TOU Factor 1 1 Used of PV financial analysis 2024 0.346 0.223 2024 18.638 18.638 2024 18.871 18.871

CNG conversion cost $5,000 $5,000 2025 0.338 0.212 2025 18.638 18.638 2025 18.871 18.871

CNG Equipment $150,000 $150,000 2026 0.331 0.201 2026 18.638 18.638 2026 18.871 18.871

Job Creation: Jobs/$1m 17.00 17.00 Fed Stimulus methodology 2027 0.324 0.191 2027 18.638 18.638 2027 18.871 18.871

GHG Units (short or metric tons) metric metric 2028 0.316 0.181 2028 18.638 18.638 2028 18.871 18.871

Conversion to tons (short or MMT) 2204.6 2204.60 lbs/metric ton (1kg) 2029 0.309 0.172 2029 18.638 18.638 2029 18.871 18.871

2030 0.303 0.163 2030 18.638 18.638 2030 18.871 18.871

2031 0.296 0.155 2031 18.638 18.638 2031 18.871 18.871

2032 0.290 0.147 2032 18.638 18.638 2032 18.871 18.871

2033 0.283 0.140 2033 18.638 18.638 2033 18.871 18.871

2034 0.277 0.133 2034 18.638 18.638 2034 18.871 18.871

2035 0.271 0.126 2035 18.638 18.638 2035 18.871 18.871

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7.3 Action Plan Evaluations

The GHG Emission Reduction Action Plans involve more than CO2e reduction and cash flow. There are critical concerns that should be factored into the decision making process. These include the financial metrics of internal rate of return (IRR) and net present value (NPV) used to evaluate the worthiness of the investment; the cost of implementing the measure, some measures come with a large price tag which will challenge liquidity; the degree to which the plan resolves existing problems, such as old, high maintenance air conditioning units; the visibility of the measures to the public, for example the photovoltaic systems are a physical example of actions taken the City and communicate action and commitment to the community. Other key considerations include the employee impacts of new equipment or procedures, which may generate internal opposition; and the impact on the variability of future energy costs and the associated budgetary vulnerability.


• Measure Capital Cost: • Financial Metrics (IRR and NPV) • Resolution of Existing Problems • GHG Impact • Public Visibility • Employee Impact • Community Impact • Energy Cost Stabilization

Table 21 below provides the evaluation results for each measure by individual criteria. The individual scores for each category (cost, financial metrics, etc) are summed to provide an overall score for that measure. While this table provides important information to be considered when selecting measures, the scores are advisory only. A relatively low score does not preclude a measure, nor should a high score guarantee inclusion of the measure in the Action Plans. There will always be additional considerations that are not reflected in the Selection Evaluation process. The “adjusted measure score” reflects the relative weighting of the evaluation criteria as presented in Table 21 below.


Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)


total=24

2 5 2 3 4 2 2 4 24

Table 21: Evaluation Criteria Weighting



Measure Number Measure Name


Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



29 Grease to Gas Methane Program -3.0 3.0 6.00 6.0 3.00 -1.00 2.00 6.0 22.00 77.00

38 Bus Fleet A -3.0 3.0 0.00 6.0 5.00 0.00 0.00 6.0 17.00 71.00

39 Bus Fleet B -3.0 2.1 0.00 6.0 5.00 0.00 0.00 6.0 16.12 66.61

32 Streetlighting C: Turn off 50% of Residential (non intersection) lighting -1.0 3.0 0.00 4.7 5.00 -1.00 -2.00 6.0 14.72 65.19

33 Streetlighting D: Turn off 50% of Residential (non intersection) lighting -1.0 3.0 0.00 4.6 5.00 -1.00 -2.00 6.0 14.53 64.62

40 Fleet Replacement Strategy A (includes Nissan Elec) -3.0 2.0 0.00 6.0 4.00 -1.00 0.00 6.0 14.04 60.21

9 K. Swim Center Closure 50% Days 1.8 3.0 0.00 6.0 3.00 -3.00 -3.00 5.8 13.55 59.61

41 Fleet Replacement Strategy B (includes Nissan Elec) -3.0 1.9 0.00 6.0 4.00 -1.00 0.00 6.0 13.87 59.33


-2.7 3.0 0.00 1.9 6.00 0.00 0.00 4.8 12.99 58.38

37 4 day work week (Building) 1.8 3.0 2.00 1.8 3.00 1.00 -2.00 3.0 13.66 50.21

4 K.Swim Center Pool Covers Repl. MCAP 2.5 3.0 0.00 2.9 3.0 0.0 0.0 2.0 13.32 48.44

30 Streetlighting A: 50% Conversion HPS to LED (or equiv.) -3.0 2.1 0.00 1.4 3.00 1.00 0.00 6.0 10.48 46.70

31 Streetlighting B: 50% Conversion HPS to LED (or equiv.) -3.0 2.1 0.00 1.3 3.00 1.00 0.00 6.0 10.47 46.69

59 PV 1.0 MWac -3.0 -3.0 0.00 6.0 6.00 0.00 0.00 6.0 12.00 45.00

60 PV 2.0 MWac -3.0 -3.0 0.00 6.0 6.00 0.00 0.00 6.0 12.00 45.00

26 Retrofit Frates Pumps (Zone 4) 2.2 2.3 1.00 0.2 6.00 0.00 0.00 0.4 12.02 43.85

3 K.Swim Center VFD MCAP 2.4 3.0 0.00 4.4 0.0 0.0 0.0 2.4 12.21 42.59

54 PV 1.0 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00

55 PV 2 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00

56 PV 1.0 MWac (PPA) 0.0 -3.0 0.00 6.0 6.00 0.00 0.00 3.0 9.00 39.00

58 PV .5 MWac -3.0 -3.0 0.00 3.9 6.00 0.00 0.00 6.0 9.93 38.78

52 Fleet Management Software Linked to Fleet Replacement A -3.0 1.0 3.00 1.0 4.00 0.00 0.00 3.7 9.63 38.53

36 4 day work week (Commute) 3.0 3.0 2.00 0.9 3.00 1.00 -2.00 0.0 10.93 37.79

53 Fleet Management Software Linked to Fleet Replacement B -3.0 1.0 3.00 0.9 4.00 0.00 0.00 3.6 9.41 37.72

12 Cavn. Cntr Supplimental Solar Watr Heating EEM-7 2.7 1.2 0.00 0.1 6.0 0.0 0.0 0.1 10.04 35.77

7 K. Swim Cnter High Eff. Condensing Boilers EEM-3 -1.9 1.1 0.00 1.5 6.0 0.0 0.0 1.1 7.87 34.81

57 PV .5 MWac (PPA) 0.0 -3.0 0.00 4.0 6.00 0.00 0.00 3.0 7.01 33.04

5 K. Swim Cntr Opt. Operation Pool Pumps and Filtration EEM-1 2.6 3.0 1.00 0.6 0.0 1.0 0.0 1.5 9.70 32.04

20 Corporation Yard Lighting Retrofit ABAG EW 2.8 3.0 2.00 0.1 1.00 1.00 0.00 0.2 10.00 31.37

2 K.Swim Center Solar Thermal Expansion MCAP -3.0 0.6 2.00 6.0 1.00 2.00 0.00 0.9 9.53 30.71

27 Petaluma Aqueduct supplying Zone 4 -3.0 0.7 0.00 0.6 6.00 0.00 0.00 1.8 6.13 30.66

23 Senior Center Lighting Retrofit ABAG EW 2.8 3.0 2.00 0.0 0.00 1.00 0.00 0.1 9.02 27.34

22 Elwood Cntr Soup Kitchen Lighting Retrofit ABAG EW 2.9 3.0 2.00 0.0 0.00 1.00 0.00 0.1 9.05 27.28

Table 22: Measure List and Evaluations A



Measure Number Measure Name


Financial Metrics

(relative)


(cumulative) 0 to 6



(cumulative)

Employee Impact

(relative)

Community Impact

(relative)



24 Airport Lighting Retrofit ABAG EW 2.6 2.4 2.00 0.1 0.00 1.00 0.00 0.2 8.31 24.44

25 Vending Machine Controls 2.8 3.0 0.00 0.2 0.00 0.00 0.00 0.6 6.70 23.87

6 K. Swim Cnter Premium Efficiency Motors EEM-2 2.8 3.0 0.00 0.2 0.0 0.0 0.0 0.5 6.50 23.15

19 Animal Shelter Lighting Retrofit ABAG EW 2.9 2.1 2.00 0.0 0.00 1.00 0.00 0.1 8.08 22.72

10 Cavn. Cntr Opt. Operation Pool Pumps and Filtration EEM-5 2.7 2.4 1.00 0.1 0.0 1.0 0.0 0.2 7.37 22.41

21 Cavn. Cntr Lighting Retrofit ABAG EW 2.8 2.0 2.00 0.0 0.00 1.00 0.00 0.1 7.90 22.04

8 K. Swim Cnter Supplimental Solar Wtr Heating EEM-4 (Excl to #1,2,7,16) 2.3 2.2 0.00 0.5 0.0 0.0 0.0 0.3 5.31 18.29

1 K. Swim Center Solar Thermal Repair MCAP (Excl to #2,7,8,16) -3.0 0.7 2.00 6.0 0.00 -1.00 0.00 0.0 4.73 17.64

14 City Hall, Com Cntr, Police Dept. SBEA Lighting Measures 0.4 0.0 2.00 0.9 0.0 0.0 0.0 1.9 5.17 15.09

13 Cavn. Cntr Install Cool Roof EEM-8 2.6 1.5 0.00 0.0 0.0 0.0 0.0 0.1 4.27 13.27

18 Luchessi Cmnty Cntr Install Cool Roof EEM-10 (Excl to 17) 2.6 1.4 0.00 0.0 0.00 0.00 0.00 0.1 4.12 12.69

51 Biodiesel 99% linked to Fleet B -0.5 -3.0 0.00 6.0 3.00 -1.00 0.00 0.0 4.46 11.92

50 Biodiesel 99% linked to Fleet A -0.6 -3.0 0.00 6.0 3.00 -1.00 0.00 0.0 4.37 11.74

45 Biodiesel 99% 0.0 -3.0 0.00 5.6 3.00 -1.00 0.00 0.0 4.56 11.69

16 Police Facility HVAC Upgrade ABAGEW / HDR EEM-2 -3.0 0.4 0.00 0.3 3.00 0.00 0.00 0.6 1.34 11.53

62 K.Swim Center 80 kWac PV System MCAP -3.0 -3.0 0.00 0.7 6.00 0.00 0.00 1.6 2.21 11.19

11 Cavn. Cntr Premium Efficiency Pool Pump Motors EEM-6 3.0 0.6 0.00 0.0 0.0 0.0 0.0 0.0 3.57 8.94

63 City Hall PV System 50kWac -3.0 -3.0 0.00 0.4 6.00 0.00 0.00 1.0 1.42 8.30

61 Community Center 41 kWac PV MCAP -3.0 -3.0 0.00 0.3 6.00 0.00 0.00 0.8 1.17 7.32

15 Police Facility Energy Management System MCAP 0.7 0.7 0.00 0.2 0.0 0.0 0.0 0.3 1.93 6.78

42 Electric Vehicles (Nissan 28 Vehicles) -3.0 -2.7 0.00 0.6 6.00 -1.00 0.00 0.6 0.53 6.77

64 Public Works PV System 25.3 kWac -3.0 -3.0 0.00 0.2 6.00 0.00 0.00 0.5 0.70 5.59

49 Biodiesel 50% linked to Fleet B -0.5 -3.0 0.00 4.7 2.00 -1.00 0.00 0.0 2.13 3.93

17 Luchessi Cmty Cntr HVAC Upgrade EEM-9 (Excl to 18) -3.0 0.5 0.00 0.4 0.00 0.00 0.00 1.1 -0.96 2.27

48 Biodiesel 50% linked to Fleet A -0.6 -3.0 0.00 5.2 1.00 -1.00 0.00 0.0 1.57 1.34

34 Commute 1 2.5 -3.0 0.00 2.2 0.00 2.00 0.00 0.0 3.68 0.53

35 Commute 2 2.5 -3.0 0.00 2.2 0.00 2.00 0.00 0.0 3.68 0.53

44 Biodiesel 50% 0.0 -3.0 0.00 2.8 2.00 -1.00 0.00 0.0 0.81 -0.57

46 Biodiesel 20% linked to Fleet A 3.0 -3.0 0.00 2.1 1.00 -1.00 0.00 0.0 2.08 -0.76

47 Biodiesel 20% linked to Fleet B 3.0 -3.0 0.00 1.9 1.00 -1.00 0.00 0.0 1.87 -1.39

43 Biodiesel 20% 3.0 -3.0 0.00 1.1 1.00 -1.00 0.00 0.0 1.12 -3.63

65 Efficiency Coordinator (.5FTE) 3.0 -3.0 0.00 0.0 0.00 0.00 0.00 0.0 0.00 -9.00

66 Efficiency Coordinator (.5FTE) 3.0 -3.0 0.00 0.0 0.00 0.00 0.00 0.0 0.00 -9.00 Table 23: Measure List and Evaluations B



The table below compiles the scoring for each measure included in each plan and yields a relative score for each metric. As with the previous table, a higher score indicate more a more favorable evaluation for that metric or plan. Plan C, for example scores high on “Financial Metrics” but scores low on “Public Visibility” and scores below Plans D and E overall. The category weighting has been integrated into these numbers as well as an integration factor to allow the aggregation of the relative and comprehensive values.97

Metric \ Plan A B C D E

Cost -13.7 24.8 38.6 42.0 25.1

Financial Metrics -88.6 147.9 145.5 126.7 115.4

Resolution of Existing Problem 4.5 17.4 22.6 22.6 22.6

GHG Impact 47.7 51.9 47.9 60.5 64.4

Public Visibility 81.5 99.6 81.5 125.2 147.9

Employee Impact 2.0 12.0 20.0 18.0 26.0

Community Impact -8.0 -18.0 -4.0 -12.0 -4.0

Energy Cost Stabilization 53.7 78.6 64.4 83.5 94.6

Total 79.2 414.1 416.5 466.6 492.0

Plan Scoring

Table 24: Plan Evaluation Results

This analysis is intended to provide an overview of the effectiveness of each plan. While it should encourage a more comprehensive review of the cost/benefits of each strategy, these quantitative results are based on subjective judgments and are advisory only. They should be only one consideration in the selection of the most appropriate plan for the City of Petaluma.

97 A factor of 0.38 was applied to the results of the “cumulative” metrics to equalize the scale of results for the two types of scoring (relative and cumulative).



7.4 Kenilworth Swim Center Recommendations98 Kenilworth Swim Center EEM-1: Optimize Operation of Pool Filtration/Circulation Pump The circulation pump runs continuously at full speed for 24 hours a day, 365 days a year even though the pools are in use from March through October during the hours from about 5:00 a.m. to roughly 9:00 p.m.

It is possible to reduce the flow rates during non-peak use and unoccupied hours and still maintain water quality and clarity.

The current State health regulations for pools, CCR Title 22, Division 4, Chapter 20 state:

‘The pumps, filters, disinfectant and chemical feeders, flow indicators, gauges and all related parts of the pool water purification system shall be kept in operation whenever the pool is available for use, and at such additional times and periods as may be necessary to maintain the water in the pool in a clear and disinfected condition. The variation in flow during a filtration cycle shall be such as to not reduce the flow below 65 percent of the rate required in Section 2-9032 of Title 24, California Administrative Code.’

The Department of Health Services (DHS) is working with the California Conference of Directors of Environmental Health to revise the existing public swimming pool regulations (Title 22). The proposed revisions state that during operating hours plus two hours before and two hours after the filtration pump must operate at no less that 75% of pumping rate to maintain required water changes per hour. During the remaining hours the pumping must be sufficient to keep the water in a clear and disinfected condition.

We recommend installing a controller that cycles the pump at night and installing a variable frequency drive (VFD) on the pump motor so that the pump flow rate can be varied over the day. During pool operating hours, it should be possible to vary the operation of pump between 75% and 100% of its rated full speed, assuming the pump is designed to deliver required water changes per hour at full output. The pump could be set to run at 75% flow during most operating hours and then ramp up automatically to 100% when the outside air dry-bulb temperature is above 80 degrees Fahrenheit (when it is assumed that most of the chemical deterioration occurs and it is more likely to have higher occupancies). The controller can be overridden for known times of high occupancy such as a swim team practice or swim meets. Outside of these hours, operate the pump at full speed periodically, such as for 30 minutes every two hours, in order to maintain the clear and disinfected condition of the pool water. This rate of cycling and VFD reduction should be tested and reduced or increased if needed to achieve clear water when the pools open. This measure would require installation of a VFD on the pump motor, a temperature sensor, and a local programmable controller. The operating regime will meet the requirements of the existing and proposed versions of the health code.

An alternative approach that would save less energy but would also be less expensive would be to simply cycle the pump at night on a timer and not attempt to vary the pump flow rate during the day. This would not require installing a VFD.




7.5 Building and Swim Energy Efficiency Measures99




7.6 ABAG Energy Watch Lighting Recommendations ABAG EW lighting recommendations100 City of Petaluma - Cavanaugh Center Data Entry incentive level: $0.20

Audit Conducted 1/17/2008 Calculated Cells, some partially manual $0.133

Lighting Retrofit Recommendations Linked to Fixture Code Sheet adder for reduced AC l 5.00% 15 years for long-term

Linked to Hours Codes Sheet

Savings Notes

Ref No Room Name room type Fixture Code Fixture Type

QTY Watts Total kW Hours Pre Total KWH

Retrofit Descriptio

QTY Watts Hours Post

Total kW Total KWH

kW Saved kWH Saved

Total $ Saved

Total $ Saved

Total Unit Total Cost Unit Rebate

Total Rebate

Extended cost

payback with AC savings

Long Term

1 Main Hallway Entrance lobby A1

2x4 recessed

fixture with

1 72 0.072 2000 144 2F32T8L 1 48 2000 0.048 96 0.024 48 $6.38 $6.70 $41 $41.00 $9.60 $9.60 $31.40 4.68 $69

2 Main Hallway Entrance lobby A2

4 wrap with

2F40T12s

1 72 0.072 2000 144 2F32T8L 1 48 2000 0.048 96 0.024 48 $6.38 $6.70 $41 $41.00 $9.60 $9.60 $31.40 4.68 $69

3 Main Recreation

open ofc.area B1

100 W Metal Halide

7 125 0.875 2000 1750 new hooded

7 54 2000 0.378 756 0.497 994 $132.20 $138.81 $110 $770.00 $28.40 $198.80 $571.20 4.11 $1,511

4 Storage Closet storage C1

75W Incandesc

ent

1 75 0.075 500 37.5 18W screw-in

1 18 500 0.018 9 0.057 29 $3.79 $3.98 $9 $9.00 $5.70 $5.70 $3.30 0.83 $56

5 Kitchen kitchen (main) A3

8 strip with

2F96T12s

2 128 0.256 1000 256 2F32T8H & socket

2 73 1000 0.146 146 0.11 110 $14.63 $15.36 $55 $110.00 $11.00 $22.00 $88.00 5.73 $142

6 Side Recreation

open ofc.area A3

8 strip with

2F96T12s

2 128 0.256 2000 512 2F32T8H & socket

2 73 2000 0.146 292 0.11 220 $29.26 $30.72 $55 $110.00 $22.00 $44.00 $66.00 2.15 $395

7 Side Recreation

open ofc.area A4

4 hooded industrials

with

1 72 0.072 2000 144 2F32T8L 1 48 2000 0.048 96 0.024 48 $6.38 $6.70 $41 $41.00 $9.60 $9.60 $31.40 4.68 $69

8 Side Recreation

open ofc.area B1

100 W Metal Halide

1 125 0.125 2000 250 new hooded

1 54 2000 0.054 108 0.071 142 $18.89 $19.83 $110 $110.00 $28.40 $28.40 $81.60 4.11 $216

9 Hallway to Computer corridor C3 60W

Incandesc1 60 0.06 2000 120 15W

screw-in 1 15 2000 0.015 30 0.045 90 $11.97 $12.57 $9 $9.00 $18.00 $18.00 -$9.00 (0.72) $198

10 Computer Room classroom

B1100 W Metal Halide

1 125 0.125 2000 250 new hooded

industrial

1 54 2000 0.054 108 0.071 142 $18.89 $19.83 $110 $110.00 $28.40 $28.40 $81.60 4.11 $216 Computer room is very dim

11 Computer Room classroom

A62x4 wrap

with 2 F32T8s

1 58 0.058 2000 116 2F32T8L 1 48 2000 0.048 96 0.01 20 $2.66 $2.79 $41 $41.00 $4.00 $4.00 $37.00 13.25 $5

12 Women's Restroom

public restroom

A56"x4' wrap

with 2 F40T12s

2 72 0.144 1500 216 1F32T8H 2 38 1500 0.076 114 0.068 102 $13.57 $14.24 $37 $74.00 $10.20 $20.40 $53.60 3.76 $160

13Side "Club

Room" adjacent to classroom

A24' wrap

with 2F40T12s

4 72 0.288 2000 576 2F32T8L 4 48 2000 0.192 384 0.096 192 $25.54 $26.81 $41 $164.00 $9.60 $38.40 $125.60 4.68 $277

14 Hallway to Office corridor C2 130W

Incandesc2 130 0.26 2000 520 32W

screw-in 2 32 2000 0.064 128 0.196 392 $52.14 $54.74 $9 $18.00 $39.20 $78.40 -$60.40 (1.10) $882

15 Hallway Closet

supply room C1 75W

Incandesc1 75 0.075 500 37.5 18W

screw-in 1 18 500 0.018 9 0.057 29 $3.79 $3.98 $9 $9.00 $5.70 $5.70 $3.30 0.83 $56

16 Private Office individual office A2 4' wrap

with 1 72 0.072 2000 144 2F32T8L 1 48 2000 0.048 96 0.024 48 $6.38 $6.70 $41 $41.00 $9.60 $9.60 $31.40 4.68 $69

17 Gym gym B4 400 W Metal

12 455 5.46 1200 6552 new fluorescen

12 226 1200 2.712 3254.4 2.748 3,298 $438.58 $460.51 $270 $3,240.00 $54.96 $659.52 $2,580.48 5.60 $4,327 hibay 25 ft ceilings

18 Gym entry way corridor C3 60W

Incandesc3 60 0.18 2000 360 15W

screw-in 3 15 2000 0.045 90 0.135 270 $35.91 $37.71 $9 $27.00 $18.00 $54.00 -$27.00 (0.72) $593

TOTALS 44 8.5 12,129 44 4 5,908 4.4 6,221 $827 $869 $4,965 $1,244 $3,721 4.28 $9,310

CostsExisting Fixture Retrofit Description

average KWH rate




City of Petaluma - Soup Kitchen Data Entry incentive level: $0.20


Lighting Retrofit Recommendations Linked to Fixture Code Sheet adder for reduced AC 5% 15years for long-term benefit (excluding


Savings Notes

Ref No Room Name room type Fixture Code Fixture

TypeQTY Watts Total kW Hours Pre Total

KWHRetrofit

DescriptioQTY Watts Hours

PostTotal kW Total

KWHkW Saved kWH

Saved Total $ Saved

Total $ Saved


Total Rebate

Extended cost

payback with AC

Long Term

1 Main Dining lobby A1 8' strip

with 7 128 0.896 4380 3924.48 2F32T8H

& 8' strip 7 73 4380 0.511 2238.18 0.385 1,686 $224.28 $235.49 $68 $476.00 $48.18 $337.26 $138.74 0.59 $3,394

14 ft high ceiling

2 Storage Rooms storage B1 4'x1' wrap

with 2 1 58 0.058 500 29 2F32T8L 1 48 500 0.048 24 0.01 5 $0.67 $0.70 $41 $41.00 $1.00 $1.00 $40.00 57.29 -$30

refrigerated.

3 Storage Rooms storage B1

4 x1 wrap with 2 F32T8

1 58 0.058 500 29 2F32T8L 1 48 500 0.048 24 0.01 5 $0.67 $0.70 $41 $41.00 $1.00 $1.00 $40.00 57.29 -$30

4 Storage Room storage C1

4 hooded industrial

with

2 72 0.144 500 72 2F32T8L 2 48 500 0.096 48 0.048 24 $3.19 $3.35 $41 $82.00 $2.40 $4.80 $77.20 23.03 -$27

5 Main Indoor

supply room A1

8 strip with

2F96T12

3 128 0.384 2000 768 2F32T8H & 8' strip

3 73 2000 0.219 438 0.165 330 $43.89 $46.08 $68 $204.00 $22.00 $66.00 $138.00 2.99 $553

6 Main Indoor

supply room D1

4 strip with

2F32T8

1 58 0.058 2000 116 2F32T8L 1 48 2000 0.048 96 0.01 20 $2.66 $2.79 $41 $41.00 $4.00 $4.00 $37.00 13.25 $5

7 Cleaning Supply

janitors room E1

Wall mounted

fixture with

1 60 0.06 500 30 15 W CFL 1 15 500 0.015 7.5 0.045 23 $2.99 $3.14 $9 $9.00 $4.50 $4.50 $4.50 1.43 $43

8 Kitchen kitchen (main) B1


4 58 0.232 4000 928 2F32T8L 4 48 4000 0.192 768 0.04 160 $21.28 $22.34 $41 $164.00 $8.00 $32.00 $132.00 5.91 $203

9 Kitchen kitchen (main) E1

Wall mounted

fixture with

1 60 0.06 4000 240 15 W CFL 1 15 4000 0.015 60 0.045 180 $23.94 $25.14 $9 $9.00 $36.00 $36.00 -$27.00 (1.07) $404

10 Walk-in fridge storage E3

Wall mounted

fixture with

1 75 0.075 500 37.5 18 W CFL 1 18 500 0.018 9 0.057 29 $3.79 $3.98 $9 $9.00 $5.70 $5.70 $3.30 0.83 $56

11 Restroom corridor B1


1 58 0.058 4380 254.04 2F32T8L 1 48 4380 0.048 210.24 0.01 44 $5.83 $6.12 $41 $41.00 $8.76 $8.76 $32.24 5.27 $60

12 Women's Restroo

public restroom E1

Wall mounted

fixture with

2 60 0.12 3500 420 15 W CFL 2 15 3500 0.03 105 0.09 315 $41.90 $43.99 $9 $18.00 $31.50 $63.00 -$45.00 (1.02) $705

13 Men's Restroo

public restroom E1 Wall

mounted 2 60 0.12 3500 420 15 W CFL 2 15 3500 0.03 105 0.09 315 $41.90 $43.99 $9 $18.00 $31.50 $63.00 -$45.00 (1.02) $705

14 Private Office office

E2Wall

mounted fixture with

1 240 0.24 3000 720 42 W CFL 1 42 3000 0.042 126 0.198 594 $79.00 $82.95 $9 $9.00 $118.80 $118.80 -$109.80 (1.32) $1,354 Lots of windows and natural light

152nd

Indoor Storage

supply room

B24' wrap with 2

F34T12

1 72 0.072 2000 144 2F32T8L 1 48 800 0.048 38.4 0.024 106 $14.04 $14.75 $41 $41.00 $21.12 $21.12 $19.88 1.35 $201

162nd

Indoor Storage

supply room

A1os8' strip

with 2F96T12

1 128 0.128 2000 256 2F32T8H & 8' strip

and

1 73 800 0.073 58.4 0.055 198 $26.28 $27.59 $144 $144.00 $39.52 $39.52 $104.48 3.79 $309

172nd

Indoor Storage

supply room

C34' hooded industrial

with

1 116 0.116 2000 232 2F32T8H 1 73 800 0.073 58.4 0.043 174 $23.09 $24.24 $45 $45.00 $34.72 $34.72 $10.28 0.42 $353

TOTALS 31 2.9 8,620 31 2 4,414 1.3 4,206 $559 $587 $1,392 $841 $551 0.94 $8,259

average KWH rate

Existing Fixture Retrofit Description Costs

Install wall-mounted occupancy sensor

(shared by all 3 fixtures in this room. Cost has

been added to measure ref. #16)



City of Petaluma - Senior Center and PPSC Data Entry incentive level $0.20


Lighitng Retrofit Recommendations Linked to Fixture Code Sheet adder for reduced AC 5.00% 15years for long-term benefit (excluding

Assuming 4100 Kelvin Retrofit Linked to Hours Codes Sheet

Savings Notes

Ref No Floor Dept Room Name room type Fixture

Code Fixture Type QTY Watts Total kW Hours Pre Total KWH

Retrofit Descriptio

QTY Watts Hours Post

Total kW Total KWH

kW Saved kWH Saved

Total $ Saved

Total $ Saved


Total Rebate

Extended cost

payback with AC

Long Term

Performed retrofit approximately 2 years

1 PPSC PPSC - Café ppsc B1 2x4 lensed troffer

with 2 F34T12 1 72 0.072 2500 180 2F32T8L 1 48 2500 0.048 120 0.024 60 $7.98 $8.38 $41 $41.00 $12.00 $12.00 $29.00 3.46 $97

2 PPSC PPSC - Café ppsc E1 4' wrap with 2

F34T12 12 72 0.864 2500 2160 2F32T8L 12 48 2500 0.576 1440 0.288 720 $95.76 $100.55 $41 $492.00 $12.00 $144.00 $348.00 3.46 $1,160

3 PPSCPPSC - Café's

restroomppsc C1 4' strip with

2F34T12 1 72 0.072 2500 1801F32T8H (right or left side)

1 38 2500 0.038 95 0.034 85 $11.31 $11.87 $41 $41.00 $17.00 $17.00 $24.00 2.02 $154

4 PPSCExit

Signs exit sign G1 Incandescent Exit Sign 2 40 0.08 8760 700.8

LED Exit sign w/ battery

2 5 8760 0.01 87.6 0.07 613 $81.56 $85.63 $60 $120.00 $61.32 $122.64 -$2.64 (0.03) $1,287

5 PPSC Food Storage ppsc B2 1x4 lensed troffer

with 2 F34T12 4 72 0.288 2500 7201F32T8H (centering

kit and 4 38 2500 0.152 380 0.136 340 $45.22 $47.48 $50 $200.00 $17.00 $68.00 $132.00 2.78 $580

6 PPSC kitchen ppsc B3 2x4 lensed troffer with 3 F34T12 6 116 0.696 2500 1740 2F32T8C 6 63 2500 0.378 945 0.318 795 $105.74 $111.02 $45 $270.00 $26.50 $159.00 $111.00 1.00 $1,554

7 PPSC kitchen ppsc B2 1x4 lensed troffer with 2 F34T12 2 72 0.144 2500 360

1F32T8H (centering

kit and 2 38 2500 0.076 190 0.068 170 $22.61 $23.74 $50 $100.00 $17.00 $34.00 $66.00 2.78 $290

8 Petaluma Senior

Library/Lounge recreation A1

2x4 lensed troffer with 3 F32T8, 2

ballasts7 88 0.616 3400 2094.4 2F32T8C 7 63 3400 0.441 1499.4 0.175 595 $79.14 $83.09 $45 $315.00 $17.00 $119.00 $196.00 2.36 $1,050

9 Petaluma Senior

Pool Room recreation A1


ballasts6 88 0.528 3400 1795.2 2F32T8C 6 63 3400 0.378 1285.2 0.15 510 $67.83 $71.22 $45 $270.00 $17.00 $102.00 $168.00 2.36 $900

10 Petaluma Senior

Classroom recreation A1


ballasts4 88 0.352 3400 1196.8 2F32T8C 4 63 3400 0.252 856.8 0.1 340 $45.22 $47.48 $45 $180.00 $17.00 $68.00 $112.00 2.36 $600

11 Petaluma Senior Art Room recreation A1


ballasts8 88 0.704 3400 2393.6 2F32T8C 8 63 3400 0.504 1713.6 0.2 680 $90.44 $94.96 $45 $360.00 $17.00 $136.00 $224.00 2.36 $1,200

12 Petaluma Senior

Restroom

(between

public restroom H1 2' wrap with 2

F17T8 1 31 0.031 3400 105.4 2 F17T8L 1 29 3400 0.029 98.6 0.002 7 $0.90 $0.95 $40 $40.00 $1.36 $1.36 $38.64 40.69 -$24

13 Petaluma Senior

Computer Room recreation A1


ballasts2 88 0.176 3400 598.4 2F32T8C 2 63 3400 0.126 428.4 0.05 170 $22.61 $23.74 $45 $90.00 $17.00 $34.00 $56.00 2.36 $300

14 Petaluma Senior

Recreation Room recreation A1


ballasts8 88 0.704 3400 2393.6 2F32T8C 8 63 3400 0.504 1713.6 0.2 680 $90.44 $94.96 $45 $360.00 $17.00 $136.00 $224.00 2.36 $1,200

15 Petaluma Senior

Recreation Room (Kitchen)

storage E1 4' wrap with 2 F34T12 2 72 0.144 500 72 2F32T8L 2 48 500 0.096 48 0.048 24 $3.19 $3.35 $41 $82.00 $2.40 $4.80 $77.20 23.03 -$27

16 Petaluma Senior

Recreation Room

(Storage)storage F1

Wall mounted fixture with 75 W

incandescent1 75 0.075 500 37.5 23 W CFL 1 23 500 0.023 11.5 0.052 26 $3.46 $3.63 $9 $9.00 $5.20 $5.20 $3.80 1.05 $51

17 Petaluma Senior

Front Lobby Office

lobby A12x4 lensed troffer with 3 F32T8, 2

ballasts2 88 0.176 3400 598.4 2F32T8C 2 63 3400 0.126 428.4 0.05 170 $22.61 $23.74 $45 $90.00 $17.00 $34.00 $56.00 2.36 $300

18 Petaluma Senior

Meeting Room recreation A1


ballasts4 88 0.352 3400 1196.8 2F32T8C 4 63 3400 0.252 856.8 0.1 340 $45.22 $47.48 $45 $180.00 $17.00 $68.00 $112.00 2.36 $600 Checkerboard

switching

19 Petaluma Senior

Women's Restroo

m

public restroom F1


incandescent2 75 0.15 3400 510 23 W CFL 2 23 3400 0.046 156.4 0.104 354 $47.03 $49.38 $9 $18.00 $35.36 $70.72 -$52.72 (1.07) $793

20 Petaluma Senior

Women's Restroo

m


F17T8 3 31 0.093 3400 316.2 2 F17T8L 3 29 3400 0.087 295.8 0.006 20 $2.71 $2.85 $40 $120.00 $1.36 $4.08 $115.92 40.69 -$73

21 Petaluma Senior

Men's Restroo

m

public restroom F1


incandescent2 75 0.15 3400 510 23 W CFL 2 23 3400 0.046 156.4 0.104 354 $47.03 $49.38 $9 $18.00 $35.36 $70.72 -$52.72 (1.07) $793

22 Petaluma Senior

Men's Restroo

m


F17T8 1 31 0.031 3400 105.4 2 F17T8L 1 29 3400 0.029 98.6 0.002 7 $0.90 $0.95 $40 $40.00 $1.36 $1.36 $38.64 40.69 -$24

23 Petaluma Senior

Outdoor Garden recreation O1 GE biax: F38

W2D/827 Polylux 3 38 0.114 3400 387.6 No retrofit 3 38 3400 0.114 387.6 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 NA $0Could save energy if City wants to replace

whole fixture.

TOTALS 84 6.6 20,352 84 4 13,293 2.3 7,059 $939 $986 $3,436 $1,412 $2,024 2.05 $12,764


average KWH rate



City of Petaluma - Airport Data Entry rebate $0.20


Lighitng Retrofit Recommendations Linked to Fixture Code Sheet adder for reduced AC l 0% 15years for long-term benefit


Savings Notes

Ref No Dept Room Name room type Fixture Code Fixture Type QTY Watts Total kW Hours Pre Total

KWH Retrofit Description QTY Watts Hours Post Total kW Total

KWH kW Saved kWH Saved

Total $ Saved

Total $ Saved Total Unit Total Cost Unit

RebateTotal

RebateExtended

costpayback with AC

Long Term

1 Admin Office Main Room office A1e 2x4 surface box fixtures with clear prismatic lens,

end to end, each with 2F34T12 4 144 0.576 3000 1728 2x4 surface box fixture end to end, each with 2F32T8L, one 4L Ballast 4 96 3000 0.384 1152 0.192 576 $76.61 $76.61 $50 $200.00 $28.80 $115.20 $84.80 1.11 $1,064 One fixture is on

24/7

2 Admin Office Back Room 1 individual

office (os) A1e 2x4 surface box fixtures with clear prismatic lens, end to end, each with 2F34T12 2 144 0.288 2500 720 2x4 surface box fixture end to end, each

with 2F32T8L, one 4L Ballast 2 96 2500 0.192 480 0.096 240 $31.92 $31.92 $50 $100.00 $24.00 $48.00 $52.00 1.63 $427

3 Admin Office Back Room 2 individual


with 2F32T8L, one 4L Ballast 2 96 2500 0.192 480 0.096 240 $31.92 $31.92 $50 $100.00 $24.00 $48.00 $52.00 1.63 $427

4 Admin Office Restroom 1 public

restroom C2 25W Incandescent 4 25 0.1 3500 350 9 W CFL 4 9 3500 0.036 126 0.064 224 $29.79 $29.79 $9 $36.00 $11.20 $44.80 -$8.80 (0.30) $456 Occupancy Sensor

5 Admin Office Restroom 2 public

restroom C2 25W Incandescent 4 25 0.1 3500 350 9 W CFL 4 9 3500 0.036 126 0.064 224 $29.79 $29.79 $9 $36.00 $11.20 $44.80 -$8.80 (0.30) $456 Occupancy Sensor

6 Admin Office Office 1 individual

office (os) D1 8' surface wrap with 2F96T12 1 128 0.128 2500 320 2F32T8H & socket kit 1 73 2500 0.073 182.5 0.055 138 $18.29 $18.29 $68 $68.00 $27.50 $27.50 $40.50 2.21 $234 Occupancy Sensor

7 Admin Office Office 2 individual


with 2F32T8L, one 4L Ballast 2 96 2500 0.192 480 0.096 240 $31.92 $31.92 $50 $100.00 $24.00 $48.00 $52.00 1.63 $427 Occupancy Sensor

8 Storage Shack storage C1 Wall mounted fixture with 75 W incandescent 3 75 0.225 250 56.25 23 W CFL 3 23 250 0.069 17.25 0.156 39 $5.19 $5.19 $9 $27.00 $2.60 $7.80 $19.20 3.70 $59 2 burned out/1 running

9 Hangars Hangars: Buildings 1-4 Hangar B1h 4' hooded industrial with 2F34T12 in hangar 60 72 4.32 50 216 2F32T8L 60 48 50 2.88 144 1.44 72 $9.58 $9.58 $41 $2,460.00 $0.24 $14.40 $2,445.60 255.39 -$2,302

not including additional lighting installed by some

10 Hangars Building 3 - Women's Restroom

Hangar Restroom

sE1h 4' wrap with 2F32T8 in hangar 2 58 0.116 1000 116 No retrofit recommended due to low run

hours 2 58 1000 0.116 116 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

11 Hangars Building 3 - Men's Restroom

Hangar Restroom


hours 2 58 1000 0.116 116 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

12 Hangars Building 3 - Storage storage E1h 4' wrap with 2F32T8 in hangar 1 58 0.058 250 14.5 No retrofit recommended due to low run hours 1 58 250 0.058 14.5 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

13 Hangars Hangars: Building 5 Hangar X1 Private Hangar - no audit conducted 1 0 0 50 0 Private Hangar - no audit conducted 1 0 50 0 0 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

14 Hangars Hangars:Buildings 6-8 Hangar B1h 4' hooded industrial with 2F34T12 in hangar 45 72 3.24 50 162 2F32T8L 45 48 50 2.16 108 1.08 54 $7.18 $7.18 $41 $1,845.00 $0.24 $10.80 $1,834.20 255.39 -$1,726

not including additional lighting installed by some

15 Hangars Hangars: Building 9 Hangar B1h 4' hooded industrial with 2F34T12 in hangar 15 72 1.08 50 54 2F32T8L 15 48 50 0.72 36 0.36 18 $2.39 $2.39 $41 $615.00 $0.24 $3.60 $611.40 255.39 -$575not including

additional lighting installed by some

16 Hangars Hangars: Building 9 Hangar B2h 4' hooded industrial with 3F34T12 in hangar 3 87 0.261 50 13.05 2F32T8C 3 63 50 0.189 9.45 0.072 4 $0.48 $0.48 $45 $135.00 $0.24 $0.72 $134.28 280.45 -$127not including

additional lighting installed by some

17 Hangars Hangars:Buildings 10-13 Hangar B3eh 4' hooded industrial with 4F32T8 (end to end) in

hangar 132 114 15.048 50 752.4 No retrofit recommended due to low run hours 132 114 50 15.048 752.4 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

18 Hangars Building 11 - Women's Restroom

Hangar Restroom


hours 2 58 1000 0.116 116 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

19 Hangars Building 11 - Men's Restroom

Hangar Restroom


hours 2 58 1000 0.116 116 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

20 Hangars Building 11 - Storage storage E1h 4' wrap with 2F32T8 in hangar 2 58 0.116 250 29 No retrofit recommended due to low run hours 2 58 250 0.116 29 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

21 Hangars Hangars:Buildings 14-17 Hangar B4eh 8' wrap with 4F32T8s (end to end) in hangar 102 114 11.628 50 581.4 No retrofit recommended due to low run

hours 102 114 50 11.628 581.4 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

22 Hangars Hangars: Building 18 Hangar B5eh 8' lensed troffer with 4F32T8s (end to end) in

hangar 36 114 4.104 50 205.2 No retrofit recommended due to low run hours 36 114 50 4.104 205.2 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

23 Hangars Building 15: Women's Restroom

Hangar Restroom

sE2h 4' sealtite prism wrap with 2F32T8s in hangar 1 58 0.058 1000 58 No retrofit recommended due to low run

hours 1 58 1000 0.058 58 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

24 Hangars Building 15: Men's Restroom

Hangar Restroom

sE2h 4' sealtite prism wrap with 2F32T8s in hangar 1 58 0.058 1000 58 No retrofit recommended due to low run

hours 1 58 1000 0.058 58 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

25 Outside Lighting Between Hangars Outside

Lighting F1 70W HPS Spotlights (on a photocell) 96 88 8.448 5000 42240 No retrofit recommended 96 88 5000 8.448 42240 0 - $0.00 $0.00 $0 $0.00 $0.00 $0.00 $0.00 #DIV/0! $0

26 Outside Lighting Air Strip Pole Lights Outside

Lighting F2 400W Metal Halide on tall poles 13 458 5.954 5000 29770 320 Pulse Start Metal Halide 13 366 5000 4.758 23790 1.196 5,980 $795.34 $795.34 $200 $2,600.00 $92.00 $1,196.00 $1,404.00 1.77 $10,526

27 Outside Lighting

Runway Ground Lights

Outside Lighting F4 45W Incandescent lamps with CLEAR lens cover 15 45 0.675 5000 3375 Screw-in 9W CFL, with clear lens 15 9 5000 0.135 675 0.54 2,700 $359.10 $359.10 $9 $135.00 $36.00 $540.00 -$405.00 (1.13) $5,792

28 Outside Lighting

Runway Ground Lights

Outside Lighting F3 45W Incandescent lamps with BLUE lens cover 15 45 0.675 5000 3375 Screw-in 5-10W blue LED, with clear lens 15 5 5000 0.075 375 0.6 3,000 $399.00 $399.00 $50 $750.00 $40.00 $600.00 $150.00 0.38 $5,835

TOTALS 568 58.2 86,332 568 52 72,584 6.1 13,748 $1,828 $1,828 $9,207 $2,750 $6,457 3.53 $20,970

Please confirm quantity of blue

verses clear lenses on runway

lights.


average KWH rate



7.7 Petaluma Potable Water Pumping Data Distribution Pumping Calendar Year 2005

and Power Consumption

From Scada January February March April May June July August September October November December Total CCF Pumped by Location

Corona Pump Station 3 x 10hp

Zone 4 Total CCF by Month 0 0 0 0 0 0 0 0 0 0 0 0

KWH used for pumping

Frates Pumpstation 3 x 25hp

Zone 4 Total CCF by Month 6,900 5,900 9,390 20,570 25,490 46,520 62,850 63,780 48,260 35,220 18,480 14,190 357,550

KWH used for pumping 823 1,459 145 3,220 6,399 15,174 22,353 22,270 19,654 14,369 5,154 4,771 115,791

Variable

Magnolia Pumpstation 3 x 30hp and 1 x 20hp


KWH used for pumping 7,440 6,360 5,360 6,960 7,600 12,800 17,960 18,360 16,480 13,080 6,920 6,520 125,840

McNear Pumpstation 3 x 30hp



Victoria Pumpstation 2 x 30hp



Country Club Pump Station 2 x 10hp

Zone 5 Total CCF by Month 550 430 670 2,460 3,590 5,890 8,370 8,610 6,460 4,160 1,580 620 43,390

KWH used for pumping 370 597 1,431 2,515 4,834 6,992 6,807 6,017 4,697 1,344 771 522 36,897

CCF 50,620 44,720 53,900 78,100 98,580 148,680 197,890 196,190 157,610 126,560 73,310 61,400 1,287,560

KWH 19,005 17,630 16,991 25,510 34,967 58,407 77,332 75,628 69,111 52,429 27,960 23,398 498,368

Million Gallons 37.864 33.451 40.317 58.419 73.738 111.213 148.022 146.750 117.892 94.667 54.836 45.927 963.095

CCF MG KWH G/KWH

Zone 2 807,860 604.279 296,414 2,039

Zone 3 78,760 58.912 49,266 1,196

Zone 4 357,550 267.447 115,791 2,310

Zone 5 43,390 32.456 36,897 880

Total 1,287,560 963.095 498,368 1,932

1) Work on Fraites Pump Station projected to save 20% (2008). 2) Eliminated by Petaluma Aqueduct (East Side Alignment) 2015 per notes below (apply after #1)



7.8 Transit Bus Replacement Costs101

Total Federal Local Federal % Local %

Auto 26,000 21,695 4,305 83.44% 16.56%

Minivan Under 22' 48,000 40,052 7,948 83.44% 16.56%

Cut-Away/Van Under 26', 4 or 5-Year, Gas 72,000 58,770 13,230 81.62% 18.38%Cut-Away/Van Under 26', 4 or 5-Year, Diesel 97,000 79,176 17,824 81.62% 18.38%Cut-Away/Van Under 26', 4 or 5-Year, CNG 108,640 88,677 19,963 81.62% 18.38%

Cut-Away/Van Under 26', 7-Year, Gas 101,000 83,830 17,170 83.00% 17.00%Cut-Away/Van Under 26', 7-Year, Diesel 136,000 112,880 23,120 83.00% 17.00%Cut-Away/Van Under 26', 7-Year, CNG 152,000 126,159 25,841 83.00% 17.00%Cut-Away/Van 26'+, 4 or 5-Year, Gas 76,000 62,034 13,966 81.62% 18.38%

Cut-Away/Van 26'+, 4 or 5-Year, Diesel 102,000 83,257 18,743 81.62% 18.38%Cut-Away/Van 26'+, 4 or 5-Year, CNG 114,000 93,052 20,948 81.62% 18.38%

Cut-Away/Van 26'+, 7-Year, Gas 106,000 87,980 18,020 83.00% 17.00%Cut-Away/Van 26'+, 7-Year, Diesel 143,000 118,689 24,311 83.00% 17.00%Cut-Away/Van 26'+, 7-Year, CNG 160,000 132,799 27,201 83.00% 17.00%

Transit Bus 30' Diesel 445,000 358,917 86,083 80.66% 19.34%Transit Bus 30' CNG 498,000 401,665 96,335 80.66% 19.34%

Transit Bus 30' Hybrid 601,000 484,740 116,260 80.66% 19.34%Transit Bus 35' Diesel 458,000 369,320 88,680 80.64% 19.36%Transit Bus 35' CNG 513,000 413,670 99,330 80.64% 19.36%

Transit Bus 35' Hybrid 619,000 499,146 119,854 80.64% 19.36%Transit Bus 40' Diesel 471,000 379,730 91,270 80.62% 19.38%Transit Bus 40' CNG 528,000 425,684 102,316 80.62% 19.38%

Transit Bus 40' Hybrid 637,000 513,562 123,438 80.62% 19.38%

Over-the-Road 30' DieselOver-the-Road 35' DieselOver-the-Road 40' Diesel 551,000 443,608 107,392 80.51% 19.49%Over-the-Road 40' CNG 617,000 496,744 120,256 80.51% 19.49%

Over-the-Road 40' Hybrid 744,000 598,991 145,009 80.51% 19.49%Over-the-Road 45' Diesel 595,000 479,032 115,968 80.51% 19.49%Over-the-Road 45' CNG 666,000 536,194 129,806 80.51% 19.49%

Over-the-Road 45' Hybrid 803,000 646,492 156,508 80.51% 19.49%Over-the-Road 60' Diesel 785,000 631,087 153,913 80.39% 19.61%Over-the-Road 60' CNG 879,000 706,656 172,344 80.39% 19.61%

Over-the-Road 60' Hybrid 1,060,000 852,168 207,832 80.39% 19.61%

Articulated 60' Diesel 667,000 536,223 130,777 80.39% 19.61%Articulated 60' CNG 747,000 600,537 146,463 80.39% 19.61%

Articulated 60' Hybrid 900,000 723,539 176,461 80.39% 19.61%

Regional Bus/Van Pricelist FY 2008-09

Proposed FY09 Price

101 Metropolitan Transportation Commission



7.9 Vehicle List with Measures These lists include all vehicles in the inventory from 2000 to 2008. Some units have been retired. The vehicle numbers are drawn from lists provided by City Staff. The duplicate numbers indicate a retired vehicle or an inconsistency in numbering between the original lists.102

Vehicle

No. Year Description Model Fleet Replacement A

Fleet Replacement B

Nissan Electric Vehicle Program Biodiesel B20 Biodiesel B50

Linked to ABiodiesel B50 Linked to B Biodiesel B99

2 1996 2 ton truck LARGE TRUCK yes yes yes yes yes

3 1985 SUV 4x2 SUV-2WD yes yes

5 1994 Generator Equipment

7 1993 1993 DODGE SPIRIT MIDSIZE CARS


11 2007 Ford Police 4 dr sed POLICE CRUISER 1 yes yes




14 2008 4dr sedan POLICE CRUISER 1 yes yes

17 1998 1998 FORD CROWN VIC POLICE CRUISER 1 yes yes


20 1993 1993 FORD TAURUS LARGE CARS


21 2007 Dodge Police 4 dr sed POLICE CRUISER 1 yes yes

22 2006 Investigations POLICE CRUISER 1 yes yes




25 2007 Ford 4 dr sed POLICE CRUISER 1 yes yes

27 1995 1995 FORD TAURUS GL LARGE CARS yes yes yes


29 1998 1998 CHEV ASTRO VAN MINIVAN-2WD yes

30 1990 1990 PONTIAC LARGE CARS


31 2007 Street Crimes POLICE CRUISER 1 yes yes

32 1995 1995 OLDS CERIA LARGE CARS


33 1997 Toyota Under Cover POLICE CRUISER 2 yes yes

34 1995 1995 OLDS CERIA LARGE CARS


36 1987 1987 GMC SERRIA P/U STD PU TRUCKS 2WD

37 2003 Dodge Police Van VANS, PASSENGER

38 2003 GMC Under Cover POLICE CRUISER 1 yes yes

39 1995 1995 OLDS LARGE CARS

39 2004 Ford Police Van VANS, PASSENGER


61 2006 Pontiac Under Cover POLICE CRUISER 1 yes yes


64 2002 Chry 4 dr sed POLICE CRUISER 2 yes yes


70 1996 1996 FORD CROWN VICTORIA POLICE CRUISER 1


70 2008 Crown Vic POLICE CRUISER 1 yes yes

71 1996 1996 FORD CROWN VIC POLICE CRUISER 1



72 1975 1975 FORD E100 VAN VANS, PASSENGER


73 1994 1994 CHEV CAPRICE POLICE CRUISER 2











Measure Summary (Yes indicates inclusion in the measure)

Table 25: Vehicle List and Measures Units 2 - 76

102 2000 Smog List, Vehicle Inventory 6/2007, List provided by Staff September 11, 2008.



Vehicle

No. Year Description Model Fleet Replacement A

Fleet Replacement B

Nissan Electric Vehicle Program Biodiesel B20 Biodiesel B50

Linked to ABiodiesel B50 Linked to B Biodiesel B99






79 1995 1995 CHEVROLET CAPRICE POLICE CRUISER 2



80 2007 F250 STD PU TRUCKS 2WD yes yes yes















86 2008 Charger POLICE CRUISER 1 yes yes
















95 2006 Magnum POLICE CRUISER 1 yes yes

100 2006 Harley MC Motorcycle

101 2007 Motorcycle Motorcycle






111 1988 Kawas MC Motorcycle

112 2005 Suzuk MC Motorcycle




122 2003 Trailer Non Motorized



124 2006 Ford 3/4T PU Truck STD PU TRUCKS 4WD yes yes yes yes yes

125 1986 Chev 3/4T PU Truck STD PU TRUCKS 4WD yes yes yes yes yes

200 2006 Ford 4 dr sed LARGE CARS yes yes yes







Vehicle No. Year Description Model Fleet

Replacement AFleet

Replacement BNissan Electric

Vehicle Program Biodiesel B20 Biodiesel B50 Linked to A

Biodiesel B50 Linked to B Biodiesel B99

202 2008 Escape SUV-2WD yes yes

206 1996 1996 FORD F250 P/U STD PU TRUCKS 4WD


209 2007 Chev PB Patcher Truck LARGE TRUCK yes yes yes yes yes


211 2007 Roller Equipment

212 2008 Asphalt Paver Equipment

213 2008 Grinder Equipment

220 1997 1997 DODGE 2500 1/2T PU STD PU TRUCKS 2WD yes yes yes

220 1998 1998 DODGE RAM 1500 STD PU TRUCKS 2WD



223 1986 1986 NASSIAN P/U SMALL PU TRUCKS 2WD


225 1986 Welder Equipment


228 2003 Ford Dump Truck LARGE TRUCK yes yes yes yes yes

229 1991 Internl Dump Truck LARGE TRUCK yes yes yes yes yes

230 1992 1992 FORD SUPER DUTY LARGE TRUCK

230 2007 Ford Flatbed Dump Truck LARGE TRUCK yes yes yes yes yes

231 1972 1972 FORD F500 LARGE TRUCK yes yes yes yes yes

231 1975 1975 FORD F500 LARGE TRUCK

231 2006 Chev PB Patcher Truck LARGE TRUCK yes yes yes yes yes

237 1993 Air Compressor Equipment


239 2006 Pipeh Vacuum Trailer Non Motorized


243 2006 Ford Utility Truck LARGE TRUCK yes yes yes yes yes


247 2006 Forklift Equipment

249 2007 Ford Hybrid HYBRID SUV

250 2007 Ford 1/2T PU Truck STD PU TRUCKS 2WD yes yes yes

253 1991 1991 FORD F150 STD PU TRUCKS 2WD

256 1998 Generator Equipment


260 2005 Backhoe Tractor Equipment


261 2007 Ford Flatbed Truck LARGE TRUCK yes yes yes yes yes

264 2007 EZ-LI Equipment

265 2007 Line Striper Equipment


267 2007 F450 LARGE TRUCK yes yes yes yes yes

270 2003 ITW D Adhesive supply Non Motorized

280 2006 Ford SUV 4X2 SUV-2WD yes yes






287 1977 1977 GMC 600 LARGE TRUCK

290 2004 Traffic Trailer Non Motorized yes yes yes

291 1984 1984 CHEV C20 VANS, CARGO



293 2004 Aerial Truck LARGE TRUCK yes yes yes yes yes


294 2006 Aerial Truck LARGE TRUCK yes yes yes yes yes









Replacement AFleet





312 2008 Utility Cart Non Motorized

313 2003 John Deere Riding Mower Equipment yes yes yes

314 2004 John Deere Riding Mower Equipment yes yes yes

315 2004 Riding Mower Equipment yes yes yes

320 1989 1989 CHEV S10 SMALL PICKUP TRUCKS 2WD


336 1997 1997 FORD RANGER SMALL PU TRUCKS 2WD


341 1997 Flatbed Dump Truck / FORD SUPER D LARGE TRUCK yes yes yes yes yes

342 1973 1973 CHEVROLET C-30 VANS, CARGO



349 1988 1988 FORD FORD F150 STD PU TRUCKS 2WD

349 2004 John Deere Utility Cart Non Motorized






365 1997 Kubot Tracter Equipment yes yes yes

367 2000 Jacob Riding Mower Equipment yes yes yes

369 2008 Riding Mower Equipment yes yes yes

372 1989 JCB Backhoe Equipment yes yes yes






383 1976 Case Miscellaneous Equipment


385 1997 Misc Equipment












398 1987 Jacob Riding Mower Equipment yes yes yes




420 2004 Taurus LARGE CARS yes yes yes


500 2006 Ford Hybrid 4dr sedan HYBRID CAR

502 2003 Sterl Vacuum Flush T Equipment yes yes yes


503 2006 Chev Dump Truck LARGE TRUCK yes yes yes yes yes


505 2005 Gorma Pump (water) Equipment yes yes yes

522 2003 Chev Compact PU SMALL PU TRUCKS 2WD yes yes yes yes yes










Replacement AFleet





528 1982 Air Compressor Equipment yes yes yes

529 2006 Prius HYBRID CAR

530 2007 Prius HYBRID CAR

531 2008 Tacoma SMALL PU TRUCKS 2WD yes yes yes yes yes

533 1994 Chev 1/2T PU Truck STD PU TRUCKS 2WD yes yes yes

536 1997 Wacke Generator Equipment yes yes yes

537 ? JCB Backhoe Equipment yes yes yes

538 1989 Winco Generator Equipment yes yes yes

539 2002 JCB Backhoe Equipment yes yes yes


549 1989 1989 CHEVROLET 1500 STD PU TRUCKS 2WD

549 2005 Traffic Trailer Non Motorized

550 1989 1989 CHEVROLET 1500 STD PU TRUCKS 2WD




555 1991 1991 CHEVROLET 2500 VANS, PASSENGER

556 1991 1991 CHEV C2500 VANS, PASSENGER



559 1989 Winco Generator Equipment yes yes yes



561 ? Pacific TE Vaccum Trailer Equipment yes yes yes

562 1996 Pacif Vacuum/Flush Equipment



566 2003 Ford Utility Dump Truck LARGE TRUCK yes yes yes yes yes







590 1993 Inger Air Compressor Equipment yes yes yes

591 1990 Inger Air Compressor Equipment yes yes yes

592 1997 1997 FORD F250 STD PU TRUCKS 4WD yes yes yes yes yes

594 1998 Wacke Generator Equipment yes yes yes

595 1990 Welder Equipment



598 2003 Ford Van VANS, PASSENGER

600 2007 Ford Hybrid HYBRID SUV

601 2001 Toyota Electric Vehicle Electric Vehicle (compact)



603 2008 Generator Equipment yes yes yes

604 1984 Kohle Generator Equipment yes yes yes

605 1995 1995 DODGE NEON COMPACT CARS yes yes yes

606 1989 1989 GEO PRISM COMPACT CARS

607 1978 1978 GMC RALLY VAN VANS, PASSENGER



610 1990 1990 DODGE DAKOTA SMALL PU TRUCKS 2WD



613 2002 Dodge 4 dr sedan LARGE CARS yes yes yes

614 1995 1995 FORD TAURUS GL LARGE CARS yes yes yes







Replacement AFleet




615 2000 Hyund 4 dr sedan COMPACT CARS yes yes yes






620 1997 1997 FORD CLUB WAGON XLT VANS, PASSENGER

620 2007 F150 STD PU TRUCKS 2WD yes yes yes





624 2007 GO-4 Motorcycle Motorcycle




630 2008 Hybrid HYBRID CAR

631 2008 Hybrid HYBRID CAR



700 2002 Dodge 4 dr sedan LARGE CARS yes yes yes

714 1994 1994 FORD F350XL STD PU TRUCKS 4WD

718 1996 Vacuum / Flush Equipment yes yes yes

718 2006 Vacuum / Flush Equipment yes yes yes

720 1987 Case Backhoe Equipment yes yes yes



723 2006 Grimm Air Compressor Equipment

724 2005 Traffic Trailer Non Motorized


727 1962 Rodde Flexible Rodde Equipment




733 1998 PACO Pump (water) Equipment yes yes yes



800 2000 J/D Tractor Equipment yes yes yes

801 2004 Chev Dump Truck LARGE TRUCK yes yes yes yes yes

802 1986 Honda MC Motorcycle







811 1998 Ford Compact PU SMALL PU TRUCKS 2WD yes yes yes yes yes

813 1966 Boston Whaler Boat Equipment

814 1979 Valco Boat Equipment



820 2003 Yacht Boat Equipment


825 2008 Forklift Equipment

902 1994 1994 FORD RANGER XL SMALL PU TRUCKS 2WD











Replacement AFleet




991 1976 GMC Fuel Tanker Truck LARGE TRUCK yes yes yes yes yes

992 ? Tractor Non Motorized yes yes yes

9300 1997 1997 FORD CROWN VIC LARGE CARS


9301 2006 Ford Fire Unit LARGE TRUCK yes yes yes yes yes

9302 1996 GMC Fire Unit LARGE TRUCK yes yes yes yes yes

9305 1999 Dodge 1/2T PU Truck STD PU TRUCKS 2WD yes yes yes






9341 1982 Ford Fire Unit LARGE TRUCK yes yes yes yes yes

9351 2000 Sutph Fire Unit LARGE TRUCK yes yes yes yes yes

9351 2005 Sutph Fire Unit LARGE TRUCK yes yes yes yes yes

9382 1995 3-D P Fire Unit LARGE TRUCK yes yes yes yes yes

9382 1996 3-D P Fire Unit LARGE TRUCK yes yes yes yes yes

9384 1977 Van Fire Unit LARGE TRUCK yes yes yes yes yes

9385 1989 Pier Fire Unit LARGE TRUCK yes yes yes yes yes

82B 1991 1991 FORD CROWN VICTORIA LARGE CARS

M991 2001 Braun Fire Unit LARGE TRUCK yes yes yes yes yes




ORB1 1995 SEA D Fire Unit LARGE TRUCK yes yes yes yes yes

A1 1982 Brink Van VANS, CARGO yes yes

A2 1999 Dodge Under Cover POLICE CRUISER 1 yes yes

A3 2004 Ford 4 dr sed POLICE CRUISER 1 yes yes


Table 31: Vehicle List and Measures Units 991 – A3



7.10 Solar Electric Production Assumptions

Solar Electric System Performance Inputs Calculations

Module Temp. (PTC) Rating (%) 89% in Blue in Black

Inverter Efficiency (%) 91%

CEC AC Rating (%) 81% (CEC Rating net AC watts/gross DC watts)

Dust & Dirt (%) 7%

Manufacturer Fudge (%) 3%

Module Mismatch (%) 1%

Wiring (%) 3%

Real AC Performance / DC Rating 68%

Inverter replacement cost 824 ($/kWac)

Output Degradation 0.5% (per year)

Size (DC) example 1234.720336 kW DC

Size (AC) 1,000.0 (Net CEC AC Kilowatts)

CEC Performance 1,570 (CEC AC Rating kWh/yr per CEC AC kW installed)

Real Performance 1,318 (Real AC kWh/yr per CEC AC kW installed)

Annual kWh (initial year) 1,317,994 (kWh/yr)

Module Degradation 0.5% (% / yr)

System Maintenance 0.25% (% Gross system cost / yr)

Permit $1,200 ($)

TOU Meter $1,643 ($)

Cost $8.0 ($/netACwatt)

Rebate $0.19 ($/netAC kWh)

Time of Use Factor 0.0 Ave. ($/kwhr) generation / ($/kwhr) use

Total Installed Costs $8,002,843 ($)

Rebate (example) $190,000 ($)

Final Net Cost $7,812,843 ($)



7.11 Vehicle Fuel Cost Trends Petrofuel Price Trends and Future Jim Housman, PE (retired) 11/19/07

There are a number of factors that contribute to the cost of gasoline at the pump. According to the U.S. Energy Information Agency (EIA) the price of gasoline can be broken down as follows: Crude Oil: 64% Refining (including additives) 13% Distribution and Marketing 9% Taxes: 14% It should be clear from the attached graph that the major factor driving gasoline prices is the price of crude oil. There have been two distinct issues driving the price of crude in the past five years, geo-political issues and geological issues. The geo-political issues driving oil prices are primarily the declining value of the dollar, the rapid growth in demand, primarily in Asia, and the economic uncertainty caused by military conflict. An additional geo-political factor is the shift in oil resources from the control (primarily) of privately owned multinational oil companies to being owned and managed by national oil companies. The motivation of shareholder owned companies is largely short term profits, driving the producers to produce the maximum amount of oil in the shortest time. National oil companies, while depending on oil revenue for investment capital, may be motivated to invest a significant portion of their income in non-oil related programs decreasing their ability to increase production as existing oil fields decline. Oil can also be used as a diplomatic tool, punishing enemies and rewarding friends. Short term decisions made by national oil companies for political reasons may have long term economic effects on oil using societies. Geologically the oil industry is shifting from an environment where a relatively small number of oil fields are each producing very large quantities of oil to one where a very large number of oil fields are each producing a relatively small amount of oil. For example twenty years ago there were 15 oil fields in the world producing over one million barrels per day. Today there are only four, and at least one of those fields (Cantarell in Mexico) is in significant decline. Two thirds of the fields in the oil producing nations in the world are in decline. Not a single field discovered in the past ten years is capable of producing a million barrels per day. (reference 4) In 1987, after the oil industry recovered from the turmoil caused by the Iran revolution, the price of gasoline in the United States averaged under 70 cents per gallon. In that same year the spot price of crude oil (the price quoted in the news) was about $13.40. In November of 2007 those prices were $3.40 for gasoline in California and $83.03 for crude oil. In planning for future energy costs we can extrapolate these numbers to estimate gasoline cost in 2008 and future years.



In the simplest terms the cost of gasoline has grown, on average, at about 8% a year over the past twenty years. However if we look at just the past five years, from 2002 to 2007, the price of gasoline has escalated more like 17% each year. In 2012 the difference between those growth rates will be the difference between gasoline at $5.00 per gallon or $7.45 per gallon. Given the political and geological issues faced by the oil industry it would be prudent to assume that oil prices will continue their upward momentum.

PRICES 2000 THRU NOV 07

$-

$15.00

$30.00

$45.00

$60.00

$75.00

$90.00

2000

2002

2004

2006 Feb Apr Ju

nAug Oct

2007

Cru

de O

il

$-$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00

Gas

olin

e

Crude Oil (Spot)

Calif. Gasoline Average

Sources: 1. http://publications.uu.se/abstract.xsql?dbid=7625 2.http://tonto.eia.doe.gov/dnav/pet/pet_pri_wco_k_w.htm 3.http://tonto.eia.doe.gov/dnav/pet/pet_pri_gnd_a_epm0_pte_cpgal_w.htm 4. http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp 5. http://www.simmonsco-intl.com/files/giantoilfields.pdf



7.12 Carbon Credits Carbon Offsets/Green Tags Prepared by Peter Spencer

The David Suzuki Organization defines a carbon offset as “an emission reduction credit from another organization’s project that results in less carbon dioxide or other greenhouse gases in the atmosphere than would otherwise occur. Carbon offsets are typically measured in tons of CO2-equivalents (or 'CO2e') and are bought and sold through a number of international brokers, online retailers, and trading platforms.” http://www.davidsuzuki.org/Climate_Change/What_You_Can_Do/carbon_offsets.asp

A green tag is a specific type of carbon offset also referred to as Renewable Energy Certificates (RECs). According to the Environmental Protection Agency, “Renewable Energy Certificates represent the environmental, social, and other positive attributes of power generated by renewable resources.”

The carbon offset is a generic term for all types of purchasable GHG reduction programs sold in the market. For example, CO2 emissions can be offset by paying a group to plant trees anywhere in the world. The green tag, a subset of carbon offsets, is specific to electricity generation. To offset CO2 emissions with a green tag, a purchase is made which supports renewable electricity generation and consumption somewhere else. That green-generated electricity becomes part of the total pool of power and thereby reduces emissions from overall electricity production.

Individuals and organizations can purchase carbon offsets to reduce climate impacts from their activities. When carbon emissions are too difficult or costly to avoid, it’s possible to pay someone else to reduce GHG. Dozens of companies, both commercial and nonprofit, offer a variety of offset types and prices.

The most common type of offset involves trees, either reforestation or avoided deforestation. Other common offsets are renewable energy and energy conservation projects. Prices for offsets/green tags vary widely from $3.56 to $30.00 per metric ton. (See survey in appendix) These prices are low compared to many other mitigation measures.

Renewable energy offsets, sold as green tags, fund wind, solar, biomass, and biodiesel projects worldwide. For every megawatt of power produced by a renewable source, one green tag is issued to the producer. The green tags can be sold to raise profits from renewable energy generation thus making it more competitive in the market. Energy conservation offsets often involve purchasing a GHG emission allowance from a company on the Chicago Climate Exchange. This “retires” the allowance preventing others from purchasing it to emit GHG.

Verification and accounting systems for offsets differ and there are currently no accepted standards. There is a wide variation of GHG baseline calculations for activities and also for the calculations of GHG reductions from projects. However, many providers make a good effort to ensure their product’s value and provide documentation. The Green-e program is the most accepted certification program and referenced by the EPA. (http://www.green-e.org/)



Arguments in favor of Carbon Offsets:

• Supports growth of the renewable energy industry • Compensates for GHG emissions which are too difficult or costly to avoid • Lowers cost of GHG reductions • Provides a market-based system for GHG reduction • Can benefit poor countries with investments • Positive PR for organizations that reduce emissions • Raises awareness and encourages public policy changes

Sources of supportive information:

An excellent resource for consumers with ratings for top providers: A Consumer’s Guide to Retail Offset Providers Clean Air-Cool Planet: http://www.cleanair-coolplanet.org/ConsumersGuidetoCarbonOffsets.pdf EPA description of various green purchasing options: Guide to Purchasing guide for Green Power Environmental Protection Agency: http://www.epa.gov/greenpower/pdf/purchasing_guide_for_web.pdf Realistic assessment supportive of offsets with large number of links: How the Retail Carbon Offsets Market Can Further Global Warming Mitigation Goals EM Market Insights: http://conserveonline.org/workspaces/climate.change/carbonmarkets/em_going_carbon_neutral.pdf

Arguments against Carbon Offsets:

Trees: • Trees store carbon, but don’t reduce total biological carbon brought to the earth’s surface

in fossil fuels • Planting releases carbon from the soil • An unrealistic amount of trees would need to be planted to be effective • Most projects are planting monocultures causing ecosystem problems • Predicting the carbon performance of trees is not possible • Increasingly challenged by scientists as unsuccessful strategy

All methods: • Don’t address the fundamental problem of emissions • Makes it easy to avoid measures reducing emissions • Removes money from local economy • Poor accountability • No proof that there is an overall improvement in the climate with offset system • Short-term solution with little direct benefit to offset purchasing organization • May ignore local problems such as air pollution or need for more power plants



• Questionable future of unregulated and unproven strategies in new offset industry • Doesn’t create lasting benefit for organization

Product Certification/Verification

AtmosClear Climate Club

USCarbonfund.orgUS

e-BlueHorizonsUSTerrapassUS

DriveNeutral.orgUSNative EnergyUS

The CarbonNeutral CompanyUKClimate FriendlyAus

Sustainable travel InternationalUS, Switzerland

Bonneville Environmental Foundation

USMyclimateSwitzerland

Global Cool £20.00UK ($39.48)

Product Certification/

VerificationDrivingGreenIrelandSolar Electric Light FundUSCarbon Clear

UK a: Atmos Clear - Low price for 25 Ton option at $89 b: Carbonfund.org - Low price for ZeroCarbon tags option: 18 Ton + 5 Ton match, pay $99 for $23 Ton c: Terrapass - Low price when purchasing 204 metric ton of carbon offsets for $1,499.951. Offset Types: There are hundreds of potential offset types. We have limited our survey to just the most common.2. Verification: "n/a" means we were unable to determine a third-party verification body. The projects may, however, be verified. 3. Choice: refers to whether customers may choose between project types and/or specific projects.4. Price: prices change and exchange rates fluctuate. The data listed was first gathered from the respective websites July 21, 2006 5. Other offset providers may exist. This survey provides a cross section of the industry, projects may be added or removed over time.6. Some information may be incomplete or has changed. We welcome updates.

Home, Car, Air, Babies

n/a$17.00 No Reforestation No

Car, Air, Events

n/a

$10.00 Yes Renewables No External Calculators

n/a

$8.00 No Renewables No

Services for which independent product certification or verification information not availableCarbon Offset

ProviderPrice

(US$/Metric ton CO2)

Non-profit

Projects Types Project Choice

Offset Types

Air, Events, Business

Designated Operational Entity

Yes Renewables, Efficiency

No n/a CDM

$30.00 Yes Renewables No

Air, Car, Home, Hotel

See Myclimate

$29.00 Yes Renewables No Home, Air, Business,

Event

Green-e

$18.00 Yes Renewables No

Business, Home, Car, Air, Events

KPMG, Edinburgh Centre for Carbon Management, Independent Advisory Committee

$16.00-19.00 No Renewables No Home, Car, Air,

Business

Office of the Renewable Energy Regulator, NSW Government, Ernst & Young.

$14.00-18.00 No Renewables, Efficiency, Reforestation

Yes

Car Chicago Climate Exchange

$13.20 No Renewables Yes Home, Car, Air, Events, Business

Green-e

$7.50 & up Yes Efficiency No

Home, Car, Air

Chicago Climate Exchange, Environmental Resources Trust

$7.35c - 11.00

No Renewables, Efficiency

No Car, Air, Events,

Business

Green-e, Chicago Climate Exchange, Center for Resource Solutions

$5.00 No Renewables, Reforestation

No

Car, Home Environmental Resources Trust

$4.30b - 5.50 Yes Renewables, Efficiency, Reforestation

Yes Home, Car, Air, Events, Business

Green-e, Chicago Climate Exchange, Environmental Resources Trust

$3.56a - $25.00

No Methane No

Ecobusinesslinks.com Carbon Offset SurveyCarbon Offset

ProviderPrice

(US$/Metric Non-profit

Projects Types Project Choice

Offset Types



Sources of Offset critical information:

The most complete, well-written analysis of climate science and offsets: Carbon Trading: A Critical Conversation on Climate Change, Privatization and Power Dag Hammarskjöld Centre: http://www.dhf.uu.se/pdffiler/DD2006_48_carbon_trading/carbon_trading_web.pdf

Excellent analysis from a sustainability perspective: The International Challenge of Climate Change United Kingdom, Environmental Audit Committee: http://www.defra.gov.uk/environment/climatechange/pubs/eac/pdf/cc-govres.pdf Scientific paper explaining why reforestation won’t help climate change: Planting trees will not cancel out climate change: Nature: http://www.scidev.net/pdffiles/nature/nature04486.pdf Short negative view of green tags: The wooly world of green tags out of Kirby Mountain: http://kirbymtn.blogspot.com/2006/04/woolly-world-of-green-tags.html In-depth assessment of trading systems and their limitations: Is the US Experience with Pollution Markets Really an Argument for Global Carbon Trading? McGill International Journal of Sustainable Development, Law and Policy, fall 2005: http://www.fern.org/media/documents/document_3657_3658.pdf Good short summary of why offsets don’t work: Carbon ‘offset’ - no magic solution to ‘neutralize’ fossil fuel emissions Forests and the European Union Resource Network: http://www.fern.org/media/documents/document_884_885.pdf Strong short letter opposing carbon trading: We must reduce fossil fuel use, not trade carbon: Financial Times: http://www.fern.org/media/documents/document_3634_3635.pdf (Source: http://www.ecobusinesslinks.com/carbon_offset_wind_credits_carbon_reduction.htm) For the most complete and up to date list of green tag products and marketers, visit the Green Power Network, part of the U.S. Dept of Energy, Energy Efficiency and Renewable Energy Office. http://www.eere.energy.gov/greenpower/markets/certificates.shtml?page=0 For a detailed report on the status of green power marketing, check out the following publication from the National Renewable Energy Laboratory: http://www.eere.energy.gov/greenpower/resources/pdfs/40904.pdf



7.13 Electric Vehicles Electric Vehicle Current Status Jim Housman, P.E. (retired) May 7, 2007 Battery powered electric vehicles pose opportunities for cost savings and enhanced convenience in an increasing number of applications where their unique properties can be used to advantage. While gasoline as a motor fuel has significantly higher energy density and lower cost per unit of energy, when the overall “well-to-wheel efficiencies of electrical power are taken into account it can be advantageous to operate electrical vehicles in place of their gasoline or diesel counterparts. The majority of electric vehicles available today, not including hybrids, are classified as “Neighborhood Electric Vehicles” (NEV). In general these vehicles are limited to a top speed of 25 miles per hour and are only permitted on public roads with speed limits below 35 miles per hour. They have minimal requirements for lighting and passenger protection in keeping with their low speed nature. Some of the larger manufacturers of NEVs are listed on the following web site: http://www.eere.energy.gov/afdc/afv/elec_vehicles.html In a recent study (2001) the Department of Energy 103 evaluated the performance of 348 NEVs operated in 15 automotive fleets. The fleets included in the study belonged to military, commercial, least expensive NEVs, resembling golf carts can be purchased for less than $5000. Used but functional vehicles are generally available under $1000.104 Because of the simplicity of the electric power train vehicle maintenance costs are a fraction of that required for gasoline or diesel engines. There is no oil to change, no sparkplugs, filters or coolant issues. The light weight of most electrical vehicles also means that brakes, tires and suspension components are very durable. Currently one of the most conventional appearing NEVs is the Zenn. While still relying on traditional lead-acid battery technology the Toronto Canada based company has created an unusually sophisticated NEV using a small urban vehicle built in France and converted in Canada to electric power. Because of the volume production already in place with the basic car (originally diesel powered) Zenn has managed to price the vehicle just above the “golf cart” market while delivering a vehicle with both the style and convenience of a small gasoline powered vehicle. The majority of NEVs currently on the market use technology that has not changed significantly for the past half century. They use lead-acid batteries, DC motors and simple control systems. A new regime of electrical vehicles are appearing in the market in the very near future, most likely 103 http://avt.inel.gov/pdf/nev/nevstudy.pdf 104 http://www.eaaev.org/eaalinks.html



prompted by the rapidly increasing price of fossil fuels and the increased awareness of Americans that our access to fossil fuels is becoming precarious. One of these new electrical vehicles, the Tesla roadster, is a technological showcase in the form of a high performance sports car. Another, the Phoenix SUT (sport utility truck), also uses state-of-the-art technology in a practical utility vehicle. Both vehicles use sophisticated AC motors, Lithium ion batteries, heat pump HVAC systems, regenerative braking and computerized control systems. Both are advertising operating ranges of over 100 miles on a single charge and, based on the battery technology, charge times of under 30 minutes should be expected. Early test data on both vehicles describe performance equal to comparable gasoline powered vehicles. In the case of the Tesla roadster that means acceleration to 60 miles per hour in less than 6 seconds and a top speed of 130 miles per hour.105 The Phoenix SUT boasts a 1000 pound payload, 90 mile per hour top speed and 60 mile an hour in less than 10 seconds and low energy density prevented the development of electric vehicles even moderately competitive with liquid fueled vehicles. In the late 1990s electric car and hybrid-electric car developers began investigating the advances made in battery technology for use in portable computers and other electronic devices. The first of these technologies evaluated for vehicle use was the Nickel-Metal Hydride battery. This battery was promising enough to be used in the second generation EV1 electric car developed by General Motors for compliance with the proposed California Zero Emissions Standard. While not significantly lighter than the lead-acid battery it replaced, the increased energy-to-size ratio allowed for a significantly increased range for the EV1. Since that time electric car enthusiasts have turned their attention to the Lithium ion battery. These batteries have both significantly better energy-to-weight and energy-to-volume municipal, rental and transportation organizations. The NEVs were found to be successful replacements for gasoline powered vehicles in most circumstances. Success was indicated by satisfied users, improved economy and reliability of the vehicles. The study did find some areas where improvements could be made. Higher speed capability and improved range were listed as desirable. In addition users would have liked improved passenger protection, including solid doors and roll down windows. Both were lacking in the majority of the fleet vehicles. While the study found that 91% of the vehicles had operated without problems there were some reliability issues. Fourteen vehicles had battery packs replaced, Five had problems with switches and four controllers were replaced. By a large majority the study found that fleet owners were satisfied with the performance of their vehicles. Some were used only on public roads, some were never used on public roads and some were used under both circumstances. Specific uses included police work, material handling, towing, personnel transportation and community shopping uses. A large market currently exists for this type of vehicle permitting competitive pricing. The most sophisticated of the NEVs retail in the $10 to $15 thousand dollar range. At the higher end of this range will be found vehicles with features and styling that compare favorably with 105 http://www.teslamotors.com/



conventional automobiles but lacking only the gasoline engine performance. The simplest and characteristics. Early versions of these batteries were sensitive to high discharge rates and to certain manufacturing defects which resulted in a number of fires occurring in portable computers using this technology. Since that time changes in the cathode material, manufacturing improvements and the development of external control methods have potentially eliminated the problem. As a result a new wave of enthusiasm for electric vehicles is developing. Both the high performance Tesla Roadster sports car and the Phoenix Sport Utility Trucks (SUT) are designed around the latest versions of the Lithium ion battery.106 Phoenix Motorcars plans to sell approximately 500 Sport Utility Trucks in 2007 to selected fleet operators. One such operator is Pacific Gas and Electric, the northern California utility company. Phoenix plans to begin selling to individual users in 2008 and estimates that it will sell 6000 vehicles in that year. Pricing for the 2008 model year should be in the $40 to $50 thousand range. 4 First shipments of the Tesla Roadster are scheduled for August 2007. Technological changes are appearing rapidly. Recently EEStor, a Texas company has announced a breakthrough battery/ultra-capacitor system that may leapfrog the Lithium ion battery technology with improved storage capacity, discharge rate and cost. Zenn motorcars has signed an exclusive agreement with EEStor to provide storage systems for their next generation of electric vehicles107. Regardless of the success of such efforts it is an indication of a growing interest in non-fossil fueled power systems. For short distance, light load applications electric powered vehicles are the right choice for a large number of applications. The long charging times needed by lead-acid batteries limit the application of these vehicles to under fifty miles per day in most cases. For those fleet applications that can justify the high first cost Phoenix Motorcars SUTs are a practical vehicle available this year. With the rapid changes taking place in battery, motor and motor controller technologies look for increased choices in the zero emission vehicle market. While these vehicles are especially designed for specific audiences they represent logical entry points for new technologies into an existing, mature, market. The Tesla roadster is aimed at the wealthy car enthusiast who is willing to pay above market price for the uniqueness of an electric powered performance car. The Phoenix is marketed to fleet purchasers who value their environmental image above the short term ownership cost. Success in these two markets will work as both test beds for these technologies in real operating environments and as bootstrapping operations to bring down the cost of these technologies as production volumes increase. For the past one hundred years battery technology has been the limiting factor in keeping electric powered vehicles from competing with fossil fuel powered vehicles. For most of this time the only practical battery technology for use in electric cars was the same lead-acid battery used for starting power in conventional automobiles. The combination of high weight, slow re-charging,

106 http://en.wikipedia.org/wiki/Altairnano 107 http://www.technologyreview.com/Biztech/18086/page1/



Further Reading The GM EV1: http://www.thejaffes.org/rory/ev1/ev1.pdf The French postal service plans to order 10,000 electric vehicles: http://www.autobloggreen.com/2007/04/18/the-french-postal-service-plans-to-order-10-000-electric-vehicle/ Nissan and NEC to produce electric-car batteries: http://www.detnews.com/apps/pbcs.dll/article?AID=/20070413/UPDATE/704130433/1148/rss25 Electric car batteries might serve as reservoirs of green power?: http://www.edn.com/index.asp?layout=blog&blog_id=1470000147&blog_post_id=1170007917 Basic battery technology: http://www.batteryuniversity.com/index.htm Battery data: http://en.wikipedia.org/wiki/Nickel_metal_hydride_battery http://en.wikipedia.org/wiki/Lithium_ion http://en.wikipedia.org/wiki/Lead_acid Specs on Altair nano battery: http://www.altairnano.com/documents/NanoSafe_Datasheet.pdf Johnson Controls reveals new hybrid-electric car batteries: http://wistechnology.com/article.php?id=1485 Altairnano lithium ion battery system: http://www.azonano.com/news.asp?newsID=1967 Safety of lithium ion batteries: http://www.technologyreview.com/read_article.aspx?id=17250&ch=biztech Lithium ion battery improvements: http://www.technologyreview.com/read_article.aspx?id=16384&ch=biztech


Climate Protection Campaign 161 Tellus Applied Sciences, Inc

7.14 Commute Programs

Commute Programs: Examples of Success 6/17/07 Jim Housman, PE The United States of America consumes 9.2 million barrels of gasoline every day, approximately 25% of all the gasoline consumed in the world.108 Yet the United States contains only 4.5% of the world’s population. We drive bigger vehicles and we drive them farther each year than any other society. We have the cheapest gasoline of any nation that imports more petroleum than it exports (excepting China and Thailand)109. Americans are used to using their cars for virtually 100% of their transportation needs. We have built our cities, and even our small towns, around the assumption that everyone who wants to go anywhere will drive. Our driving has been cheap and convenient. But in recent years that has begun to unravel. As our homes have become farther away from our workplaces and as our need to import oil has increased driving has become more and more expensive and more irksome. And in spite of spectacular efforts to reduce pollution our driving has continued to be a major factor in environmental degradation. Slowly over time these factors have been at the root of a change in behavior that is taking place all over the continent. In all 50 states, and in Canada, programs are arising to limit the number of automobiles on the road during peak driving hours. A number of states have established transportation demand management (TDM) legislation to reduce public road usage. In addition, local governments have established regional traffic mitigation programs to assist local employers in encouraging their workforce to stop driving to work alone. Often these programs enable groups of employers to share incentives and facilities to enhance the commuter experience while reducing costs for both employer and employee. California has no state wide traffic mitigation program, however the recently passed AB1431 (Vehicle Greenhouse Gas Emissions) will almost certainly address the effects of commuting on greenhouse gases. The US Department of Transportation has created a program dubbed “Best Workplaces for Commuters” (BWC) to acknowledge those employers that have done the most to make alternate commute options work the best for their employees. As of June 2007 the site has over 1,400 employers listed as meeting the department’s stringent standard for inclusion on the list. Typically to win acknowledgement employers must provide emergency ride home capabilities for transit and car/van pool commuters, provide some kind of subsidy or support for those not driving to work alone and commit to having 14% of employees participate in the program within 18 months. In addition to the BWC program the Internal Revenue Service permits employers to pay for certain commute benefits with pre-tax dollars, saving money for both employers and employees.110

108 http://www.eia.doe.gov/neic/quickfacts/quickoil.html 109 http://europe.theoildrum.com/node/2653 110 http://www.bwc.gov/



Commute programs exist at the federal, state, county and jobsite levels because they work. In a survey funded by the US Department of Transportation (DOT) in 2004 found that well designed commute programs reduced vehicle trips by an average of 15.3%.111 That kind of reduction pays off. It pays off in savings to the employer, government at all levels and the employee. Most employers are probably so accustomed to providing parking spaces for employees that it is not considered to be a real cost of doing business. Yet some employers must set aside more land for parking than is used for generating income. The Victoria (B.C.) Transport Policy Institute estimated in 2000 that parking lot construction costs can vary between $1500 (US) and $1900 (US) per space. That cost is in addition to the value of the unimproved land. When parking structures become necessary per space costs can exceed $9000 per space. In addition there are annual maintenance costs.112 One estimate of the value to U.S. employers of this unproductive land placed the rental value nationwide at over 35 billion dollars.113 DOT estimates that current freeway construction costs exceed one-quarter million dollars per lane-mile with a continuing cost of about one percent of that amount for annual maintenance. While this cost is not apparent directly to the taxpayer it is there and as more roadways are constructed to accommodate peak traffic loads for commuters both the capital costs of construction and the annual maintenance costs are an increasing burden on taxpayers and on the local officials who must negotiate to find the funds.114 Commute costs to employees is more than the obvious. A UC Berkeley study in 1990 indicated that the average Bay Area one-way commute distance increased between 1980 and 1990 from 10.6 miles to 11.8 and the average duration from 27.7 minutes to 29.0 minutes. Over a 50 week working year that amounts to 5900 miles per year and 242 hours on the road. With per-mile driving costs approaching 50 cents employees are spending almost $3000 per year just to get to work. Since employers do not pay for the time that commuters sit in their cars in heavy traffic it is the individual worker whose time is wasted crawling through traffic. According to the Texas Transportation Institute California commuters who have recently moved to a metropolitan area spend, on average, 250 hours per year in commuter traffic. There are great success stories in communities developing programs to reduce vehicle miles traveled (VMT). Boulder, Colorado has a program called Ride Arrangers that reports having saved 28 million VMT in 2006. Ride Arrangers has 6,000 people in their carpool database, 380 people vanpooling with a waiting list to fill 10 more vans. There are 4,000 “teleworkers” and 11,000 families enrolled in the “schoolpool” database. In the annual Bike to Work Day in 2006 there were 20,000 participants. 115 111 Mitigating Traffic Congestion; Association for Commuter Transportation; PO Box 15542, Washington, DC 20003-0542;2004 112 Todd Litman; Parking Management Strategies, Evaluation and Planning; Victoria Transport Policy Institute; 2006 113 http://72.14.253.104/search?q=cache:biyCdgRbNHQJ:www.commuterchoice.gov/pdf/sanfran/bwc-present-sfa.ppt+sonoma+best+workplaces&hl=en&ct=clnk&cd=2&gl=us&lr=lang_en 114 http://www.publicpurpose.com/hwy-fy$.htm 115 Linda Dowlin, Denver TDM Manager; personal communication; 6/11/07



In the Bay area Contra Costa county reports that their SchoolPool program has reduced VMT by 4 million miles in 20028. The San Mateo County Commute Alternatives Program has mailed 80,000 Commuter Checks to employees of 3,200 employers in the county since 1991.116 C2HM Hill reports a 115,000 mile reduction in VMT in 2002 at a single worksite in Denver. In Seattle the University of Washington estimates that the UPASS program has eliminated 91 million vehicle trips since it was established in 19914. These examples show that in a large variety of environments and over long periods of time employers, employees, taxpayers and the environment are benefiting from well designed commute programs. Today, more than ever in the past, it makes sense to create programs allowing commuters to get out of their cars and find more appropriate ways to get to and from work. The ability of the modern passenger vehicle to take us anywhere we want, when we want is at its least beneficial when we are traveling the same path at the same time of day over many months and years. The rising cost of operation, the increasing time spent unproductively and the anger and frustration so often connected with present day commuting will continue to get worse in the future. We cannot pave the entire nation to enable every person to drive effortlessly where ever they want to go at any time of day. It follows that community leaders in every American community should be emulating the examples of those communities that have gained so much by instituting these programs.

116 http://www.smccap.org/index.jsp



FURTHER READING

1. MASSRides, Massachusetts Office of Transportation; http://www.commute.com/ 2. Burby, John; The Great American Motion Sickness (or Why You Can’t Get There From

Here), Little, Brown and Co., New York; 1971 3. Yergin, Daniel; The Prize; Simon & Schuster, New York; 1991 4. Meadows, Donella et al; The Limits to Growth; The New American Library, New York;

1971 5. Commuter Connections, Metropolitan Council of Governments; Washington DC;

http://www.mwcog.org/commuter/ccindex.html 6. Census Bureau Study of Commute Distances; http://www.census.gov/Press-

Release/www/releases/archives/american_community_survey_acs/001695.html 7. Santa Cruz Commute Solutions; http://www.commutesolutions.org/ 8. Commuter Calculator; http://www.rideworks.com/rwcalc2.htm 9. Strategies for Increasing the Benefits of Commuter Benefits Programs; TCRP Report 87;

Transportation Research Board; 2003 10. Commuter Check; Section 132 (f) pre-tax transportation benefit program;

http://www.commutercheckpremium.com/ 11. Bay Area Commuter Comments; http://www.ibabuzz.com/transportation/ 12. Westchester County New York Commute Program:

http://www.westchestergov.com/smartcommute/programs_services.htm 13. TDM Case Studies and Commuter Testimonials; Transportation Demand Management

Institute of the Association for Commuter Transportation 1518 K St., N.W., #503; Washington, DC 20005; 1997

14. Washington State Commute Trip Reduction Program; http://www.pewclimate.org/states.cfm?ID=14

15. Boulder, CO “GOBoulder program: http://www.bouldercolorado.gov/index.php?option=com_content&task=view&id=705&Itemid=311

16. Accordia Northwest, Inc., Seattle WA; Commute Trip Reduction Program; 17. http://www.commuterchallenge.org/cc/daw99acordia.html 18. Sustainable Transportation Success Stories; Smart Communities Network;

http://www.smartcommunities.ncat.org/transprt/trsstoc.shtml 19. Ride Solutions; Mid Ohio Regional Planning Commission;

http://ridesolutions.morpc.org/ 20. City of Palo Alto Way 2 Go Program; http://www.city.palo-alto.ca.us/transportation-

division/commute-index.html 21. Washington D.C.; Capital Rideshare Program; http://capitolrideshare.com/index.htm



Examples of Successful Programs



7.15 Grease to Gas Augmentation of Digester Gas

“Grease to Gas” Restaurant Trap Grease Collection and Augmentation of Digester Gas Excerpts from Riverside “Project Description” Document dated 4/17/07 Jim Housman, PE (retired) 4/17/08

Summary:

1. Capital cost apparently very low due to use of contracting company picking up and delivering waste to facility. Total expenditures for labor, equipment and laboratory analysis were $85,000 at time of report minus a potential $16k grant from the PUC.

2. Because the city already operated a treatment facility with methane capture, capital investment was only required to adapt the existing system to accept the waste grease.

3. The additional amount of methane gas generated by the addition of the grease wastewater has been as high as 493,000 cubic feet. This is the same as 4,930 therms of natural gas.

4. City receives $6500/mo. in disposal fees from delivery company ($21,000 in 2007) 5. Sewage systems overflows caused by grease trap problems was reduced 6. Biosolids production in the city’s digesters was reduced saving $48,000/month 7. Fuel savings obtained at the site were as high as $85,000/mo. 8. Total savings were over $1M for 9 months.

The city of Riverside, California operates a publicly owned treatment works (POTW) capable of handling 40 million gallons per day. The treatment process is fully tertiary utilizing anaerobic digestion and treats an average daily flow of 35 MGD. The City’s POTW has a cogeneration facility that has the capability of generating about 3 megawatts of power. This cogeneration facility has three internal combustion (IC) engines that use the methane gas produced by the digesters as a fuel source. In addition to the IC engines, the City will be installing a one-megawatt fuel cell that will use digester gas to produce electrical power.

The City’s Public Utilities Department (PUD) was informed of the Grease to Gas project and was quite interested due to the renewable energy source created by the processing of the grease wastewater. The PUD also oversees a grant program for renewable energy resources. The Grease to Gas project qualified for a grant and the PUD prepared a report for the Utilities Board for approval of $16,237 to cover the costs of laboratory services and analyses and equipment purchases and installation. The grant was approved on June 29, 2005. The total costs to date for labor, laboratory analyses, and equipment is approximately $85,000.

The company agreed to charge City restaurants $0.10/gallon to pump the grease interceptors (underground tanks connected to the restaurant wastewater drains). Other vacuum companies were charging $0.15 to $0.20/gallon to pump the interceptors. The contracted company also brings grease wastewater from other areas throughout southern California, from Santa Barbara to San Diego and from Los Angeles to Blythe. The City charges the company $0.01/gallon ($0.03/gallon in 2007) to receive the wastewater for disposal and receives about $6,500/month in disposal fees. The project currently receives about 30,000 gallons per day of grease wastewater



from restaurants in the southern California and, since March 27, 2006 has processed 6,800,000 gallons of grease wastewater.

The additional amount of methane gas generated by the addition of the grease wastewater has been as high as 493,000 cubic feet. This is the same as 4,930 therms of natural gas (100 therms per cubit foot). This is enough gas generated in one day to supply the winter needs of 101 homes in Riverside and the summer needs of 340. In one month, the gas generated at the treatment plant can be as high as 17,898,961 cubic feet or 178,989 therms. This is enough gas to supply the winter needs of 3,674 homes in Riverside and the summer needs of 13,055 homes in Riverside. The daily electrical generation of 1.5 megawatt-hours is enough electrical power to supply the needs of 1,128 homes in Riverside.

The effects on the sewer system were equally favorable. The sanitary sewer overflows (SSOs) caused by restaurant grease blockages were reduced from 30% of all calls to less than 1%.

An additional benefit of the project was the observed reduction in the amount of biosolids created from the treatment process. Since the introduction of grease wastewater into the digester, the number of methane forming bacteria has increased dramatically. These bacteria are also better adapted to metabolize solid organic material in the digester. As a result of the increased bacterial population, the overall biosolids production has been reduced by about 25%. This has reduced the average monthly wet tons produced from 5,000 to about 4,000. The disposal fee is $48/ton and a reduction of 1,000 tons per month saves $48,000/month.

One goal of this project is to achieve energy independence from natural gas. The project has reduced the natural gas requirements of the cogeneration power plant by 80%. This yielded a monthly savings ranging from $80,000 to $85,000 per month. The energy costs savings, reduced costs for biosolids disposal, and wastewater treatment charges created by this project have saved the City over $1,000,000 in nine months.

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