DESALINATION TASK FORCE MEMORANDUM

TO: DESALINATION TASK FORCE FROM: PROGRAM MANAGERS SUBJECT: ENERGY STUDY STATUS REPORT, PROJECT ASSESSMENT REVIEW, AND DISCUSSION ON PROJECT EVALUATION, SCORING AND RANKING METHODOLOGY DATE: OCTOBER 19, 2011 RECOMMENDATION: That the scwd2 Desalination Task Force receive the sixth Energy Study status report and schedule, provide feedback on the attached 16 draft Project Assessments (dPAs), receive an update on the October 13, 2011 Energy Study Technical Working Group (ETWG) Workshop, and provide feedback on the scoring, ranking and selection methodologies being described below and in the attached document(s). BACKGROUND: This memorandum serves as the sixth status report and will update the Task Force on work progress with regard to the Energy Minimization and Greenhouse Gas Reduction Study (Energy Study). With guidance from members of the ETWG and additional local energy experts, the Energy Study work to date has focused on establishing the potential energy use of the facility, further understanding the CEQA and regulatory framework used to evaluate that energy use, and vetting potential projects that could be implemented to reduce energy and indirect GHG impacts of the project. Sixteen projects (which can be generally categorized as water and energy efficiency projects, renewable energy projects, and/or GHG reduction projects) were recommended for in-depth evaluation by the ETWG. (For simplicity, the 16 projects will be collectively referred to as GHG reduction projects for the remainder of the document.) The dPAs provide a framework for understanding the project efficiency, and relative economic and social costs. These factors may ultimately be used to assemble cost effective and community-valued GHG reduction project portfolios, the foundation of the Energy Minimization and GHG Reduction Plan. At its September meeting, the Task Force was given an introduction to the dPAs to provide context to their content and layout as well as a sample dPA. Task Force members were informed about the second ETWG Workshop, scheduled to take place on October 13, 2011. Task Force members reiterated the importance of continued engagement with the ETWG, requesting again that the ETWG provide feedback on the dPAs and proposed project scoring, ranking and sensitivity analysis. DISCUSSION: Energy Study Schedule and Work Flow As mentioned in previous status reports, the Energy Study is being developed in stages. An outline of the tasks involved and their status is presented below. 1. Define the potential energy use and associated indirect GHGs of the desalination facility. Complete.

11 2. Identify a range of potential GHG reduction goals for future consideration. Ongoing with no noteworthy update at this time. 3. Identify and assess potential GHG reduction projects. See Item 4. 4. Score and rank the projects according to the evaluation criteria and sensitivity analysis. Ongoing. Objectives of the October ETWG Workshop include receiving ETWG feedback on the dPAs, and to identify, discuss and recommend a methodology by which projects can be ultimately selected by each agency. 5. Recommend a portfolio of projects to meet a range of potential goals for each agency. Not yet started. Energy Study work remains on schedule and generally follows the timeline below.

Item Corresponding Participants Approximate Task No. Date Identify CEQA threshold of 2 EIR consultant Late October significance Sept. 21st – Oct. TF and ETWG review of 16 dPAs 3 TF, ETWG 19th ETWG meet to review dPAs and Staff, Kennedy/Jenks develop methodology for project 4 October 13th (K/J), ETWG evaluation and selection Review TF comments on dPAs and TF, Staff, K/J, October TF 4 present ETWG meeting results ETWG meeting Review GHG reduction project selection results, review feasible project portfolios to meet range of TF, Staff, K/J, November TF 4 GHG reduction goals, discuss draft ETWG meeting Energy Minimization and GHG Reduction Plan content and structure Prepare the draft Energy Mid Nov. – Mid Minimization and GHG Reduction 5 Staff, K/J Dec. Plan Energy Community Informational Staff, K/J, ETWG, N/A December Meeting community Discuss Community Informational Meeting, discuss noteworthy comments and considerations, December TF 5 TF, Staff incorporate comments into draft meeting Energy Minimization and GHG Reduction plan ETWG review the draft Energy Minimization and GHG Reduction 5 Staff, K/J, ETWG January Plan Present the draft Energy Minimization TF, Staff, K/J, February TF and GHG Reduction Plan to the scwd2 5 ETWG meeting Task Force

12 Previously Approved Project Evaluation Criteria, Scoring, Ranking and Sensitivity Analysis Over the last several months, staff and K/J have developed a comprehensive process for evaluating, scoring and ranking the potential GHG reduction projects. The goal of the process is to provide a framework to assess the attributes of each project as well as to identify the methodology for selecting project(s) that best suit the community. At its June and July meetings, the Task Force preliminarily approved the evaluation criteria, weightings and sensitivity analyses as follows but did request that additional feedback be received by the ETWG during the continued development of the Energy Study. Approved Evaluation Criteria, Weighting and Sensitivity Analysis

Proposed Sensitivity Analyses TF Recommended Evaluation Criteria Weighting Cost- Local- Weighting Other Range Focused Focused Local Benefit 15 to 20% 20% 10% 50% 20% Energy Produced or 10 to 15% 10% 5% 10% 15% GHG Reduced Technical Maturity 15 to 25% 10% 5% 10% 15% Sustainability* 10 to 15% 5% 2.5% 2.5% 10% Reliability and Operational 5 to 10% 5% 2.5% 2.5% 5% Complexity Cost/Cost 15 to 50% 50% 75% 25% 35% Effectiveness Total 100% 100% 100% 100% *Sustainability was added as an evaluation criterion at the July TF meeting. This project selection process closely resembles the method used for narrowing down alternatives in other components of the scwd2 desalination programmatic evaluation. The sequencing of the methodology is outlined below. 1. Establish project evaluation criteria. 2. Establish an evaluation criteria weighting. 3. Evaluate and define each project in relation to each evaluation criterion. 4. Score each project with respect to each evaluation criterion. 5. Perform a sensitivity analysis on evaluation criteria weightings to determine the effect of policy considerations on project ranking. Additional sensitivity analyses could be added to attempt to capture additional economic and non-economic policy considerations. 6. Assemble GHG reduction project portfolios based on results of sensitivity analysis. The attached, scwd2 Evaluation Criteria Scoring and Weighting Sensitivity Analysis, provides an overview of this methodology.

13 Alternative Project Selection Methodologies Staff requested preliminary feedback from the ETWG with regard to the methodology outlined above. Several ETWG members identified other methods for project evaluation and selection. A main objective of the October 13, 2011 ETWG Workshop will be to come to a consensus with regard to the most appropriate project evaluation and selection methodology. The distinctions between the current and alternative methodologies are outlined below. Distinction One According to the ETWG members, the primary responsibility of a public agency is to pursue the most cost effective GHG reduction projects to maximize return on investment (ROI). Maximizing ROI should first be done from a purely economic perspective and should follow the basic rule of prudent economic investing; build a diverse portfolio. Synonymous with capital or retirement investing, a diverse GHG reduction project portfolio should be assembled with different types of projects to minimize risk and maximize rate of return, profitability and flexibility. Different economic variables can be used to identify GHG reduction projects that are analogous with: • certificates of deposit (long-term investment, low risk, lower rate of return) • bonds or mutual funds (middle-term investment, medium risk, medium rate of return) • stocks (short term investment, higher risk, potential for quick high rate of return) Once projects are grouped into the three investment categories, a policy consideration with regard to what percentage of each category should make up the portfolio can to be made to maximize ROI and flexibility and minimize risk. This approach differs from the approved project selection methodology in that it maximizes ROI and builds a diverse portfolio before attempting to score and rank the projects. It also differs by identifying additional economic policy considerations in project portfolio selection. The approved approach scores and ranks the projects according to Net Present Value (NPV) only and does not necessarily take into consideration the other economic policy considerations and nuances involved in creating a diverse portfolio. (Or, it may take into consideration these different economic policy considerations, but only after scoring and ranking based on NPV). This new approach identifies the economic policy considerations and nuances first and then ranks and groups the projects with those in mind.

Once a thorough economic analysis is done, agencies can then focus on the non-economic policy considerations. This process is described below in greater detail. Distinction Two This new approach separates project evaluation into two stages which are iterative. The first stage, as described in Distinction One, ranks projects through economic considerations. The next stage defines the policy considerations needed to finalize the project evaluation, and reexamines each of the projects to see if it meets that policy objective. For example, an economically derived project portfolio consists of projects A, B, and C. During the second stage, decision makers realize that none of these projects meet a policy decision made to have 50% of the projects installed locally. The decision makers can at that point choose to adjust the portfolio to meet this policy objective, but then can circle back to stage one to confirm the economic viability of the new portfolio. According to some experts in the field, policy choices should follow a thorough understanding of the economics.

14 This distinction differs from the approved project selection methodology in that additional policy-based evaluation criteria may be added down the road in the process. It also does not attempt to score, based on a scale of one to ten, the purely subjective policy-focused evaluation criteria. Scoring the subjective criteria may or may not shed light on the intricate policy-based preferences or fatal flaws. Not attempting to score the subjective criteria gives agencies an opportunity to be flexible about policy considerations when assembling the project portfolios. Through this iterative process, an opportunity arises to zero in and act upon the most important community influences on project portfolio selection. The following policy-based evaluation criteria have been identified through research and discussions with ETWG members and may be selected by the decision makers in assembling a project portfolio. 1. Project is relatively simple to implement with no/fewer construction/environmental hurdles. 2. Project embodies a water/energy nexus. 3. Project presents the potential for accountable/real/tangible GHG emissions reductions that are NOT dependent on customer behavior or participation. 4. There is funding available from various sources including borrowing, incentives from government and utilities, and grants from foundations that make the project more attainable. 5. Project has other negative costs: maintenance, impacts on safety, health, comfort, or productivity. 6. Project has other benefits: maintenance savings realized elsewhere; capital improvement; improved safety, comfort, or productivity; public relations value, etc.. 7. Project establishes a relationship to other possible energy saving or GHG emissions mitigation measures and synergistic opportunities. 8. Project provides interaction with state or regional GHG mitigation initiatives. 9. Project has potential to scale upward. 10. There is organizational capacity to undertake and manage the project. 11. There is alignment with City CAP and/or other regional plans. 12. Project has stakeholder support and enthusiasm.

Summary of Potential Project Selection Alternative The potential sequencing of the alternative methodology is outlined below. 1. Maximize ROI and flexibility and minimize risk by assembling a diverse project portfolio. 2. Establish key policy drivers for each agency (Task Force recommendation to governing bodies). 3. Confirm that project portfolios fulfill agency-specific policy missions. 4. If needed, rearrange project portfolios to encompass required policy missions. These two different approaches will be discussed at the October 13 ETWG meeting, and staff will present the outcomes from that Workshop at the October 19, 2011 Task Force meeting. FISCAL IMPACT: There is no fiscal impact associated with this item. ATTACHMENTS: Draft scwd2 GHG Reduction Project Assessments Evaluation Criteria Scoring and Weighting Sensitivity Analysis

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Draft scwd2 GHG Reduction Project Assessments

Introduction

Sixteen greenhouse gas (GHG) reduction projects are currently being evaluated as part of the scwd2 Energy Minimization and GHG Reduction Study (Energy Study). The 16 projects were selected collaboratively with input from Task Force members, Energy Study Technical Working Group (ETWG) members, City and District staff, Energy Study Technical Advisors Kennedy/Jenks, and additional community members. The attached 16 Draft Project Assessments (DPA) provide information and preliminary analysis of the GHG reduction project evaluations.

Project and Energy Study Background

The energy requirement of seawater desalination as a supplemental supply is among the key issues in the evaluation of the proposed project. scwd2 is conducting an Energy Study to ensure that the most advanced and energy efficient technologies and approaches are identified and incorporated into the proposed desalination project. Indirect GHG emissions are attributed to the proposed project from the purchased power to treat and distribute desalinated water. The Energy Plan will also explore ways the agencies can offset all or a portion of the GHGs that are indirectly associated with the desalination project.

As part of the Energy Study, scwd2 convened an Energy Technical Working Group (ETWG) to provide independent scientific review and guidance on the planning, execution, and reporting of the energy aspects of the Desalination Program. During the Energy Study Project Workshop in June 2011, the ETWG and other workshop participants reviewed over 45 projects and identified fifteen to evaluate further. Another project was later added by the scwd2 Task Force. The potential GHG reduction projects are broadly categorized as: • Water and energy efficiency projects • Renewable energy projects • GHG Offset projects (match table below and PPT)

Table 1 lists the sixteen projects that were evaluated in more detail:

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Table 1: GHG Reduction Project Assessments

PA # Project Title Water and Energy Efficiency Projects 1 Additional Water Conservation Activities 2 Recycled Water Projects 3 Residential/Commercial Energy Efficiency and Renewables Rebates/Incentives 4 Graywater and Rainwater Programs 5 Improved Digester Mixing System at Santa Cruz WWTP 6 Energy Audit Recommended Improvements at Santa Cruz WWTP 7 Pump and Motor Efficiency Improvement Program Renewable Energy Projects 8 Food Waste to Energy Project 9 Renewable Energy Purchase Programs 10 Local Solar Projects 11 Fuel Cells 12 Microhydro at Graham Hill WTP 13 Hydropower Project at Lake Nacimiento GHG Offset Projects 14 GHG Offset Purchases 15 Fleet Fuel Reduction Program 16 Carbon Dioxide Addition for Post-Treatment

Project Assessment Components

The scwd2 GHG reduction Draft PAs have been developed using a common format to facilitate comparing and contrasting the various efficiency, renewable energy and GHG offset project options. The DPAs include the following nine sections which are based on the project evaluation criteria.

1. Executive Summary – The first page of each DPA presents an executive summary that describes the project, the potential expected amount of GHG reduction, the project lifetime and sustainability of the GHG reduction, and the conceptual cost of the project.

2. Project Description – This section provides a description of the project, background information on the program or technology, and vendors that could provide equipment or services related to the project.

3. History and Technical Maturity – This section provides a discussion of the history of the technology or program, the stage of research and/or development of the technology, and existing systems or programs that SCWD or SqCWD have experience with.

4. Reliability and Operational Complexity – This section discusses the proven performance, stage of research and/or development, and reliability of the proposed project. Reliability of the project is the ability of the project to produce the expected GHG reductions. This section also discusses the operational complexity of the project.

5. Sustainability – This section describes the project life and the sustainability of the project to provide GHG reductions (and/or water and energy savings) over a long period scwd2 Desalination Program, GHG Reduction Project Assessments Page I-2 K/J Project No. 0868005*03, version 9/21/2011 17

of time, assuming proper maintenance to the system. For example, a solar project will provide GHG reductions for the 20 to 30 year life of the solar equipment. The solar equipment can be replaced and the renewable energy and GHG reductions can be sustained into the future. An efficiency project only provides a GHG reduction for the accelerated period of the equipment replacement. Efficiency projects do not provide sustained GHG reductions into the future due to the requirement for GHG reductions to be “additional” to what would happen in the absence of proposed project.

6. Local Considerations – This section describes the local economic and social benefits of the proposed project to the community and considers the environmental and community factors related to the proposed projects. Local considerations include: a. Helping to improve the local economy through local construction, job creation, and training b. Helping to educate and inform the community on water, energy and sustainability issues c. Reduction of local energy consumption and/or reduction of local GHG emissions d. Reduction/reuse of local waste generation e. Impacts on the air, land, water, noise, aesthetic/visual, and if it creates waste by- products

7. Energy Production, Energy Savings, and GHG Reduction – This section describes the expected amount of energy saved, renewable energy produced, or GHG mitigated by a proposed project. In many of the Draft PAs, the GHG reductions are calculated separately for SCWD and for SqCWD to account for different proposed operating scenarios for the desalination facility and different project specific factors for each agency.Eligibility criteria for renewable energy projects have been developed by the US Department of Energy and state agencies such as the California Energy Commission (CEC) Emerging Renewables Program. GHG reduction projects pursued by scwd2 should meet these eligibility criteria in order to be recognized by regulatory agencies.

8. Cost / Cost Effectiveness – This section provides a summary of the conceptual level costs for the project, and develops a GHG reduction cost effectiveness factor in dollars per metric ton of equivalent carbon dioxide reduced ($/MT CO2e). A cost summary table is provided for each project that summarizes the cost categories described below:

a. Conceptual Capital Costs: The conceptual level capital costs generally include equipment, engineering and construction or installation. For efficiency rebate programs, the money for the rebates was assumed to be set aside as a capital cost reduction. For some projects, applicable PG&E rebates or incentives that could reduce the project capital costs are included.

b. Conceptual O&M Costs: The conceptual level operations and maintenance (O&M) costs include labor, materials, and applicable fuel, chemical, or other operating costs. For efficiency rebate programs, the money for marketing was assumed to be an operating cost. For efficiency and renewable energy projects that reduce the cost of energy purchased from the grid, the savings are included to reduce O&M costs.

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c. Average Annual Net Costs: This represents the average of the calculated annual net costs for a project, and is intended to show the magnitude of the annual cost of implementing the project. The net cost is calculated by subtracting the project costs from the project benefits for each year of operation. Project costs include debt service on the capital cost of the project (if any), O&M costs, and any fuel costs. Benefits include any cash payments paid by PG&E as an incentive and the avoided cost of electricity that results from saving or generating electricity.

d. Lifecycle Energy Cost ($/KWh): Lifecycle cost is a tool to gauge the cost effectiveness of the project. The net present value (NPV) of the Annual Net Cost is used for this calculation. This eliminates the effects of inflation, the different cost characteristics of projects, and the different lives of projects. A NPV calculation converts the Annual Net Costs to present day dollars, and creates a levelized cost in $/KWh.

e. Lifecycle CO2 Reduction Cost ($/MT): This metric is similar to the Lifecycle Energy Cost but reflects the cost of the reduced metric tons of GHG rather than the energy saved or generated. The calculation is the same except for the denominator changes from energy (KWh) to metric tons reduced (MT). This metric is expressed in $/MT.

9. Summary of Advantages and Disadvantages – This section provides an overview of general advantages and disadvantages of the project.

Next Steps - Project Assessment Scoring and Ranking

The proposed project evaluation criteria are as follows: 1. Local Benefit and Considerations 2. Energy Production or GHG Reduction 3. Technical Maturity 4. Sustainability 5. Reliability and Operational Complexity 6. Cost / Cost Effectiveness

The recommended project evaluation criteria would be applied to evaluate, score, and rank the proposed GHG reduction projects. The project evaluation criteria could have different weightings based on the relative importance of the criteria for the overall Program objectives. With six evaluation criteria, the average weighting, based on 100-percent total weight, is approximately 15-percent. Therefore, the weighting of criteria could categorized, for example, with those criteria of higher relative importance having a higher than average weighting.

SCWD and SqCWD staff has worked with Energy Study Technical Advisor, Kennedy/Jenks to identify a proposed weighting range for each evaluation criterion. Based on feedback from the Task Force and the ETWG, the range for each criterion was refined to a recommended weighting. In addition, several proposed sensitivity analyses were developed to vary the weight of some of the factors. The recommended weightings of the evaluation criteria and example potential sensitivity analysis weightings are shown in Table 2.

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Table 2: Recommended Weighting and Example Sensitivity Analysis Weightings for Evaluation Criteria

Proposed Sensitivity Analyses Recommended Evaluation Criteria Weighting Cost- Local- Weighting Other Range Focused Focused Local Benefit 15 to 20% 20% 10% 50% 20% Energy Produced or 10 to 15% 10% 5% 10% 15% GHG Reduced Technical Maturity 15 to 25% 10% 5% 10% 15% Sustainability 10 to 15% 5% 2.5% 2.5% 10% Reliability and Operational 5 to 10% 5% 2.5% 2.5% 5% Complexity Cost/Cost 15 to 25% 50% 75% 25% 35% Effectiveness Total 100% 100% 100% 100%

This report, including the sixteen PAs, will be distributed to the ETWG members for their review and comment. scwd2 staff will hold a second Energy Study Project Workshop in October 2011 during which time the ETWG will use the above criteria to evaluate, score, and rank the proposed 16 GHG reduction projects. The results of this ranking will be presented to the scwd2 Task Force for review and comment.

Next Steps – Portfolio of GHG Reduction Projects

Based on the project rankings, a recommended portfolio of projects will be developed for SCWD and for SqCWD to meet the range of potential GHG reduction goals for the scwd2 Desalination Program. The recommended portfolio of projects for each agency will be presented to the ETWG and the scwd2 Task Force for review and comment.

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Project Assessment Attachments

1 Additional Water Conservation Activities 2 Recycled Water Projects 3 Residential/Commercial Energy Efficiency and Renewables Rebates/Incentives 4 Graywater and Rainwater Programs 5 Improved Digester Mixing System at Santa Cruz WWTP 6 Energy Audit Recommended Improvements at Santa Cruz WWTP 7 Pump and Motor Efficiency Improvement Program 8 Food Waste to Energy Project 9 Renewable Energy Purchase Programs 10 Local Solar Projects 11 Fuel Cells 12 Microhydro at Graham Hill WTP 13 Hydropower Project at Lake Nacimiento 14 GHG Offset Purchases 15 Fleet Fuel Reduction Program 16 Carbon Dioxide Addition for Post-Treatment

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Executive Summary: Draft PA No. 1 – Additional Water Conservation Activities

Description Additional or accelerated water conservation programs that focus on the energy efficiency of water consuming appliances would directly save energy and promote reduction of potable water use. The reduction of GHG emissions associated with this project would primarily be from the direct energy savings of using a more energy efficient washer and the indirect energy savings of using less potable water. SCWD and SqCWD already have robust overall water conservation programs. This project would accelerate the existing washing machine replacement program by increasing the number of rebates for residential washers and more aggressively targeting commercial high efficiency washing machines.

Amount of GHG Reduction The estimated GHG reductions rely on participation in the program and may be less than estimated if actual participation is less than assumed by this project assessment. Assuming 750 additional customers per year install high efficiency front loading washing machines, this program could reduce water and energy consumption and could potentially provide an annualized GHG reduction of approximately 240 MT CO2e per year for SCWD and 213 MT CO2e per year for SqCWD. The majority of these savings are direct energy reduction from the more efficient machine (80 to 90%); a smaller portion is indirect savings from lower water use. This project could reduce approximately 35 to 55% of the potential GHG reduction goals for SCWD, and 12 to 15% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability Due to the criteria of additionality, only new or accelerated programs, beyond the existing programs described above, can be counted as a GHG reduction project for the scwd2 Desalination Program. For SCWD and SqCWD, the additional GHG reduction credit from these accelerated programs is estimated to have a 12 year lifetime, since it is assumed that in 12 years, or less, customers would have signed up through the existing programs offered by SCWD and SqCWD. Also, a washing machine replaced through this program is expected to last approximately 12 years.

Project Cost For SCWD, this project is estimated to have an average annual net cost of approximately $167,000 per year, or approximately $600 per MT CO2e. For SqCWD, this project is estimated to have an average annual net cost of approximately $110,000 per year, or approximately $460 per MT CO2e.

Table ES-1: Additional Water Conservation Project Summary

Avg Annual Capital Average Lifecycle Lifecycle GHG Life Agency GHG Reduction Cost ($ Annual Net Energy Cost Reduction (yr) (MT CO2e/yr) mil) Cost ($/yr) ($/kWh) Cost ($/MT) SCWD 12 240 $2.6 $167,000 $0.19/kWh $600 SqCWD 12 213 $1.9 $110,000 $0.15/kWh $460

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Draft Project Assessment No. 1 – Additional Water Conservation Activities

Description

This assessment estimates the energy savings and GHG reduction potential from the development of an additional or accelerated water conservation program.

Background SCWD and SqCWD have robust water conservation programs designed to maximize water savings and incorporate latest technologies and practices. Programs are developed to ensure compliance with state requirements, most recently the SBx7-7 demand reduction goals. The proposed program would build on existing activity and reduce energy consumption and indirect GHG emissions from washing machine use throughout the SCWD and SqCWD areas by providing customers with incentives to purchase high efficiency machines.

High-efficiency clothes washers (HEW) deliver high level wash performance while saving both water and energy. Resource efficient models use 35 to 50% less water and approximately 50% less energy to heat the water.

Existing SCWD Program SCWD has offered a clothes washer rebate program to its residential and commercial customers since 2000, primarily as a water conservation measure. The program currently provides a $100 rebate as an incentive to choose HEWs. As a signatory to the CUWCC’s Memorandum of Understanding Regarding Urban Water Conservation in California, the program is one of several Best Management Practices (BMPs) SCWD has committed to implement. Since 2000, SCWD has issued between 500 and 700 rebates per year, which has generated an estimated cumulative total water savings of 44.3 million gallons of water per year through 2010. The current program provides rebates to any machine that has an ENERGY STAR label.

Existing SqCWD Program SqCWD has been offering rebates for high-efficiency clothes washing machines since 1999. It first offered a $100 credit to residential customers who purchased and installed approved HEWs. The program has since expanded to include a $200 rebate to commercial customers who install ENERGY STAR HEWs.

Since 1999, 3,467 residential and 46 commercial HEW rebates have been issued by SqCWD; this is an average of approximately 293 rebates per year. SqCWD has been considering modifications to the commercial washer rebate program in an effort to increase participation, particularly among coin-operated laundries that are using multi-load washers. The multi-load commercial washers are significantly more expensive than single-load washers used in most residences, and an increase in the current rebate amount of $200 may entice commercial laundry owners to retrofit these units.

Although there currently is not an estimate of local market saturation at this time, according to the 2007 California Single Family Water Use Efficiency Study, only about one-third of homes were using HEWs of 30 gallons per load or less. It is expected that there is still a strong

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potential for energy and water conservation in improving the efficiency of clothes washers. SCWD currently is performing a market penetration analysis to determine the fixture efficiency and saturation in its service area. The results of this analysis will better inform the savings estimates developed in the proposed program and will be incorporated as soon as they are available.

Proposed Additional Program The proposed program would offer a rebate of $400 as an incentive to residential customers and $800 for commercial customers who purchase clothes washers meeting the California Energy Commission’s (CEC) most efficient, Tier 3 specifications. The goal in offering this rebate is to make the net cost of HEWs less than the cost of conventional clothes washers for the consumer, in order to accelerate the number of customers who participate in adopting this technology. Compared to a standard top loading machine with a water factor of 13, a Tier 3 machine would save an estimated 28 gallons of water per day or almost 10,000 gallons per year and a high-efficiency commercial washer retrofit saves about 15,586 gallons per year per unit. The HEWs are also more energy efficient than standard top loading machines, therefore the rebate program could provide energy savings from both the machines themselves, and from the associated energy to provide potable water.

Based on discussions with the SCWD and SQCWD Water Conservation Directors, the project assessment estimates an increase in current participation rates to provide rebates for an additional 375 residential top loading HEWs and 63 commercial HEWs per year for SCWD. This would be an approximately 60% increase in current participation rates. The project assessment estimates an increase in current participation rates to provide rebates for an additional 250 residential top loading HEWs and 62 commercial HEWs per year for SqCWD. This would approximately double the current participation rates.

Table 1 estimates the number of additional rebates and water savings that could be achieved over the life of this program.

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Table 1: Estimated Water Savings from Washing Machine Rebate Conservation Program SCWD SqCWD Total Additional Rebates Total Total Additional Rebates Total Year Water Water Residential Commercial Savings Residential Commercial Savings (MGY) (MGY) 1 375 63 5 250 62 4 2 750 126 10 500 124 7 3 1,125 189 14 750 186 11 4 1,500 252 19 1,000 248 14 5 1,875 315 24 1,250 310 18 6 2,250 378 29 1,500 372 21 7 2,625 441 34 1,750 434 25 8 3,000 504 39 2,000 496 28 9 3,375 567 43 2,250 558 32 10 3,750 630 48 2,000 620 35 11 4,125 693 53 2,750 682 39 12 4,500 756 58 3,000 744 42 Average Annual Water Savings (MGY) 31 23

Performance Metrics In 2004, the CEC adopted tiered water and energy efficiency standards for clothes washers. The CEC high-efficiency clothes washer specifications have two parts: energy consumption (Modified Energy Factor) and water usage (Water Factor).

Modified Energy Factor (MEF) is the energy performance metric for ENERGY STAR qualified clothes washers and all clothes washers as of January 1, 2004. MEF, expressed in ft3/kWh/cycle, is the quotient of the capacity of the clothes container, C, divided by the total clothes washer energy consumption per cycle, with such energy consumption expressed as the sum of the machine electrical energy consumption, M, the hot water energy consumption, E, and the energy required for removal of the remaining moisture in the wash load, D. The higher the value, the more efficient the clothes washer is. The higher the MEF, the more efficient the washer. The equation is shown below: C MEF = M + E + D

Water Factor (WF) is measured by the quantity of water (gallons) used to wash each cubic foot of laundry. WF is the quotient of the total weighted per-cycle water consumption, Q, divided by the capacity of the clothes washer, C.. The lower the water factor rating, the more water efficient the clothes washer. A clothes washer with a water factor rating of 6 uses half the amount of water compared to a washer with a rating of 12, to clean the same amount of clothes. A typical clothes washer has a water factor rating of 12 to 13. Water efficient clothes washers have water factor ratings of 9.5 or less. Some super efficient machines have ratings lower than 5. The equation is shown below: Q WF = C

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The federal EnergyGuide label on clothes washers shows annual energy consumption and cost. These figures use the energy factor, average cycles per year, and the average cost of energy to to estimate energy consumption and cost. The ENERGY STAR criteria for clothes washers changed on January 1, 2011. The new ENERGY STAR criteria require all qualified products to have a Modified Energy Factor (MEF) of 2.0 or greater as well as a Water Factor (WF) of 6.0 or lower

The CEC developed high efficiency specifications for residential clothes washers as part of its Super Efficient Home Appliances initiative (Table 2). This program will provide incentive for the most efficient CEC, Tier 3 specification.

Table 2: CEC HEW Specifications Tier MEF WF Federal Standard 1.26 9.5 ENERGY STAR 2.00 6.0 CEC Tier 1 2.00 6.0 CEC Tier 2 2.20 4.5 CEC Tier 3 2.40 4.0

Vendors Over 100 models of residential and commercial high-efficiency washers are offered by companies such as Continental, Dexter, GE, Huebsch, Maytag, Speed Queen, Staber, Unimac, Wascomat, and Whirlpool. The proposed program expansion will build on the structure and administration of the current program.

History and Technical Maturity

State and Utility Rebates Washing machine rebate programs have been implemented by water agencies and energy utilities in California for over a decade and are an element of many statewide programs, such as the California Urban Water Conservation Council’s (CUWCC) One Stop Rebate program. The programs have been successful in terms of both customer participation and water and energy savings.

PG&E also offers a rebate for qualifying clothes washer models. Models must be CEE Tier 2 or higher, so using CEE list as qualifying criteria is already being practiced by energy utilities and should not be a problem for customers to use.

Energy and water utilities have been promoting efficient washers and providing rebates for over a decade. In addition, through the Super-Efficient Home Appliances Initiative, CEE promotes the manufacture and sales of energy-efficient clothes washers and has developed a set of specifications and a qualifying products list to define energy efficiency. The CEE works with initiative participants (utilities and energy organizations) to promote qualifying washers through incentive, educational and promotional programs. Tier 3 Machines are widely available at retail locations.

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Reliability and Operational Complexity The reliability of this and other rebate programs to provide GHG reductions will depend on the participation rate in the program. Participation can be increased through public education and advertising campaigns, however, participation is not guaranteed. The actual program participation rates would need to be confirmed on an annual basis and additional efforts made to promote the program if participation is below target.

Since the proposed program is an expansion of a successful long-standing program, operational impacts are expected to be minor. There will potentially be an increase in outreach and rebate processing but the program will not require and new processes to be developed. It is expected that staffing will need to be expanded by about 0.2 FTE to process the increase in rebates. There are no major risks identified with this project. If it is not successful, the rebates would not be issued and the program would be discontinued.

Project Life and Sustainability Due to the criteria of additionality, only new or accelerated programs, beyond the existing programs described above, can be counted as a GHG reduction project for the scwd2 Desalination Program. Additional projects have to create “reductions in emissions that are additional to any that would occur in the absence of the certified project activity” (Kyoto Protocol, Article 12.5).

For SCWD and SqCWD, the additional GHG reduction credit from these accelerated programs is estimated to have a 12 year lifetime, since it is assumed that in 12 years, or less, customers would have signed up through the existing programs offered by SCWD and SqCWD. A washing machine replaced through this program is expected to last approximately 12 years. Therefore, the GHG reduction credits for this program are assumed to last only for up to a 12-year period. A customer that signs up in year 4 would only receive credit for 12 – 4 = 8 years of GHG reductions. At the end of the 12-year project life, an assessment could be made to determine if continuing the program would provide additional GHG reduction credits.

Local Considerations Economic This project would have local economic and environmental benefits. Local washing machine suppliers would get an increase in business as more machines are replaced. Although the primary purpose is energy savings, the program would also accelerate long-term water savings and reduce local GHG emissions throughout the water service area and help reduce per capita water use.

Environment Air: The air quality will be enhanced and GHGs reduced because of the reduction in the consumption of electricity.

Land: no impacts

Water: This program could potentially decrease potable water demand.

Noise: no impacts

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Aesthetic/Visual: no impacts

Waste by-product: this project will reduce the amount of wastewater that will need to be processed. The disposal of old washing machine could create waste but much of the old machines can be recycled as scrap materials.

Energy Savings and GHG Reductions This project directly saves energy and reduces GHGs at each residence or commercial location, as well as indirectly by reducing the amount of water used by washing machines. The washing machine energy savings is related to more efficient operation, heating of water, and less drying energy (due to high spin cycles that remove excess water) as compared to standard washing machines. The reduced water use also saves energy associated with the production and delivery of potable water.

The program proposes to increase current participation rates and provide rebates for an additional 375 residential and 63 commercial HEWs per year for SCWD, and an additional 250 residential and 62 commercial HEWs per year for SqCWD. These rebates will supplement the standard ENERGY STAR incentives currently being offered (see discussion in History and Technical Maturity section). Incentives would be available to both residential and commercial customers, and this analysis assumes that about 10% of the rebates will be for commercial uses.

The majority of these savings are direct energy reduction from the more efficient machine (80 to 90%); a smaller portion is indirect savings from lower water use. The direct energy savings are approximately 224 kWh per year for each residential HEW, and approximately 543 kWh per year for each commercial HEW. This averages approximately 768,000 kWh per year for SCWD and 583,000 kWh per year for SqCWD over the life of the program.

The estimated average indirect energy savings from the reduction of potable water demand are shown in Table 3.

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Table 3: Estimated Water and Indirect Energy Savings by Agency Santa Cruz Water Department Average water conservation (over 12 year program) 31 MGY Surface water power factor 1.3 kWh/kgal Desalination power factor 14.5 kWh/kgal 86% surface water SCWD drought year blend assumed 14% desalination Non-drought year net energy savings 40,680 kWh/yr Drought year net energy savings 100,058 kWh/yr Average annualized energy savings1 57,645 kWh/yr

Average annualized GHG reduction 17 MT CO2e Soquel Creek Water District Average water conservation (over 12 year program) 23 MGY Groundwater power factor 2.1 kWh/kgal Desalination power factor 14.5 kWh/kgal 62% groundwater SqCWD non-drought year blend assumed 38% desalination 71% groundwater SqCWD drought year blend assumed 29% desalination Non-drought year net energy savings 156,477 kWh/yr Drought year net energy savings 131,017 kWh/yr Average annualized energy savings1 149,203 kWh/yr

Average annualized GHG reduction 43 MT CO2e 1Assumes 5 non-drought and 2 drought years every 7 years.

Table 4 provides a summary of the energy savings and GHG reduction from a washing machine program.

Table 4: Energy Savings and GHG Reductions Avg Annual Avg Annual GHG Total GHG Total Project Energy Agency Energy Savings Reduction Reduction Savings (kWh) (kWh/yr) (MT CO2e/yr) (MT CO2e) SCWD 826,000 240 9,900,000 2,900 SqCWD 732,000 213 8,800,000 2,600

This project could reduce approximately 35 to 55% of the potential GHG reduction goals for SCWD, and 12 to 15% of the potential GHG reduction goals for SqCWD.

Cost At $400 per residential rebate and $800 per commercial rebate, the 12-year program is expected to cost approximately $2.6 million for SCWD and $1.9 million for SqCWD. It is estimated that staffing will need to be expanded by about 0.2 FTE to process the increase in scwd2 Desalination Program, GHG Reduction Project Assessments Page 1-8 K/J Project No. 0868005*03, version 9/21/2011 29 rebates. The estimated cost also includes the avoided cost from energy savings. Table 5 lists the estimated cost of the program.

Table 5: Estimated Costs for Washing Machine Rebate Conservation Program Lifecycle GHG Life Capital Cost Average Annual Lifecycle Energy Agency Reduction Cost (yr) ($) Net Cost ($/yr) Cost ($/kWh) ($/MT) SCWD 12 $2.6 million $167,000 $0.19/kWh $600 SqCWD 12 $1.9 million $110,000 $0.15/kWh $460

Summary of Advantages and Disadvantages Advantages: • Builds on an existing, successful program • Integrates water and energy programs • Customers generally like the new machines and appreciate the opportunities to save water and energy • Water and energy savings are reliable and long term for the customer

Disadvantages: • There may be a significant number of “free riders”, as with any rebate program, that would have made the purchase without the rebate. • Lifetime of GHG reductions is limited by additionality criteria.

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Executive Summary: Draft PA No. 2 – Recycled Water Projects

Description

SCWD and SqCWD have evaluated various recycled water projects and the two most feasible projects are discussed below. These two projects have been evaluated in significant detail and are used here to evaluate the potential GHG reduction associated with each of the projects. Pasatiempo Golf Course (SCWD): This recycled water project would allow SCWD to reduce potable water used for irrigation. In concept, the neighboring Scotts Valley Water District (SVWD) would provide recycled water for irrigation of the Pasatiempo Golf Course. This would allow SCWD to reduce potable water supply to Pasatiempo. However, as part of the proposed project, SCWD would provide potable water to SVWD in winter months.

Seascape Golf Course (SqCWD): This recycled water project would help to reduce overdraft conditions of the groundwater basin that supplies SqCWD. Seascape Golf Course is irrigated by groundwater but is not a SqCWD customer. If Seascape is served 134 AFY of recycled water, the golf course could reduce its groundwater pumping by 134 AFY. Over time, this could help to reduce the overdraft conditions of the groundwater basin but would not provide SqCWD with an additional potable water supply.

Amount of GHG Reduction Although recycled water projects at Pasatiempo and Seascape could provide water supply benefits, these projects have a fatal flaw as a GHG reduction project since they increase energy use and associated indirect GHG emissions.

Project Life and Sustainability A recycled water project would continue to require energy to operate and thus increase, not reduce, energy use and associated indirect GHG emissions provide an additional water resource for the life of the project and beyond. The project would be sustained by normal maintenance to repair any infrastructure deterioration.

Project Cost The estimated project costs as shown in Table ES-1. Because the projects would increase GHG’s the unit cost of dollars per GHG reduction is shown as not applicable.

Table ES-1: Recycled Water Project Summary Annualized Average Lifecycle Lifecycle GHG Capital Project Annual Energy GHG Project INCREASE Cost Life Cost Cost Reduction (MT ($) ($/year) ($/kWh) Cost ($/MT) CO2e/yr) Pasatiempo 30+ years 13 – 311 $5.6 $619,000 N/A N/A (SCWD) (sustainable) (fatal flaw) million Seascape 30+ years 7 $10.3 $907,000 N/A N/A (SqCWD) (sustainable) (fatal flaw) million 1 Depending upon the amount of desalination used in a drought year.

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Draft Project Assessment No. 2 – Recycled Water Projects

Description This assessment estimates the energy savings and GHG reduction potential from the development of recycled water projects.

Background: Kennedy/Jenks’ Recycled Water White Paper dated January 2010 discusses the opportunities and limitations for recycled water use in the scwd2 use area. Major findings of the white paper included: • Both SCWD and SqCWD have implemented and/or are investigating recycled water programs as part of their integrated water portfolios. • Current California (CA) regulations do not allow recycled water (i.e., highly-treated wastewater) to be discharged directly into a potable/drinking water distribution system (otherwise known as direct potable use) and therefore would not meet SCWD’s drought water supply needs. Irrigation demands would be reduced in a drought by curtailment. • Current California (CA) regulations do allow recycled water to be used for indirect potable reuse whereby highly-treated wastewater is injected into the ground via percolation ponds or pumping, and extracted later for use. However, indirect potable reuse currently is not feasible for SqCWD or SCWD because: 1) it requires blending recycled water with surface or groundwater prior to injection, and both surface and groundwater supplies are already limited; 2) injection wells are required to be located a prescribed distance away from any public or private drinking water well which is difficult due to the thousands of wells within Soquel-Aptos area groundwater basin; and, 3) local land limitations are not conducive to percolation/blending ponds. • Recycled water for SCWD and SqCWD could potentially provide irrigation water for parks, sports fields, and/or golf courses during a drought, but would require a new dedicated distribution system that would be prohibitively expensive compared with the relatively small volumes of water delivered for appropriate use. • Scotts Valley Water District (SVWD) could provide approximately 200,000 gallons per day of recycled water for irrigation of Pasatiempo Golf Course.

SCWD and SqCWD already have evaluated various recycled water projects, and the two most feasible projects are discussed below. These two projects have been evaluated in significant detail and are used here to generally describe the opportunities and limitations of this type of project.

Opportunity for Recycled Water for SCWD Pasatiempo Golf Course: Kennedy/Jenks’ Engineering Feasibility Report for Recycled Water Service to Pasatiempo Golf Course (Pasatiempo) dated March 2010 discusses the potential to build a satellite tertiary treatment plant at Pasatiempo to treat secondary effluent from Scotts Valley Wastewater Treatment Plant (WTP). In concept, Scotts Valley Water District (SVWD) would provide recycled water for irrigation of Pasatiempo, one of SCWD’s potable water customers, and in exchange, SCWD would provide the SVWD with in-kind potable water during the winter, when SCWD has excess surface water available.

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In non-drought years, SCWD could offset approximately 28 million gallons per year (MGY), or 87 acre-feet per year (AFY), of surface water delivered to Pasatiempo in the summer with recycled water from SVWD. SCWD would still serve Pasatiempo with 33 MGY of surface water to meet Pasatiempo’s demand. In turn, SCWD would provide 28 MGY of surface water in the winter to SVWD.

In drought years, the scenario would be the same, except SCWD would serve Pasatiempo 33 MGY of a blend of surface water and desalinated water. The blend is estimated to be approximately 14% desalination, but the actual ratio would be calculated at the end of each year based on an actual usage of the desalination plant.

The potential recycled water use scenarios for Pasatiempo are summarized in Table 1.

Table 1: Potential Pasatiempo Recycled Water Use Scenarios Potential Future Drought Potential Future Scenario, with Current Scenario Scenario, No RW Status RW Project Project In dry season, SVWD serves Pasatiempo with 28 MGY recycled Non- SCWD serves Pasatiempo Golf Course with water, and SCWD serves Pasatiempo Drought approximately 62 MGY (189 AFY) with surface with 33 MGY of surface water. SVWD water. Years receives 28 MGY of surface water from SCWD in wet season. In dry season, SVWD serves SCWD curtails and Pasatiempo with 28 MGY recycled SCWD curtails and serves Pasatiempo with water, and SCWD serves Pasatiempo Drought serves Pasatiempo approximately 52 MGY with 33 MGY of blend surface with approximately 52 Years of blend surface water/desal. SVWD receives 28 MGY MGY of surface water water/desal of surface water from SCWD in wet season.

Note that Pasatiempo has expressed an interest in shifting toward xeriscaping, which could reduce its water demand and reduce the need for irrigation water. This water supply scenario should be revisited if Pasatiempo’s demands change significantly.

Opportunity for Recycled Water for SqCWD Seascape Golf Course: Black & Veatch’s Water Recycling Planning Study dated June 2009 identified recycled water production at Seascape Golf Course (Seascape) to be a potentially feasible recycled water project for SqCWD.

Seascape Golf Course is irrigated by groundwater extracted from their own private well. If Seascape is served 134 AFY of recycled water, the golf course could reduce its groundwater pumping by 134 AFY. Over time, this could help to reduce the overdraft conditions of the groundwater basin but would not provide SqCWD with an additional potable water supply. At this time, it is unlikely that SqCWD would request use of the groundwater well at Seascape. The Seascape golf course well is used for irrigational purposes and does not meet state requirements for potable wells. Additional treatment would add complexities and costs and this option does not align with SqCWD’s groundwater management goals of shifting groundwater pumping inland. The potential recycled water use scenarios for Seascape are summarized in Table 2.

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Table 2: Potential Seascape Recycled Water Use Scenarios

Project Current Scenario Potential Future Scenario Seascape uses 134 AFY recycled water and 306 AFY Seascape uses 440 AFY Seascape groundwater, and reduces 134 AFY pumping of of groundwater from its groundwater. This could help reduce the overdraft Golf Course own private well conditions in the groundwater basin.

History and Technical Maturity The use of recycled water to offset potable water use for irrigation is a technically mature concept that has been widely implemented throughout California.

Because state regulations and groundwater management plans may have site-specific treatment requirements, the approved uses for recycled water must always be evaluated on a case by case basis. Understanding the relationship between water quality requirements for potential uses, health related water quality requirements, and other regulatory water quality requirements related to the use of recycled water is critical to identifying the suitability and benefits of recycled water use.

The production, discharge, distribution, and use of recycled water are subject to federal, state, and local regulations, the primary objectives of which are to protect public health. In the State of California, recycled water requirements are administered by the State Water Resource Control Board, individual Regional Water Quality Control Boards, and the California Department of Public Health.

The regulatory requirements for recycled water projects in California are contained in the California Code of Regulations (CCR), which includes Title 22 and Title 17; the California Health and Safety Code; and the California Water Code.

Reliability and Operational Complexity For SCWD, the summertime supply to Pasatiempo would be shifted to wintertime supply to SVWD. The water to SVWD would be delivered through a new connection and would require a new pump station and pipeline and minor operational changes. In addition, this may require additional treatment improvements at the SCWD Graham Hill WTP that are not accounted for in this analysis.

SqCWD currently does not serve Seascape for irrigation of it’s greens, so SqCWD would have to incorporate this recycled water service into their operations. This would add complexity for SqCWD staff.

Sustainability A recycled water project would continue to provide an additional water resource for the life of the project and beyond. The project would be sustained by normal maintenance to repair any infrastructure deterioration. However, as shown below, the projects do not provide an overall reduction in energy for the water supply and therefore do not provide a reduction in GHG emissions.

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Local Considerations Economic

The Pasatiempo and Seascape projects would provide some local benefit by creating shorter term construction jobs and a few long-term operations and maintenance jobs, and by providing an additional water resource. There would also be opportunity for public outreach and education on recycled water.

Environmental

Air: These projects do not create air pollution.

Land: Recycled water can have higher salinity than potable and groundwater sources. Water quality should be tested to ensure that it would not affect the soil or sensitive plant species.

Water: Diverting and treating a portion of secondary effluent would reduce the amount of secondary effluent to the ocean outfall. Recycled water would not create more supply of water during drought years.

Noise: The satellite treatment plants could have some equipment noise, which could be mitigated by placing the equipment in an enclosure.

Aesthetic/Visual: The satellite treatment plants could have a visual/aesthetic impact but could be constructed in a design and area that is less visually disruptive.

Waste by-product: There are no waste by-products of recycled water projects.

Energy and GHG Changes Table 3 shows the estimated energy changes of a SCWD recycled water program.

Table 3: Estimated Energy Changes for SCWD Recycled Water Program Assumptions Annual Pasatiempo Demand 189 AFY Surface water power factor 1.3 kWh/kgal Desalination power factor 14.5 kWh/kgal Recycled water power factor 3 kWh/kgal Power factor for new pumping station delivering potable water from SCWD to 1 kWh/kgal SVWD 1 AF 326 kgal 86% surface water SCWD drought year blend assumed 14% desal Non-Drought Year, without Recycled Water project SCWD would provide 189 AFY of surface water Annual Non-Drought Energy Use 80,000 kWh/yr without Project Non-Drought Year, with Recycled Water project Dry Season

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SVWD would provide 87 AFY of recycled water SCWD would provide 102 AFY of surface water 189 AFY Pasatiempo would use 128,000 kWh/yr Wet Season SCWD would provide potable water 87 AFY of surface water to SVWD… …which would use (water treatment & 65,000 kWh/yr pumping energy) Annual Non-Drought Energy Use with 193,000 kWh/yr Project Annual Non-Drought Year Energy 113,000 kWh/yr INCREASE Drought Year, without Recycled Water project, with curtailment SCWD curtailment (15% or more) 85% of potable water delivered SCWD would provide 161 AFY of blend surface water/desal Annual Drought Year Energy Use 167,000 kWh/yr without Project Drought Year, with Recycled Water project, with curtailment Dry Season SVWD would provide 87 AFY of recycled water SCWD would provide 102 AFY of blend surface water/desal 189 AFY Pasatiempo would use 191,000 kWh/yr Wet Season SCWD would provide potable water to 87 AFY of surface water SVWD… …which would use (water treatment & 65,000 kWh/yr pumping energy) Annual Drought Energy Use with 256,000 kWh/yr Project Annual Drought Year Energy 89,000 kWh/yr INCREASE Annualized energy INCREASE 106,000 kWh/yr (2 drought years every 7 years)

Although a recycled water project at Pasatiempo could provide water supply benefits, it has a fatal flaw as a GHG reduction project because it increases energy use and associated indirect GHG emissions. Sensitivity analyses were run on these calculations to consider the percent of desalination use and the Pasatiempo demand, and these analyses also showed an increase in energy use.

Table 4 shows the estimated energy changes of a SqCWD recycled water program.

Table 4: Estimated Energy Changes for SqCWD Recycled Water Program Assumptions Assumed groundwater power factor for Seascape (average of SCWD and 2.5 kWh/kgal SqCWD groundwater power factors) Recycled water power factor 3 kWh/kgal 1 AF 326 kgal scwd2 Desalination Program, GHG Reduction Project Assessments Page 2-6 K/J Project No. 0868005*03, version 9/30/2011 36

Seascape demand 440 AFY Annual recycled water production at 134 AFY Seascape Without Recycled Water project Seascape would pump 440 AFY of groundwater Annual Energy Use without Project 354,000 kWh/yr With Recycled Water project Seascape would receive 134 AFY of recycled water Seascape would pump 306 AFY of groundwater Annual Energy Use with Project 377,000 kWh/yr Annual Energy INCREASE due to 23,000 kWh/yr Project

Although a recycled water project at Seacape could provide water supply benefits, it has a fatal flaw as a GHG reduction project because it increases energy use and associated indirect GHG emissions.

Table 5 provides a summary of the energy and GHG changes from a recycled water program.

Table 5: Estimated Energy and GHG Changes for Recycled Water Program Annualized Energy Increase Total GHG Increase Project 1 (kWh) (MT CO2e) Pasatiempo (SCWD) 106,000 31 Seascape (SqCWD) 23,00 7 1Assuming a 7 year drought cycle with 5 non-drought and 2 drought years.

Cost Table 6 below summarizes the estimated costs of the Pasatiempo and Seascape recycled water projects.

Table 6: Estimated Costs of Recycled Water Projects Capital Life Average Annual Cost Lifecycle GHG Reduction Project Title Cost (yrs) ($/year) Cost ($/MT) ($ million) Pasatiempo $5.6 30 $619,000 N/A (SCWD) million1 Seascape $10.3 30 $907,000 N/A (SqCWD) million 1Does not include cost of a new potable water supply pipeline from SCWD’s Loch Lomond to the SVWD distribution system.

Summary of Advantages and Disadvantages Advantages: • Utilization of a water resource that currently is untapped. • Low environmental impacts.

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Disadvantages: • Does not reduce energy or GHG. • High unit cost of water production. • Does not provide additional water or reduce water demands for SqCWD. • Increased operational complexity for SCWD and SqCWD.

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Description A residential and/or commercial renewables rebate program could provide homeowners and businesses in the scwd2 area with rebates or incentives to install solar photovoltaic (solar PV) and solar water heater (SWH) systems.

Amount of GHG Reduction Two programs that were considered were a Solar Power (solar PV) Group Buy Program and SWH Group Buy Program. The Solar Power and Solar Water Heater Group Buy Programs are estimated to reduce GHG emissions on average 170 MT and 76 MT CO2e per year, respectively, for a total 246 MT. These programs could reduce between 35 to 55% of the potential GHG reduction goals for SCWD, and approximately 15% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability Solar Power and SWH Group Buy Programs would continue to provide GHG reductions for the estimated 30 year life of the solar PV arrays and 20 year life of the solar water heaters. The project would be sustained by normal routine maintenance.

Project Cost The Solar Power and SWH Group Buy Programs would use local financial institutions to provide the capital for the program; therefore, there is no capital cost to SCWD or SqCWD. The incentives are $700 per solar PV project and $200 per SWH. Low capital and incentive costs associated with the project result in a low lifecycle cost of $0.03 for the solar PV and $0.034 for the SWH per MT CO2e. In addition, the average annual net costs are about $65,000 and $30,000 per year respectively.

Table ES-1: Solar Power and SWH Group Buy Program Summary Average Average Lifecycle Lifecycle Capital Annual Annual GHG Life Energy Project Cost Net GHG Reduction (yr) Cost ($) Cost Reductions 1 Cost ($/KWh) ($/Yr) (MT/Yr) ($/MT) Solar PV 30 $0 $64,714 170 $0.10 $0.03 Group Buy Program Solar Water Heater 20 $0 $29,731 76 $0.14 $0.04 Group Buy Program 1 This generation cannot be counted by the scwd2 desalination plant because it is claimed by the solar PV and SWH system owners.

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Description This assessment estimates the GHG reduction from an incentive program for homeowners and businesses in the scwd2 area that would incentivize them to install new solar photovoltaic (solar PV) or solar water heater (SWH) systems. This project assessment looks at a program that enables a group of local people to buy solar PV and SWH projects in bulk to obtain a lower installed cost.

Incentives for additional water conservation activities are addressed in Project Assessment No. 1 - Additional Water Conservation Activities.

Types of Incentives Incentives come in several forms, including rebates or up-front payments, tax credits, and loans. Incentives are designed to influence individuals and/or organizations to invest in energy efficient or renewable energy technology that they would not otherwise purchase.

Tax Credits: Tax credits are provided by federal, state, or local taxing authorities to individuals and organizations with income tax liabilities. The tax credits are deducted from the income tax liability of an individual or an organization, and usually calculated based on a percentage of the installed cost of a project (i.e. – 30% of the total installed cost). Creating new tax credits is a complicated processes that requires specific legal authority, and therefore they are not analyzed in this assessment.

Rebates: A rebate is an up-front one-time cash incentive that is designed to entice an individual and/or organization to purchase a product or system they would not otherwise purchase. The payment could be based on a flat amount, a $/kW or $/kWh payment over a specific period of time, or a $/MT payment.

Loans: Loans can be used to entice individuals or businesses to make a capital investment in two ways: by providing a low or no interest loan and by creating easy access to capital. The loans can be provided through local private financial institutions and can be backed or guaranteed by the local governments. A local government can also “buy-down” the interest rate with an up-front payment to the financial institution. In addition, local governments can use their own funds and create a loan pool.

History and Technical Maturity Rebate and incentive programs are proven and mature. Incentives and rebates have a history dating back many decades in this country. They have been applied to the purchase of durable goods like cars, appliances, and consumer electronics. In the late 1970s electric utilities started providing incentives and rebates to increase the use of energy conservation equipment. Today, rebates and incentives are commonly used to increase the use of energy efficient equipment and renewable energy systems. This is a cost-effective way to manage energy demand and defer the need to build additional generation, transmission, and distribution assets. Tax credits became an additional incentive tool in the 1990s.

Incentives continue to be a major tool to encourage energy efficiency and renewables. PG&E has incentive and rebate programs for residential customers. Rebate programs have been used

scwd2 Desalination Program, GHG Reduction Project Assessments Page 3-2 40 to promote the purchase of: energy efficient appliances, lighting, heating and cooling systems, and building envelope improvements like insulation, duct ceiling, cool roofs, and low-e windows.

Businesses, schools, non-profits, and governments can receive incentives for similar improvements on their facilities that include: boilers, energy management systems, controls systems, agricultural systems, data center cooling control systems, window film, and building envelope improvements like insulation, and customized energy saving projects.

There are also rebates and tax incentives to encourage the installation of renewable resources. The Self Generation Incentive Program (SGIP) and the California Solar Initiative (CSI) are examples of renewable energy rebate and incentive programs.

There are also programs to promote water conservation which in turn save energy and reduce GHG emissions. For example, the City of San Diego Water Department offers several rebate programs for low flow toilets and washing machines for residential customers. For commercial customers, they offer rebates for high-efficiency clothes washers,http://www.cuwcc.org/smart- rebates-main.aspx high-efficiency toilets, high-efficiency urinals, pressurized water brooms; and more specialized uses such as x-ray film processor re-circulation systems and cooling tower conductivity controllers.

Proposed Incentive Programs Solar Power Group Buy Program: This program is modeled after successful programs at the City of Portland, OR and San Jose, CA. SCWD or SqCWD would work with local financial institutions and solar PV providers to lower the cost of purchasing solar PV system by doing a bulk purchase. This program would use local financial institutions to make the loans and would not require SCWD or SqCWD capital. As well, the loan would eliminate one of the key hurdles to purchasing solar PV projects – the lack of up-front capital. The SCWD or SqCWD roles would be limited to facilitating the program, providing a modest rebate to secure the rights to the GHG emissions, and possibly buying-down the interest rate of the loan (not modeled here). The participating financial institutions and solar vendor would be selected through an RFP process. Once the program is set-up, an advertising campaign would be used to entice participants during an enrollment period. Once the enrollment period closes, the installation period would begin. As part of participation in the program individuals and businesses would be required to contractually sign over the right to the GHG emissions reductions from their system so that they could be claimed solely by scwd2; thereby avoid being double counted. However, all the tax credits and energy production would remain with the system owner. This program could start in the first year with a pilot of only SCWD and SqCWD employees and a small pool of local business, and then expand to the rest of the community. This would allow for the agencies to fix any administrative issues that may occur with the kick-off of the program prior to expanding the program to the public and additional businesses. In San Jose the installation period for their initial 130 employee participants lasted from September 2010 to February 2011. San Jose’s program saved about 300 KW, or about 2.3 KW per installation. For this assessment, a program is assumed to install 50 solar PV systems per year over a 5 year period. If the program is deemed to be successful it could easily be ramped up in years 2 through 5, and install more units then the planned 50 units per year.

Solar Water Heater Group Buy Program: This program operates exactly the same as the Solar Power Group Buy Program. The assessment assumes a program to install 25 SWH systems per year for a 5 year period. If the program is deemed to be successful, it could easily be ramped up in years 2 to 5, and install more units then the planned 25 units per year.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 3-3 41 Reliability and Operational Complexity The operation and savings associated with renewable projects is known and well understood. The rebate and incentive programs described here are fairly straight forward and only moderately difficult to administer.

The solar program savings are easily quantified by simply adding up the installed KWhs of solar PV, or the reduced electricity or natural gas resulting from newly installed solar water heaters.

Sustainability A Solar Power Group Buy Program would continue to provide GHG reductions for the estimated 30 year life of the solar PV arrays and 20 year life of the SWHs. The projects would be sustained by normal routine maintenance. Local Consideration Economy The Solar Group Buy Programs would benefit the local community. When residents, institutions, and commercial customers participate in this program, they generate sales of products and local service. Local construction and service jobs would be created to support the projects driven by rebates and incentives. Vendors Potential solar vendors in the area include, but are not limited to: • Suns Up Solar (Santa Cruz, CA) • Solar Technologies (Santa Cruz, CA) • Westinghouse Solar (Columbia, CA) • Sun Power (San Jose, CA) Potential local financial institutions include, but are not limited to: • Santa Cruz County Employees Credit Union • Santa Cruz Community Credit Union • Bay Federal Credit Union

Environment Air: Solar PV and SWH projects do not create air pollution, but the reduction in electricity use will reduce GHG emissions at power plants.

Land: Larger solar PV projects require large, unobstructed, and unshaded areas, typically 100 square feet per kW. A 2.3 kW system would require about 230 square feet, and a 100 kWs would require approximately a combined 10,000 square feet, or approximately one quarter acre of land. Land impacts would be mitigated if the installation space is on land that is already disturbed, improved, or on rooftops. SWH projects occupy very little space on rooftops.

Water: Solar PV and SWH systems only use a modest amount of water during cleaning.

Noise: Solar PV systems produce little noise pollution. Larger inverters can make a “humming” sound similar to transformers. The sound can be mitigated by locating inverters in an enclosure

scwd2 Desalination Program, GHG Reduction Project Assessments Page 3-4 42 or within existing maintenance or electrical yards, and locating them away from residences or sleeping areas. Some SWHs have a small pump that creates a minimal amount of noise.

Aesthetic/Visual: Visual impacts from solar PV installations coincide with space constraints, and solar PV systems impact a viewshed in proportion to the size of the project. Placement of the system is the main factor that affects visual impact. For example, roof-top systems integrating solar PVs into existing structures would minimize visual impacts, whereas utility-scale installations would likely occupy large open spaces that would be visible from a considerable distance. SWH projects occupy very little space on rooftops and have a very limited aesthetic/visual impact.

Waste By-products: Installed solar PV and SWH systems generate no waste by-products from their operation.

Energy Production, Energy Savings and GHG Reductions Table 1 provides a summary of the energy production and GHG reductions from a Solar PV and SWH Group Buy Programs. However, the energy production and savings cannot be counted toward the scwd2 desalination plant because they would be controlled and owned by the solar PV and SWH system owners.

Table 1: Estimated Energy Production and GHG Emissions Average Annual Energy Annual GHG Lifetime GHG Annual Energy Project Production Reduction (MT Reduction (MT 1 Savings (kWh/yr) 1 CO e/yr) CO e) (kWh/yr) 2 2 Solar PV 138,000 583,000 170 5,085 Group Buy Program Solar Water Heater 62,500 260,000 76 1,818 Group Buy Program 1 This generation cannot be counted by the scwd2 desalination plant because it is claimed by the solar PV and SWH system owners. Cost The costs for the Solar PV and SWH Group Buy Programs are the set-up and administration costs, the annual enrollment advertising campaign, and a rebate. The rebate is assumed to be about 5% of the installed cost, or $700 per solar PV project and $200 per SWH; and is meant to secure the rights to the GHG emissions reductions. We assume this program will need 0.25 FTE per year per program, for a total of 0.5 FTE. We assume $10,000 per year per program for marketing, for a total of $20,000. All of the generation and all of the solar rebates and incentives accrue to the solar PV system owner, and not to SCWD or SqCWD. The programs install 50 solar PV and 25 SWH systems per year over a 5 year period. There are no capital costs since the programs use local financial institutions to make the loans. Table 2 provides a summary of the costs for the program.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 3-5 43 Table 2: Estimated Solar PV Group Buy Program Costs Average Lifecycle Lifecycle GHG Life Capital Project Annual Net Energy Cost Reduction Cost (yr) Cost ($) 1 Cost ($/Yr) ($/kWh) ($/MT) Solar PV 30 $0 $64,714 $0.10 $0.03 Group Buy Program Solar Water Heater 20 $0 $29,731 $0.14 $0.04 Group Buy Program 1 This generation cannot be counted by the scwd2 desalination plant because it is claimed by the solar PV and SWH system owners.

Summary of Advantages and Disadvantages Advantages: • Local economic and job benefits. • Mature technology with low risk. • Environmental considerations are low. • Loans overcome the barrier of up-front capital for residences and businesses, while no SCWD or SqCWD capital is needed. • Once set-up, the program has low operations & maintenance requirements. • Provides GHG reductions to scwd2, and energy cost savings to the community. • Creates community involvement from participants, and education and awareness through the enrollment advertising campaign. Disadvantages: • Requires additional staff and considerable set-up effort. • Energy generation and savings cannot be counted by the scwd2 desalination plant because it is claimed by the solar PV and SWH system owners.

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Executive Summary: Draft PA No. 4 – Graywater and Rainwater Projects

Description Graywater and/or rainwater projects would allow SCWD or SqCWD to reduce potable water used for landscape irrigation. This would save energy associated with potable water and therefore reduce indirect GHG emissions.

Amount of GHG Reduction The estimated GHG reductions rely on customers participating in the program and may be less than estimated if actual participation is less than assumed by this project assessment. SCWD – Accelerated Residential Graywater/Rainwater Reuse Project: In non-drought years, the water supply offset would be for surface water; in drought years, the offset would be for a blend of desalinated and surface water. GHG emissions could be reduced by an average of 1.3 metric tons annually.

SCWD – UCSC Graywater/Rainwater Reuse Project: In non-drought years, the water supply offset would be for surface water; in drought years, the offset would be for a blend of desalinated and surface water. GHG emissions could be reduced by 5 metric tons annually.

SqCWD – Accelerated Graywater/Rainwater Reuse Program: The water supply offset would be for a blend of desalinated and groundwater. GHG emissions could be reduced by an average of 3.2 metric tons annually.

This project is estimated to reduce less than 1% of the potential GHG reduction goals for SCWD and SqCWD.

Project Life and Sustainability Graywater and/or rainwater reuse programs would provide non-potable water for irrigation for the life of their systems. For SCWD and SqCWD, the additional GHG reduction credit from these accelerated programs is estimated to have a 15 year lifetime, since it is assumed that in 15 years, customers would have signed up through the existing graywater/rainwater programs offered by SCWD and SqCWD. The UCSC project, since it is not existing or planned, is assumed to provide GHG reduction for 30 years and beyond with normal maintenance.

Project Cost Table ES-1: Graywater/Rainwater Reuse Project Summary Avg Average Lifecycle Lifecycle Annual Life Capital Annual Energy GHG Project GHG (yrs) Cost ($) Net Cost Cost Reduction Reduction ($/yr) ($/kWh) Cost ($/MT) (MT/yr) SCWD – Residential 15 1.3 $872,000 $120,000 $12 $75,000 Graywater/Rainwater SCWD – UCSC 30 5 $1,100,000 $85,000 $4 $11,000 Graywater/Rainwater SqCWD – 15 3.2 $591,000 $91,000 $4 $23,000

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Accelerated Graywater/Rainwater

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Draft Project Assessment No. 4 – Graywater and Rainwater Programs

Description This assessment estimates the energy savings and GHG reduction potential from the development of a graywater program and rainwater harvesting/storage program for SCWD and SqCWD.

Background Graywater: Graywater is untreated water that drains from a bathtub, shower, clothes washing machine, or bathroom sink. Graywater reuse provides a year-round non-potable water supply.

Regulations finalized in January 2010 allow homeowners in California to install clothes washing machine graywater systems, also called "laundry to landscape" systems, in their homes without a permit by following the guidelines outlined by Chapter 16A of the California Plumbing Code. The reuse of graywater from any source other than a clothes washing machine requires a construction permit issued from the local enforcing agency. The total number of California households diverting graywater for onsite use is estimated to range from approximately 600,000 to 1.8 million (Sheikh).

Landscape irrigation is the most common reuse of graywater. However, it cannot be used to irrigate root crops or edible parts of food crops that touch the soil and cannot be used in spray irrigation systems. Graywater used for indoor uses, such as toilet flushing, must be treated to standards for disinfected tertiary recycled water (California Code of Regulations, Title 22), but is not common in the United States.

Rainwater Harvesting: Rainwater harvesting is defined as precipitation collected from rooftops and other above-ground impervious surfaces that is stored in catchment tanks for later use. In California, rainwater harvesting provides a seasonal, wet-weather, non-potable water supply. Rainwater harvesting systems can range from a simple barrel at the bottom of a downspout to multiple cisterns with pumps and filtration.

The most common reuse of rainwater is landscape irrigation. Untreated rainwater can be used for sub-surface outside irrigation, including edible plants and gardens. For indoor uses, such as toilet flushing, laundry, and bathing, additional treatment is required (US EPA).

Figure 1 shows a large rainwater catchment system at the SqCWD Headquarters Office that can store approximately 2,000 gallons of rainwater for irrigation.

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Figure 1: Rainwater Storage Tank at SqCWD Headquarters Office ( ~2,000 gallons)

Table 1 provides a summary of the availability, sources, and potential uses of treated and untreated graywater and rainwater.

Table 1: Summary of Availability, Sources, and Potential Uses of Graywater & Rainwater Graywater Rainwater Availability Year-round Seasonal (wet weather) Laundry, shower/bathtubs, Rooftops, other impermeable surfaces Sources sinks Irrigation – no root crops or Irrigation – includes all food crops Uses edible parts of food crops that

(Untreated) touch the soil Outdoor – sprinklers, Outdoor – sprinklers, carwash, HVAC; carwash, HVAC; Indoor – Uses (Treated) Indoor – toilet flushing, laundry toilet flushing, laundry Pre-filtration – first flush diverter, Cartridge Disinfected tertiary treatment filtration – 5 micron sediment filter, Required (CCR, Title 22, Section 4, Disinfection – chlorination with household Treatment Chapter 3) bleach or UV disinfection Disinfected tertiary treatment Treatment Total coliform < 500 cfu per 100 mL; Fecal (CCR, Title 22, Section 4, Goals for coliform < 100 cfu per 100 mL Indoor Use Chapter 3)

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Existing Programs Graywater: Existing SCWD and SqCWD graywater reuse programs are as follows:

• SCWD provides guidelines for residential graywater on its website but currently does not offer a formal graywater program.

• SqCWD has implemented a graywater rebate program that offers a $75 rebate for each qualified graywater system, up to three connections per household. Eligible connections include clothes washing machines, bathtubs/showers, and bathroom sinks. SqCWD provides guidelines and resources for graywater reuse on its website. To date the program has provided 2 rebates for graywater systems.

Rainwater Harvesting: Existing SCWD and SqCWD rainwater harvesting programs are as follows:

• SCWD has implemented a rain barrel distribution program, which provides 65-gallon rain barrels to its customers at a reduced price of $50. SCWD estimates that a rain barrel would conserve a maximum of 260 gallons per year, or 0.7 gallons per day averaged over the course of a year. To date, the program has provided 168 rain barrel systems to customers.

• SqCWD has implemented a rainwater catchment rebate program that offers $25 to $750 in rebates for the capital costs associated with installing rain barrels (up to 200 gallons) or large catchment systems (over 200 gallons). SqCWD provides guidelines and resources for rainwater reuse on its website. To date, the program has provided 25 rebates for rainwater catchment systems.

Potential New or Accelerated Graywater and/or Rainwater Reuse Programs Programs are evaluated separately for SCWD and SqCWD. For SCWD, an new residential graywater/rainwater program and a new graywater/rainwater project for the University of California, Santa Cruz (UCSC) were evaluated. For SqCWD, an accelerated graywater/rainwater program was evaluated. This analysis assumes that a rainwater system would include a large, approximately 2,000 gallon catchment tank to provide similar offsets of irrigation water as a graywater system (2,600 gallons per year).

SCWD New Residential Graywater/Rainwater Reuse Program: SCWD could implement a residential graywater/rainwater reuse program that would reduce potable water demands during irrigation months. It is assumed that residential reuse would be limited to landscape irrigation because of the complex treatment requirements for indoor reuse. The program would consist of customer rebates, as well as customer outreach and education.

The following assumptions were used to estimate the benefit of a SCWD residential graywater/rainwater reuse program: • $300 rebate per residence to provide incentive to install a graywater system or $1,000 per rebate per residence to install a large approximately 2,000 gallon rainwater catchment system. • $150,000 budget for marketing materials and public outreach and education campaign over the 15 years of the program.

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• One quarter-time FTE staff position for 15 years • 10% of single-family households apply for the rebate (1,835 households) (SCWD UWMP Table 4-1) over the program. This was assumed to be 120 households per year participating in the program. Approximately 3/4 of the rebates would be for graywater. • Graywater supplies 2,600 gallons per year per household for landscape irrigation (scwd2 Graywater Fact Sheet, 2010). For this analysis a large, approximately 2,000 gallon rainwater catchment system is assumed to provide a similar volume. • During non-drought years, graywater/rainwater reuse would offset only surface water. During drought years, graywater/rainwater reuse would offset a combination of surface water and desalination water. It is assumed that, during drought years, SCWD will implement a 15% curtailment of irrigation water supply. • The program could initially offset approximately 300,000 gallons per year and increase up to 4.8 million gallons per year (MGY) of irrigation demand over the 15-year program duration.

UC Santa Cruz Graywater/Rainwater Reuse Program: A graywater/rainwater reuse program at UC Santa Cruz (UCSC) could provide a larger-scale benefit than a residential program because of the size of the campus. The graywater supply is assumed to be from showers and laundry facilities. Although UCSC could potentially implement a treatment facility to supply treated graywater/rainwater for indoor uses, this option is not considered feasible because of the high cost for retrofitting buildings for a dual-plumbed supply. Therefore, graywater/rainwater is assumed to be used only for landscape irrigation.

The following assumptions are used to estimate the benefit of a UCSC graywater/rainwater reuse program: • A conceptual cost of $1,100,000 is allocated to retrofit dorms and laundry facilities to divert graywater, install rainwater catchment tanks, and retrofit the campus irrigation system. • 25% of campus irrigation demands would be supplied through the graywater/rainwater reuse project (SCWD Water Shortage Contingency Plan, Table 3-4) • During non-drought years, graywater/rainwater reuse would offset only surface water. During drought years, graywater/rainwater reuse would offset a combination of surface water and desalination water. It is assumed that, during drought years, SCWD will implement a 15% curtailment of irrigation water supply. • The program could offset approximately 10.3 MGY of irrigation demand during non- drought years and 8.7 MGY during drought years over the 30-year project duration.

SqCWD Accelerated Graywater/Rainwater Program: The following assumptions are used to estimate the benefit of an accelerated graywater/rainwater reuse program in SqCWD: • $300 rebate per residence (instead of $75) to provide enhanced incentive to install a Laundry-to-Landscape system and $1,000 per rebate per residence (instead of $750) to install a large, 2,00 gallon rainwater catchment system. • $150,000 budget for marketing materials and public outreach and education campaign over the 15 years of the program. • One quarter-time FTE staff position for 15 years

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• 10% of single-family households apply for the rebate (1,245 households) (SqCWD Draft UWMP, 2010). This was assumed to be 83 households per year participating in the program. Approximately 3/4 of the rebates would be for graywater. • Graywater supplies 2,600 gallons per year per household for landscape irrigation (scwd2 Graywater Fact Sheet, 2010). For this analysis a large, approximately 2,000 gallon rainwater catchment system is assumed to provide a similar volume. • Graywater/rainwater reuse would offset a combination of groundwater and desalination water, the proportions of which vary depending on whether it is a drought or non-drought year. It is assumed that, during drought years, SqCWD will implement a 15% curtailment of irrigation water supply. • The program could initially offset approximately 200,000 gallons per year and increase up to 3 MGY of irrigation demand over the 15-year program duration.

Vendors Graywater and rainwater catchment systems can be installed by homeowners or contractors. Permits are required for any graywater systems other than laundry-to-landscape systems. The SqCWD website provides a partial list of local companies and contractors that sell and/or install water catchment systems (http://www.soquelcreekwater.org/content/rain-catchment).

History and Technical Maturity The use of graywater and rainwater to offset potable water use for irrigation is a technically mature concept that has been implemented throughout California. The number of residential graywater and rainwater catchment systems is relatively small, but growing.

A potential risk with graywater/rainwater systems is the potential for poor site management, which could result in ponding or runoff of the graywater, which is not permitted by state and county regulations and ordinances. Another risk is the possibility of “bootlegged” graywater systems that have not undergone appropriate permitting that increases the risk of cross- connection to the onsite potable water supply. However, these risks can be mitigated through appropriate education, permitting, and monitoring.

Reliability and Operational Complexity The reliability of this and other rebate programs to provide GHG reductions will depend on the participation rate in the program. Participation can be increased through public education and advertising campaigns, however, participation is not guaranteed. The actual program participation rates would need to be confirmed on an annual basis and additional efforts made to promote the program if participation is below target. Also, over time it may be more and more difficult to maintain participation rates, especially with more complex systems such as graywater systems.

The technical reliability of graywater and rainwater reuse projects will depend on each individual customer to optimize the potential for reuse and to continue to use graywater or rainwater to offset landscape irrigation demands. The complexity of the graywater and/or rainwater catchment system will vary for individual households depending on the piping arrangements, space and irrigation systems of the residence. The more complex the system, the greater chance that a homeowner may not properly maintain and use the system. However,

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households that do install these systems are more likely to be aware of the water and energy saving benefits of the systems and therefore maintain the systems.

A graywater/rainwater reuse programs would have little impact on SCWD or SqCWD operations. A 25% FTE staff person would help to implement and market the program and to respond to residential inquiries/problems.

Project Lifetime and Sustainability Graywater and rainwater reuse projects would provide an additional water resource for the life of respective systems. The residential projects would be sustained over the 15-year period by outreach to water customers and providing assistance to those customers who wish to install graywater or rainwater systems. At the end of the 15-year project life, an assessment could be made to determine if continuing the program would provide additional GHG reduction credits that met the Kyoto Protocol additionality criteria.

Due to the criteria of additionality, only new or accelerated programs, beyond the existing programs described above, can be counted as a GHG reduction project for the scwd2 Desalination Program. The concept of additionality was introduced in the Kyoto Protocol in Article 12.5, which states that “emission reductions resulting from each project activity shall be certified by DOEs (Designated Operational Entities) on the basis of ... reductions in emissions that are additional to any that would occur in the absence of the certified project activity.” Because of the relatively low participation rate of the existing graywater and rainwater programs, this analysis assumes that all systems that would be installed through an accelerated program would be considered additional.

However, because plumbing code regulations have recently changed to permit easier installation of graywater and rainwater systems, and these programs are starting to become more widespread, the project life time for the GHG reduction credits has been assumed to be only 15 years. It is assumed that in 15 years, customers would have signed up through the existing graywater/rainwater programs offered by SCWD and SqCWD. The UCSC project, since it is not existing or planned, is assumed to provide GHG reduction for 30 years and beyond with normal maintenance.

Local Considerations Economy Graywater reuse and rainwater harvesting programs would provide a local benefit. The primary economic benefit would be an increase in business to local contractors. The programs also would reduce local energy consumption and associated GHG emissions from potable water production and take advantage of untapped local water resources. This also could provide cost savings for homeowners from water and energy use reduction.

Environment Air: These projects do not create air pollution, but the reduction in electricity use will reduce GHG emissions.

Land: The use of untreated graywater from laundry may impact soil quality and/or sensitive plant species. This could be mitigated or managed through the use of environmentally-friendly laundry detergents that do not include chlorine or bleach, peroxygen, sodium perborate, sodium

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trypochlorite, boron, borax, petroleum distillate, alkylbenzene, “whiteners”, ”softeners” and ”enzymatic” components. The use of rainwater is not anticipated to impact soil quality or plants.

Water: Ultimately, graywater reuse could reduce the amount of wastewater in the sanitary sewers, thereby reducing the volume of secondary effluent discharged at the ocean outfall and potentially improving water quality. Rainwater harvesting could divert stormwater from storm drains and waterways, potentially improving water quality of receiving waters. However, the relatively small amount of water reduction through this program may not provide a significant difference.

Noise: This project is not anticipated to have any noise impacts.

Aesthetic/Visual: Graywater and rainwater systems should be constructed in such a way as to not be visually disruptive.

Waste by-product: There are no waste by-products of graywater or rainwater programs.

Energy Savings and GHG Reductions The SCWD Residential Graywater/Rainwater Reuse, the UCSC Graywater/Rainwater Reuse, and the SqCWD Accelerated Graywater/Rainwater Reuse projects potentially would allow SCWD and SqCWD to substitute graywater water for potable water (either surface water, groundwater, desalinated water, or a combination, depending on the drought conditions), for landscape irrigation. Desalination requires about 14.5 kWh of energy to produce 1 kgal of water, surface water requires about 1.3 kWh of energy to produce 1 kgal of water, and groundwater requires about 2.14 kWh of energy to produce 1 kgal of water. Graywater and rainwater use little energy since generally the water is collected and distributed by gravity, although the systems may require small pumps to supply irrigation systems.

Table 2 provides a summary of the estimated potential energy saved and GHG emission reductions from the proposed graywater/rainwater reuse programs. Actual GHG emission reductions will depend of public participation rates throughout the life of the program.

Table 2: Estimated Energy Savings and GHG Reductions for Graywater/Rainwater Reuse Programs1 Average Average Lifetime Lifetime Annualized Life Annual GHG Energy GHG Project Title Energy (yrs) Reduction Savings Reduction Savings (MT CO e/yr) (kWh) (MT CO e) (kWh/yr) 2 2 SCWD – Residential 15 4,300 1.3 65,000 19 Graywater/Rainwater SCWD – UCSC 30 17,000 5 521,000 151 Graywater/Rainwater SqCWD – Accelerated 15 11,000 3.2 162,000 47 Graywater/Rainwater 1Assuming 2 drought years every 7 years.

This project is estimated to reduce less than 1% of the potential GHG reduction goals for SCWD and SqCWD.

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Cost Table 3 summarizes the estimated costs and cost effectiveness for the graywater/rainwater reuse programs. The supporting cost information is included in Attachments 1 and 2. The average annual cost is the annual operating costs plus the debt service on the capital cost over the life of the project minus energy savings.

Table 3: Estimated Costs for Graywater Reuse Programs Average Lifecycle Lifecycle GHG Life Capital Project Title Annual Net Energy Cost Reduction (yrs) Cost ($) Cost ($/yr) ($/kWh) Cost ($/MT) SCWD – Residential 15 $872,000 $120,000 $12 $75,000 Graywater/Rainwater SCWD – UCSC 30 $1,100,000 $85,000 $4 $11,000 Graywater/Rainwater SqCWD – Accelerated 15 $591,000 $91,000 $4 $23,000 Graywater/Rainwater

Summary of Advantages and Disadvantages Advantages: • Utilization of a water resource that currently is under-utilized • Energy saving and GHG emission reduction opportunities (energy/water nexus projects) • Potentially provides drought-proof irrigation water supply for customers who want to continue watering their landscapes without disruption and/or mandates that may be enforced during drought-time curtailments.

Disadvantages: • Limited and costly GHG reduction opportunities for SCWD and SqCWD • Projects may have limited program life for additional GHG reduction credits • Reliability depends on individual customers maintaining their systems

References City of Santa Cruz Water Department. 2005 Urban Water Management Plan. February 2006.

City of Santa Cruz Water Department. Water Shortage Contingency Plan. March 2009.

Sheikh, Bahman, PhD, PE. “White Paper on Graywater,” 2010.

Soquel Creek Water District. Draft 2010 Urban Water Management Plan. 2011.

scwd2. Graywater. Fall 2010.

US Environmental Protection Agency. Municipal Handbook EPA 833-F-08-010, Rainwater Harvesting Policies, provides recommendations for treatment of rainwater for indoor non-potable reuse.

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Executive Summary: Draft PA No. 5 – Improved Digester Mixing System at Santa Cruz WWTP

Description An improved digester mixing system at the City of Santa Cruz Wastewater Treatment Plant (WWTP) would include replacing the existing gas mixing system with a more energy efficient pump mixing system to save energy and reduce indirect GHG emissions.

Amount of GHG Reduction The energy savings from the improved mixing system would correspond to an annual GHG reduction of approximately 266 MT CO2e and total of 5,324 MT CO2e over the project life. This project could reduce approximately 40 to 60% of the potential GHG reduction goals for SCWD, and 15 to 20% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability An improved digester mixing system would continue to provide energy savings and GHG reduction for the 20 year life of the project. The project would be sustained by normal maintenance and repair.

Project Cost This project would result in an overall benefit to SCWD over the project life. The average annual net cost of the project is approximately -$19,000 per year, because the savings from reduced energy use is greater than the cost to install and run the project. Since the project results in a net benefit, the project lifecycle GHG reduction cost per metric ton (approximately -$45 per MT CO2e) also provides a net benefit to SCWD.

Table ES-1: Improved Digester Mixing System Project Summary Average Lifecycle Lifecycle Project Annual GHG Capital Cost Annual Energy GHG Space Life Reduction ($ million) Net Cost Cost Reduction Required (yr) (MT CO e/yr) 2 ($/Yr) ($/kWh) Cost ($/MT) None (replacing 20 266 $1.4 -$19,000 -$0.01 -$45 existing equipment)

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Draft Project Assessment No. 5 – Improved Digester Mixing System at Santa Cruz WWTP

Description This assessment estimates the energy savings and GHG reduction potential from upgrading the existing digester mixing system at the City of Santa Cruz (City) Wastewater Treatment Plant (WWTP).

Background The WWTP meets solids stabilization requirements by using three primary digesters with a combined active volume of 4.5 million gallons. The sludge in the primary digesters is mixed with a gas mixing system, which is comprised of ductile iron piping, two 60-horsepower (HP) compressors per digester, and associated valves, electrical equipment and controls. The compressors operate 24 hours per day, 365 days per year. Mixing is required in order to adequately expose the microbial culture in the digesters to the sludge, which is their food source.

In a gas mixing system, digester gas is pumped into the bottom of the digester. Mixing comes from the combination of the released gas, the rising bubbles, and reduced sludge density. However, with gas mixing systems, the bottom portion of the digester often is not adequately mixed, and any grit that would normally be in suspension will tend to accumulate on the bottom and become problematic. Also, the mixing tends to be uneven – intense in localized areas and sporadic in others. In addition, gas systems have limited capacity; the mixing ends when the gas bubbles reach the liquid surface. Sufficient mixing of the entire tank volume is needed to prevent the accumulation of grit on the floor and to minimize the creation of a scum blanket on the surface. The level of digester mixing depends on the method of mixing that is used.

Externally pumped mixing systems are characterized by highly uniform mixing. The high velocities that are developed at the discharge nozzles create a swirling motion, or spiral vortex that continues throughout the digester. A considerable amount of “shear,” or breaking up, is experienced by the solids in an externally pumped mixing system. This shearing action reduces the size of the solids particles and subsequently increases the surface area exposed to the microbial culture in the digesters, resulting in higher volatile solids destruction and increased digester gas production. Pump mixing systems tend to require less input energy than systems that rely on compressed digester gas for mixing. Pumps mixing systems also reduce grit build- up in the bottom of a digester and mat formation at the surface, thereby extending the time period between expensive cleaning cycles for the digester.

Changing from a gas mixing to an externally pumped mixing system can also potentially increase the performance of a digester in terms of volatile solids (VS) destruction. Additional VS destruction results in an increased production of digester gas. Historical data for the WWTP suggests the primary digesters have experienced VS destruction in the range of 55 to 60%. It is anticipated that this destruction rate could increase to 60 to 65% with inclusion of an externally pumped mixing system.

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Figure 1: Typical Externally Pumped Digester Mixing System

The San Francisco State University School of Engineering (with support from the U.S. Department of Energy) completed an Energy Conservation and Waste Management Report in December 2010 for the City (SFSU Report). This report made a recommendation to replace the existing gas digester mixing systems with externally pumped digester mixing systems at the City WWTP. In addition, the SFSU Report also recommends replacing the existing gas compressors that are dedicated to each primary digester with one 25 HP centrifugal pump for the pump mixing system.

Kennedy/Jenks was asked by the City to evaluate the findings of the SFSU Report prior to doing this assessment. After reviewing the calculations, assumptions, and estimated energy savings presented in the SFSU Report, it was determined that the amount of savings and estimated payback period were overstated.

Based on the active digester volumes provided by City staff, and assuming a total dynamic system head of 14 feet and typical efficiencies, a single 25 HP centrifugal pump for each digester would provide a flow rate of approximately 3,900 gallons per minute (gpm). Digester mixing energy and distribution is typically measured in terms of turnovers of digester contents per day (pumping of the entire volume is one turnover). A 3,900 gpm pump would provide approximately 4.6 turnovers per day for Digester 1 (smaller digester), and 3.5 turnovers per day if used at each of Digesters 4 and 5 (larger digesters). The recognized industry guideline is between 8 and 12 turnovers per day of the tank contents in order to adequately expose the microbial culture to the available food source and distribute thermal energy from the sludge heating system. In order to provide the recommended mixing, a single 50 HP centrifugal pump should be used for each digester, rather than 25 HP (as recommended in the SFSU Report). The corresponding mixing distribution for the two different pump sizes is presented in Table 1.

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Table 1: Digester Mixing Distribution Comparison SFSU Report K/J Analysis Active Digester Mixing Digester Mixing Digester No. Digester (turnovers/day) (turnovers/day) Volume (gal) 25 HP Pump 50 HP Pump Digester 1 1,204,000 4.6 11.3 Digester 4 1,596,000 3.5 8.5 Digester 5 1,596,000 3.5 8.5

The SFSU Report also includes an assumption that the new pump will only operate for 12 hours per day. Empirical data from similar sized facilities operating with externally pumped mixing systems has shown that, in order to transfer sufficient mixing from the pump to the contents of the digester, the pump must operate continuously. Mixing systems that have insufficient mixing can suffer from dead spots that reduce the volatile solids destruction and therefore reduce digester gas production.

Vendors The mixing pumps can be either a chopper style centrifugal pump that produces mechanical shearing as the sludge passes through, or a screw style centrifugal pump that produces hydraulic shearing at the discharge nozzles with a non-clog volute and impeller configuration. Screw centrifugal pumps are characterized by a pumping efficiency approximately 25% higher than chopper pumps and therefore are recommended for Santa Cruz. Hayward Gordon and Wemco have been manufacturing the appropriate screw centrifugal pumps for more than 15 years.

History and Technical Maturity Gas mixing systems were the preferred technology at wastewater treatment plants starting in the 1960s. However, over the last 20 years, municipalities have found that gas mixing systems are ineffective at distributing the mixing energy throughout digester tanks, resulting in “dead spots” and reduced rates of volatile solids destruction, and therefore create lower digester gas production. In the San Francisco Bay Area, the North San Mateo County Sanitation District, San Leandro WPCP, Millbrae WPCF, and Central Marin Sanitation Agency have all either replaced, or are in the process of replacing, their gas mixing systems with new externally pumped mixing systems. Both gas and pump mixing systems are well developed and technically mature.

Reliability and Operational Complexity Externally pumped mixing systems are comprised of pumps, piping, minor instrumentation, and electrical equipment (motor control centers, conduit, and wires). These types of mixing systems have been proven to be extremely reliable throughout the United States, and are now being recommended for any plant looking at potentially accepting fats, oils, and grease (FOG), or food waste (FW).

Major benefits of an improved mixing system are energy savings, better volatile solids destruction, elimination of high pressure gas piping and its inherent hazards, and increased digester gas production.

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A potential downside to replacement of the existing gas mixing system is the risk associated with coring large diameter holes in the sidewalls of the digesters for the mixing piping, and the possibility of additional cost associated with strengthening the existing wall.

The retrofit project is not anticipated to have any adverse impacts on City operations. The City staff is accustomed to operating and maintaining centrifugal pumps and the instrumentation associated with this type of project. The system runs continuously, so monitoring of speed, flow rate, or other parameters is not required. The City may actually see a reduction in maintenance requirements for the centrifugal pumps compared to gas compressors, because the pump systems tend to be more reliable.

Sustainability Improving the mixing system at the City WWTP would continue to provide energy savings for the life of the project. The project would be sustained by normal maintenance and repair.

Local Considerations Improving the digester mixing system at the Santa Cruz WWTP will benefit the local community by reducing the amount of energy used to digest sewage sludge and potentially increasing the total gas production through enhanced VS destruction.

Economy Construction of the improvements would require approximately 4 to 5 months of downtime per digester, but the required labor could come from the local community.

Environment Air: Centrifugal pumps do not have any direct emissions.

Land: Since this project involves replacing existing unit without any increase in the digester footprint there is no significant impact on land.

Water: Centrifugal pumps without mechanical seals do not consume water or create any water pollution.

Noise: Centrifugal pumps are generally quieter than air compressors, potentially resulting in a reduction in overall noise from the WWTP.

Aesthetic/Visual: The pumps would be placed at grade, with some large diameter piping extending from the digester walls. The aesthetic nature of the piping and equipment would be similar to other equipment at the plant, and not visible from outside the property.

Waste by-product: Some pumps utilize grease for bearings and oil for the mechanical seal, and would need to be disposed of properly.

Energy Savings and GHG Reductions Digester mixing is a continuous process, so energy savings would result from operation of the digester mixing pumps on a full-time basis. Energy savings included in the SFSU report were based on operating all three primary digesters simultaneously, although with the compressors operating at a utility factor of 0.64, or essentially two-thirds of the time. This is equivalent to the

scwd2 Desalination Program, GHG Reduction Project Assessments Page 5-5 K/J Project No. 0868005*03, version 9/22/2011 59 gas systems for two of the digesters operating full-time. Current practice involves having one digester out of service at any given time, so full-time operation of gas compressors for two of the digesters is a more realistic scenario. The energy savings estimated below are based on operating digester mixing pumps for the two primary digesters (Digesters Nos. 4 and 5) 100% of the time.

The energy usage associated with operating the existing gas mixing systems for two digesters is approximately 1,568,400 kWh per year. This accounts for roughly 14% of the total energy demand for the plant (based on 11,626 MWh per year). As shown in Table 2, by replacing the existing gas mixing system with a pump mixing system in Digesters 4 and 5, the estimated energy savings is approximately 915,000 kilowatt hours per year (kWh/yr), or a savings of nearly 60%.

Table 2: Mixing Systems Comparative Energy Use Motor Annual Peak # of Duty Scenario Equipment Size 2 Electricity Electrical 1 Units Factor (HP) Usage (kWh) Demand (kW) Digester 4 60 2 100% 784,200 90 Gas Compressors Existing Digester 5 60 2 100% 784,200 90 Gas Compressors Total Existing 1,568,400 179 Digester 4 50 1 100% 326,700 37 Mixing Pump Future Digester 5 50 1 100% 326,700 37 Mixing Pump Total Future 653,400 75 Total Energy Savings 915,000 104 1 Assumes similar efficiencies for both types of equipment. 2 Percent of time in operation.

Included in Table 3 is the potential estimated GHG reduction for implementing the project.

Table 3: Energy Savings and GHG Reductions for an Improved Mixing System

Annual Energy Savings (kWh/year) Annual GHG Reduction (MT CO2e/year) 915,000 266

This project could reduce approximately 40 to 60% of the potential GHG reduction goals for SCWD, and 15 to 20% of the potential GHG reduction goals for SqCWD.

Cost The capital costs shown in Table 4 are based on installation of non-clog centrifugal mixing pumps, large diameter welded steel piping, and associated electrical equipment and instrumentation. This assessment is based on upgrading only the two larger digesters to the externally pumped mixing system; leaving the smaller digester with the existing gas mixing system. Retrofitting the smaller digester does not result in significant energy savings, would not significantly impact reliability of the system, but would increase the capital costs for the project.

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The capital cost to improve the mixing system on two of the WWTP’s three digesters is estimated at $1,500,000. There is a one-time rebate incentive from PG&E through their Customized Retrofit Incentive program in the amount of $0.09/kWh for the first year’s savings, resulting in a capital cost savings of $100,000. Operation and maintenance costs (with the exception of energy cost) are similar to that of a gas mixing system, and would require approximately 0.1 full time equivalents (FTE). With proper maintenance, a pumped system should last approximately 20 years. This project’s benefits (from electricity savings) exceed its costs (from the capital cost and O&M) resulting in a negative net cost, or a benefit to SCWD.

Table 4: Estimated Improved Mixing Project Costs Lifecycle Lifecycle GHG Project Life Capital Cost Average Annual Energy Cost Reduction Cost (yr) ($ million) Net Cost ($/Yr) ($/kWh) ($/MT CO2e) 20 $1.4 -$19,000 -$0.01 -$45

Summary of Advantages and Disadvantages Advantages: • Overall financial net benefit to SCWD. • Energy savings from a reduction in total needed horsepower for operations. • GHG reduction from associated energy savings. • Better mixing resulting in more volatile solids destruction, a reduction in “dead spots,” and an increase in digester gas production. • Ability to accept fats, oils, grease, and food waste for potential waste-to-energy project that could further provide environmental benefits. • Project is located in the local community. Disadvantages: • Risk and cost associated with the required drilling of large holes in the digester walls.

References San Francisco State University School of Engineering. Energy Conservation and Waste Management Report. December 2010.

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Executive Summary: Draft PA No. 6 – Energy Audit Recommended Improvements at Santa Cruz WWTP

Description Several recommended improvements to equipment at the Santa Cruz Wastewater Treatment Plant (WWTP) identified as part of a recent United States Department of Energy (USDOE) energy audit would save energy and reduce indirect GHG emissions. Although the WWTP is owned by the City of Santa Cruz Public Works Department, the SCWD or the SqCWD could potentially provide funding for a portion of these improvements and receive the GHG reduction credit.

Amount of GHG Reduction The energy savings from the improvements recommended in the energy audit would correspond to an annual GHG reduction of approximately 334 MT CO2e and total of 6,679 MT CO2e of the project life. This project could reduce approximately 50 to 80% of the potential GHG reduction goals for SCWD, and 20 to 25% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability Implementation of the recommended improvements would continue to provide energy savings and GHG reduction for the 15 year life of the project. The project would be sustained by normal maintenance and repair.

Project Cost This project would result in an overall benefit over the project life. The average annual net cost of the project is approximately -$66,000 per year, because the savings from reduced energy use is greater than the cost to install and run the project. Since the project results in a net benefit, the project lifecycle GHG reduction cost per metric ton (approximately -$250 per MT CO2e) also provides a net benefit to the WWTP operations.

Table ES-1: Energy Audit Recommended Projects Summary Average Annual Average Lifecycle Lifecycle GHG Life Capital Cost GHG Reductions Annual Net Energy Cost Reduction Cost (yr) ($) (MT/Yr) Cost ($/Yr) ($/KWh) ($/MT)

15 329 $801,000 -$66,000 -$0.064 -$215

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Draft Project Assessment No. 6 – Energy Audit Recommended Improvements at Santa Cruz WWTP

Description This assessment estimates the energy savings and GHG reduction potential from implementing improvements recommended in a recent United States Department of Energy (USDOE) energy audit conducted at the City of Santa Cruz (City) Wastewater Treatment Plant (WWTP).

Background The San Francisco State University School of Engineering (with a grant from USDOE) completed an Energy Conservation and Waste Management Report in December 2010 for the City of Santa Cruz. That report made a recommendation to upgrade or replace a number of pieces of electrical equipment at the City WWTP in order to reduce overall electricity consumption at the plant. The report identified nine (9) Energy Efficiency Measures (EEMs). The EEMs are listed in Table 1 as described in the report. Note EEM No. 4 (Digester Mixing Improvements) has been addressed as part of Project Assessment No. 5, Improved Digester Mixing System at the Santa Cruz WWTP; therefore any potential energy and GHG savings from EEM No. 4 is excluded from this assessment. The applicable EEMs are listed below.

Table 1: Summary of Energy Efficiency Measures Total Average Type of EEM Energy Demand Fuel No. EEM Description Savings Savings Reduced (kWh/yr) (kW) 161 1 Turn Off the Boilers 0 Natural Gas MMBtu/Yr 2 Install VFD on Carbon Scrubber Fans 263,696 30 Electricity Install a New VFD Air Compressor in Place 3 176,835 0 Electricity of the Grit and DAFT Compressors Replace Gas Compressor Mixing with 4 Pump Mixing System in Anaerobic 1,207,354 195 Electricity Digesters 1 Replace One Centrifugal Dewatering Unit 5 53,227 42.9 Electricity with a Screw Press Dewatering Unit Replace the Standard Efficiency Lighting 6 109,176 18 Electricity with High Efficiency Lighting 7 Install Lighting Control in Various Areas 42,698 6.5 Electricity Replace Aeration Blower #1 with a High 8 272,290 31.1 Electricity Efficiency Turbo Blower Replace one of the Interstage Pumps with 9 a VFD Controlled Pump, and Use the 182,403 15.6 Electricity Smaller Interstage Pump as Backup Total Energy Savings 1,100,325 144 1 EEM. No. 4 addressed in Project Assessment No. 5.

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EEM No. 1 - Turn Off Boilers The facility has two boilers (pictured in Figure 1) which heat water for the digesters if the cogeneration system is unable to provide sufficient heating. According to facility personnel, the cogeneration system normally provides the necessary heating and the boilers are rarely used, except for maintenance. Usually the plant has sufficient time to start-up the boilers in case of cogeneration failure, but the boilers are kept warm in the interim, resulting in natural gas consumption. It is recommended that the boilers be turned off to decrease the annual natural gas consumption of the plant.

Figure 1: Digester Boilers

EEM No. 2 – Install Variable Frequency Drive (VFD) on Carbon Scrubber Fans Foul air from the trickling filters is conveyed through activated carbon filters to reduce the emission of noxious odors. The filter/scrubbers are shown in Figure 2. Each fan associated with a trickling filter is designed for approximately 13,000 cubic feet per minute (cfm). With seasonal demands, the number of fans online can range from two to four. It is recommended that the fan motor on each carbon scrubber be equipped with a VFD controller, and that all four fans run during the whole year, to provide the same amount of flow. The VFD will vary the speed of the fan to provide only the necessary air flow rate, based upon the number of trickling filters in operation.

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Figure 2: Trickling Filter Odor Scrubbers

EEM No. 3 – Install a New VFD Air Compressor in Place of the Grit and DAFT Compressors The WWTP currently has a 40 HP rotary screw type air compressor for the grit tank agitation, and a 30 HP rotary screw type air compressor serving the Dissolved Air Flotation Thickener (DAFT). The Grit and DAFT compressors share a common supply line, allowing the Grit compressor to serve as a back-up for the DAFT when an inline valve is opened. During periods of medium to low air demand, the compressor power consumption can be excessive, wasting significant amounts of electricity. It is recommended a single new 40 HP variable frequency drive (VFD) air compressor to replace the two current compressor units. A VFD air compressor will vary the output of the compressor to match the systems’ needs. One of the present two air compressors would be retained as backup.

EEM No. 5 – Replace One Centrifugal Dewatering Unit with a Screw Press Dewatering Unit Thickened anaerobic digester sludge is currently being dewatered with three centrifugal dewatering units. The WWTP is planning to upgrade one of the current centrifugal units due to a corroded housing and damaged drive motor. The recommendation from the report is to replace the centrifugal unit with a more energy efficient technology.

The centrifuge has a combined electrical load of 90 HP. According to the WWTP staff, the centrifugal dewatering units currently operate in batch mode 7 hours a day, 5 days a week. The recommended screw press dewatering system operates on a continuous basis. Currently the centrifugal dewatering units are run in off peak hours to avoid utility surcharges. The proposed screw press dewatering could run continuously for 96 hours during the week to process the same amount of sludge as one of the centrifugal dewatering units. The proposed screw press dewatering unit would have a combined electrical load of 9 HP. Replacing one of the centrifugal

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dewatering units with a screw press dewatering alternative could amount in significant energy savings.

EEM No. 6 – Replace the Standard Efficiency Lighting with High Efficiency Lighting A number of the areas at the WWTP are lit with older lower efficiency lightning. The report indicated that the audit team consulted with facility personnel regarding the operating hours for each area to determine potential savings. The suggested high efficiency lighting has approximately the same light intensity as standard efficiency lighting, but requires less input power and maintains a higher luminescence for a longer period of time. Energy savings can be realized due to lower power consumption of high efficiency lower wattage lamps while maintaining the same or improved lighting level.

EEM No. 7 – Install Lighting Control in Various Areas The report indicated that the audit team observed that lights are left on in certain areas of the WWTP even though these areas were unoccupied for extended periods of time. With digital or twist timers, lights will turn off automatically after a certain period of time as set by the occupant. By installing bi-level controllers on each lighting fixture, it is possible to have the bi-level controllers bring the lights to full brightness as soon as the lighting control is turned on in the area. Installing motion sensors, light switch timers and bi-level controllers will considerably reduce the lighting energy usage and the electrical demand. These bi-level controllers are not needed if the current standard efficiency lighting is replaced with fluorescent lighting. Install lighting motion sensors, digital timers, or twist timers in various areas of the facility is anticipated to reduce lighting energy usage.

EEM No. 8 – Replace Aeration Blower #1 with a High Efficiency Turbo Blower The facility currently has two 5,000 cubic feet per minute (cfm) centrifugal aeration blowers that provide a minimum of 2,000 cfm for channel mixing and 3,000 cfm plit between two solid contact tanks. Based on plant personnel, only one 5,000 cfm blower operates at any given time; 24 hours per day,365 days per year, for 8,760 hours per year. It is recommended that Aeration Blower #1 be replaced with a turbo-style blower, while leaving Aeration Blower # 2 as a backup. A turbo blower can provide the required 5,000 cfm and 8 psig at a fraction of the energy consumed by the current multi-stage centrifugal blower.

EEM No. 9 - Replace one of the Interstage Pumps with a VFD Controlled Pump, and Use the Smaller Interstage Pump as Backup The facility currently has a 10 MGD constant speed interstage pump (ISP) and two 25 MGD eddy-current driven pumps that pump primary treated water from primary settling tanks to trickling filters; the first stage of secondary treatment. Based on data provided by plant personnel, it has been approximated that the smaller constant speed pump provides the trickling filters 10 MGD during low flow periods, 30% of the day; while one large ISP provides 16 MGD during the high flow periods, approximately 70% of the day. The flow through the 25 MGD ISP is controlled at 16 MGD by an eddy current drive, a type of slip controlled drive. This type of drive is generally less efficient than other control schemes, as large amount of the drive energy is lost as heat. It is recommended that one of the 25 MGD eddy clutch systems be replaced with a VFD controlled pump with similar flow characteristics. This new VFD pump will provide the required flow for both flow periods, while the smaller pump can be used if additional flow is needed.

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Vendors A number of different vendors manufacture the equipment described in the EEMs above. VFDs, lighting, and controls are available from a multitude of local vendors. Screw presses suitable for dewatering at the capacities required are only known to be available from FKC and Huber. Turbo blowers are available from manufacturers such as HSI, Neuros, and Turblex. These companies have been manufacturing blowers for over 10 years.

History and Technical Maturity Use of variable frequency drives on motors has become a standard practice at many treatment plants. Centrifugal dewatering units are being upgraded to lower-energy screw presses and belt filter presses at a number of facilities in Northern California. High-efficiency lighting is being installed at many facilities as part of routine plant upgrades, with many plants qualifying for energy rebates. The City of Millbrae WPCP is currently replacing their multi-stage centrifugal blowers with turbo blowers in order to reduce their energy consumption. All of the EEMs described above are well developed and technically mature.

Reliability and Operational Complexity The EEMs described above are comprised of pumps, motors, VFDs, screw presses, blowers, and electrical equipment (motor control centers, conduit, and wires). These types of equipment have been proven to be extremely reliable throughout the United States. The City staff is accustomed to operating and maintaining the lighting, motors, and the instrumentation associated with these improvements.

The retrofit project is not anticipated to have any adverse impacts on WWTP operations. As part of EEM No. 1, the boilers used to heat the digesters would be turned off when in standby mode to reduce only natural gas usage. Staff will need to make preparations for operation of the boilers only when the cogeneration system is off-line for maintenance and the associated waste heat is no longer available. The addition of a screw press as part of EEM No. 5 is also anticipated to have a modest impact on operations. The screw press has a lower capacity than the existing centrifuges, and would therefore need to operate for a longer period of time. These systems are designed to operate unattended, so operators would only need to be on-site during start-up and shut-down procedures.

Sustainability Improving the lighting, odor scrubber, dewatering, and aeration systems at the City WWTP would continue to provide energy savings for the life of the project. The project would be sustained by normal maintenance and repair.

Local Considerations Economic Implementing the energy conservation opportunities at the Santa Cruz WWTP will benefit the local community by increasing efficiency and improving operations at the WWTP. Construction

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of the improvements would require approximately 12 - 16 months, with the potential for a majority of the required labor coming from the local community.

Environment Air: EEM Nos. 2-3 and 5-9 do not have any direct impacts on air pollution emissions. EEM No. 1 would result in shutdown of the boilers, thereby reducing the amount of carbon dioxide emitted when in stand-by mode.

Land: Since this project involves replacing existing units without any increase in needed space there is no impact on land.

Water: None of these EEMs us water or discharge water, so there is no impact on water use.

Noise: Overall noise levels from the WWTP are not anticipated to increase. Turbo blowers can be somewhat louder than multi-stage centrifugals, but are housed inside a building to mitigate noise. Screw presses spin at a much slower speed than centrifuges, and therefore operate at a lower decibel level.

Aesthetic/Visual: Most improvements would be made inside buildings. The aesthetic nature of the equipment would be similar to other equipment at the plant, and not visible from outside the property, so there are no visual impacts.

Waste by-product: Rotating equipment, such as compressors, blowers, and screw presses utilize grease for bearings, and would need to be disposed of properly.

Energy Savings and GHG Reductions The energy savings estimated below are based on implementing EEM Nos. 2-3 and 5-9. The energy savings associated with the seven improvement projects is approximately 1,148,000 kWh per year. This accounts for roughly 10% of the total energy demand for the plant (based on 11,626 MWh per year). A summary of the savings is shown in Table 2.

Table 2: Energy Savings and GHG Reductions for Energy Audit Recommendations Annual Energy Savings Annual GHG Reduction Project Title (kWh/year) (MT CO2e/year) Energy Audit 1,100,325 329 Recommended Improvements

This project could reduce approximately 50 to 80% of the potential GHG reduction goals for SCWD, and 20 to 25% of the potential GHG reduction goals for SqCWD.

Cost The capital costs for the seven improvement projects are estimated at $907,500. There is a one-time rebate incentive from PG&E through their Customized Retrofit Incentive program in the amount of $0.09/kWh for the first year’s savings, plus $100 per kW saved, not to exceed half of the total installed cost, for a total of $106,500. The resulting net capital cost in a total cost of $801,000 shown in Table 3. Operation and Maintenance costs (with the exception of energy cost) are estimated at 0.1 full time equivalents (FTE). With proper maintenance, the

scwd2 Desalination Program, GHG Reduction Project Assessments Page 6-7 K/J Project No. 0868005*03, version 9/22/2011 68 improvements should last 15 years. This project’s benefits (from electricity savings) exceed its costs (from the capital cost and O&M) resulting in a negative net cost.

Table 3: Estimated Energy Audit Recommendations Project Costs

Life Capital Average Annual Lifecycle Energy Lifecycle CO2 (yr) Cost ($) Net Cost ($/Yr) Cost ($/KWh) Reduction Cost ($/MT)

15 $800,959 -$66,056 -$0.0643 -$215

Summary of Advantages and Disadvantages Advantages: • Energy savings and GHG reductions. • Most of the EEMs involve equipment of which staff is already familiar. • Better control of aeration system with very modest operational impacts. • Screw press dewatering would offset cost of centrifuge retrofit. Disadvantages: • More complicated procedure for SCWD or SqCWD to fund project and receive GHG reduction credits. • Extensive upgrades to lighting required throughout plant.

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Executive Summary: Draft PA No. 7 – Pump and Motor Efficiency Improvement Program

Description This assessment estimates the energy savings and GHG reduction potential of an accelerated program, over a proposed 1-year period, to evaluate all pumps in the SqCWD system and install cost-effective pump retrofits.

SCWD has recently replaced or retrofitted their large pumps based on 2008 PG&E pump efficiency tests and therefore is not included in this assessment.

Amount of GHG Reduction This program would only count the GHG reduction associated with the acceleration of the pump replacement program. For example, assuming that that pumps are replaced on average every 15 years through routine maintenance, an inefficient pump that is 6 years old would continue to run at an inefficient rate for another 9 years, wasting energy and creating additional GHG for those 9 years. If this pump were replaced, the energy savings and associated GHG reduction could only be counted as a GHG reduction project for 9 years.

The SqCWD pumps that have been identified as inefficient have remaining lifespans of between 3 and 12 years. However, because actual pump maintenance and replacement can be dynamic and influenced by other factors, the SqCWD operations staff is reviewing this PA and the identified pumps to confirm the assumptions herein. Any resulting changes to the pump replacement schedule assumptions will be reflected in the final PA.

The program could start out earning 49 MT CO2e per year, would gradually decrease as more pumps reach their life expectancy, and would expire to zero after year 12. The average annual GHG reduction could be approximately 29 MT CO2e per year, which is approximately 2% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability As described above, because a pump and motor efficiency program is an acceleration of an existing program it is a temporary project and would expire after 12 years for SqCWD.

Project Cost The project would cost approximately $113,000 per year for the first five years (during loan repayment), and would cost approximately $588 per MT CO2e over the 12-year life of the project.

Table ES-1: Pump and Motor Efficiency Improvement Program Summary Average Capital Average Unit Cost Project Annual GHG Cost Less Space Project Annual Cost ($/MT Life (yrs) Reduction Incentives Required ($/year) CO2e) (MT CO2e/year) ($) SqCWD 12 29 $366,000 $30,000 $980 None

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Draft Project Assessment No. 7 – Pump and Motor Efficiency Improvement Program

Description This assessment estimates the energy savings and GHG reduction potential of an accelerated program over a proposed 1-year period to evaluate all pumps in the SqCWD systems and install cost-effective pump retrofits. SCWD has recently replaced or retrofitted their large pumps based on 2008 PG&E pump efficiency tests and therefore is not included in this assessment.

Background SqCWD relies solely on groundwater. The groundwater is pumped to the surface, treated, and pumped through the distribution system. The SqCWD pump database (included as Attachment 1) lists 18 well pumps and 11 booster pump stations in its water system. This assessment focuses on the larger, more-energy intensive pumps that are 50 horsepower (HP) or greater.

Current PG&E Pump Efficiency Testing: SqCWD provided a database of monthly pump and motor efficiency data that includes the latest replacement date, as summarized in Attachment 1. Seven of the well pumps had average annual efficiencies of less than 65% from July 2010 to June 2011, while the other 11 either had better efficiencies or were recently replaced.

Note: This assessment assumes that motors are not replaced as a part of this program. SqCWD has replaced all well pump motors within the last 10 years.

Description of Pump Efficiency Improvement Program: This program would accelerate and systematically replace many of the older or less efficient pumps over a 1-year period and would include the following elements:

1. Pump Efficiency Testing Database Update: The SqCWD database would be updated with any pump and motor upgrades that occurred after June 2011 or any additional efficiency testing.

2. Ranking/Prioritization of Pumps: The pumps would be ranked for replacement based on factors such as condition, necessity in the process train, redundancy, and cost.

3. Program Budget Determination: Based on the replacement cost analysis and the available resources and funding, an acceptable replacement budget and schedule would be established.

4. Replacement Schedule Coordination: Replacing the pumps requires coordination with water system operations to minimize disruption to the system. It may not make sense to perform replacements during periods of high demand.

5. Replacement of Pumps: Pump replacement would occur over a 1-year period and includes ordering and installation of new pumps and coordination with water system operations.

6. Disposal of Old Pumps: Old pumps that are replaced through the program would be discarded. Environmentally-friendly disposal methods, such as refurbishment or recycling, would be preferred.

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7. Coordination of PG&E Reimbursement: Coordination with PG&E is required to receive the pump efficiency rebates. Information for PG&E’s Energy Management Systems for Pumps and Pumping Systems and Advanced Pumping Efficiency Program are available online.

Vendors Pump Vendors: Although the existing pump manufacturers are not listed in the database, it is anticipated that SqCWD would be purchase replacement pumps from similar manufacturers.

Pump Efficiency Testing: SqCWD uses PG&E’s pump efficiency testing service.

Management of the Program: The pump efficiency improvement program could be managed by SqCWD or by an outside consultant. Staff involvement would be required to determine the budget and schedule, as well as during pump replacement implementation to coordinate with water system operation. The program manager would interface with SqCWD (if managed by an outside consultant), equipment vendors, and PG&E as needed to receive rebates.

History and Technical Maturity This type of energy savings approach is proven and technically mature. The program does not implement a new technology, but utilizes the concepts of increasing efficiency and conducting preventive maintenance, which SqCWD already incorporates into its O&M plans.

Reliability and Operational Complexity The planning phase of the project, which includes updating the pump database, budgeting, and scheduling, should not affect operation of the water system but requires SqCWD staff time. Replacing the pumps requires coordination with water system operations to minimize disruption to the system. It may not make sense to perform replacements during periods of high demand. It is anticipated that one FTE staff would be required for one year while pumps are being replaced.

Once the program is completed, it is anticipated that time dedicated to maintaining and repairing pumps would be reduced compared to pre-program levels.

Sustainability Because of the concept of additionality, this program would only count the GHG reduction associated with the acceleration of the pump replacement program. Therefore, a pump and motor efficiency program is a temporary project and would expire after 12 years for SqCWD.

Local Considerations Economy Since the number of pumps potentially replaced is relatively small, the program would not create long-term local jobs, but would help local vendors in the short-term.

Environment This program would reduce the energy consumption of SqCWD, but would not reduce local direct GHG emissions or reduce local waste.

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Air: Electric pumps do create air pollution, but GHG emissions will be reduced due to the reduced amount of electricity used for the same purpose.

Land: Since this project involves replacing one unit with another of the same function and similar size, there is no impact on land.

Water: There is no impact on water quality.

Noise: Noise impacts could be lowered because of the new pumps.

Aesthetic/Visual: There is no aesthetic or visual impact.

Waste By-Products: Disposal of old pumps is the primary environmental concern for this project. Selling or donating for refurbishment or recycling of materials would be preferred over landfill disposal.

Energy Savings and GHG Reductions This project decreases the consumption of energy and associated indirect GHG emissions of the SqCWD system.

Energy savings and GHG reductions from this program were estimated using the available information in the PG&E pump testing databases. Based on these calculations, SqCWD could save approximately 168,000 kWh per year, which results in an average annual reduction of approximately 30 MTCO2e per year. However, since the replacement of SqCWD pumps have different remaining lives, the associated annual GHG reductions will decline over time. This project is estimated to reduce approximately 2% of the potential GHG reduction goals for SqCWD.

Table 1 provides a summary of the energy production and GHG reduction from a pump and motor efficiency improvement program.

Table 1: Estimated Energy Savings and GHG Reductions for Pump and Motor Efficiency Improvement Program Average Annual GHG GHG Reduction over Program Life Annual Energy Reduction Project Life (years) Savings (kWh/yr) 1 (MT CO2e) (MT CO2e) SqCWD 12 168,0002 292 354 1 Based on 2009 PG&E emission factor of 641 lbs CO2e/MWh. 2First year reduction is 49. The reduction of the program would decline over time as more pumps reach their estimated lifespan. See Figure 2 below.

GHG reduction credits only can be taken for an accelerated pump/motor replacement program. For example, the SqCWD San Andreas well pump was replaced 12 years ago, so we assume that the pump would be replaced again, due to deteriorating performance, in approximately 3 years as part of routine maintenance. (It is assumed that each pump would operate for 15 years after the last replacement date.) Therefore, a pump replacement program could take credit for the energy savings and GHG reduction only for three years. Table 2 shows the estimated energy savings and GHG for the life of the SqCWD project.

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Table 2: SqCWD Pump Energy Savings and GHG Reduction over Time

Estimated Annual Energy Savings by Pump1 (kWh/year) Total Total Estimated Estimated Annual Annual Yr Aptos San Ledyard Madeline Seascape Garnet Energy GHG Creek Andreas Savings Offset (MT (kWh/yr) CO2e/yr) 1 32,629 33,341 12,016 28,919 24,972 36,429 168,306 49 2 32,629 33,341 12,016 28,919 24,972 36,429 168,306 49 3 32,629 33,341 12,016 28,919 24,972 36,429 168,306 49 4 32,629 33,341 12,016 28,919 24,972 -- 131,877 38 5 32,629 33,341 12,016 28,919 24,972 -- 131,877 38 6 32,629 33,341 12,016 28,919 24,972 -- 131,877 38 7 32,629 33,341 12,016 28,919 -- -- 106,905 31 8 32,629 33,341 12,016 ------77,986 23 9 32,629 ------32,629 9 10 32,629 ------32,629 9 11 32,629 ------32,629 9 12 32,629 ------32,629 9 Program Total 1,215,956 354 Annualized 101,330 29 1This table only includes the well pumps identified as inefficient. Attachment 1 contains the full list of SqCWD well pumps.

Cost This section summarizes the estimated project costs. The supporting cost information is included in Attachment 2.

Capital Cost: The capital cost for this project includes: • Replacement of pumps, including materials and installation. • Resizing or replacement of original pump fittings and valves if incorrectly sized for new equipment or decrepit. • Replacement of decrepit equipment pad, as necessary. • Removal and disposal of old pumps. • 10 percent markup for engineering costs and contingency.

The capital cost is estimated to be approximately $385,000 for 6 pumps for SqCWD.

PG&E Incentives: PG&E offers incentives for pump replacement through the Advanced Pump Efficiency Program (APEP). The efficiency information in the SqCWD database was entered into the APEP Incentive Calculator, which can be downloaded on the APEP website http://www.pumpefficiency.org/, to determine the potential incentives available. The calculator shows that SqCWD could receive approximately $19,000 in pump efficiency rebates.

O&M Cost: A pump efficiency improvement program requires program administration, management of pump testing and task orders, and working with contractors during pump replacement. Staffing may increase by one FTE employee for the 1-year duration of the project.

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In addition, the pump replacement program is estimated to save SqCWD approximately $25,000 annually in energy costs.

Table 2 provides a summary of the costs, savings and incentives for a pump and motor efficiency improvement program.

Table 2: Pump Efficiency Improvement Program Costs and Incentives Unit One-time Capital Cost Average Program Capital Cost PG&E Less Annual Life (yrs) Cost ($) 2 ($/MT Incentive ($) Incentive ($) Cost ($/yr) CO2e) SqCWD 12 $385,000 $19,000 $367,000 $30,000 $980 1Assumes a 6% interest rate and 13% bond fees. 2For 5 years, assuming a debt repayment of 5 years. Includes energy cost savings.

Summary of Advantages and Disadvantages Advantages: • Lower energy cost for pumps • Preventive maintenance would improve reliability by reducing the risk of water system disruptions • Less maintenance time and cost after implementation of program

Disadvantages: • A pump replacement program would only be a short-term GHG reduction project. GHG reduction credits can only be taken during accelerated program period after which other GHG reduction approaches would have to be considered. • Higher capital cost during 1-year replacement period

References Center for Irrigation Technology. Advanced Pumping Efficiency Program: http://www.pumpefficiency.org/

Pacific Gas & Electric. Energy Management Systems for Pumps and Pumping Systems. http://www.pge.com/includes/docs/pdfs/mybusiness/energysavingsrebates/incentivesbyindustry/agricultur e/agPumping.pdf

Attachments Attachment 1 – SqCWD Pump and Motor Testing Database

Attachment 2 – SqCWD Cost Estimate

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Executive Summary: Draft PA No. 8 – Food Waste to Energy Project

[Note: Kennedy/Jenks currently is conducting a Food Waste and Cogeneration Study (Study) for the City of Santa Cruz (City) Public Works Department (PW) which would be located at the City Wastewater Treatment Plant (City WWTP). Since the results of the Study are not yet available, this project assessment contains preliminary food waste to energy estimates and will be finalized with project-specific details at a later date.]

Description A food waste to energy (FWTE) project combines organic waste from foods with wastewater solids in a wastewater anaerobic digester to produce additional biogas (additional to the biogas produced from wastewater solids alone). According to the US EPA, food waste produces approximately three times the amount of biogas compared to wastewater solids. In this project assessment, the additional digester gas would replace current natural gas use and therefore would reduce direct GHG emissions. The quantity of local source-separated food waste is estimated to be between 60 and 100 tons per week, which could produce up to 76,400 cubic feet per day (cfd) of digester gas. Depending on the extent of the PW FWTE program, all or a percentage of the available food waste and resulting GHG reduction could be credited to SCWD and/or SqCWD.

Amount of GHG Reduction Combustion of the additional digester gas would result in a reduction of approximately 810 MT CO2e per year and over 16,200 MT CO2e total over the project life. Depending upon how the project is structured, the GHG offsets could benefit SCWD, SqCWD, the City PW, or all three. This project could produce up to 100% of the potential GHG reduction goals for SCWD and approximately 50% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability A FWTE program would continue to produce biogas and provide GHG reduction for the estimated 20 year life of the project. The project would be sustained by normal maintenance and repair.

Project Cost The average annual net cost of the project is estimated to be approximately $280,000 per year, since the capital, operation, and maintenance costs are greater than the savings from reduced natural gas use.

Table ES-1: Food Waste to Energy Project Summary Average Average Annual Lifecycle Lifecycle GHG Life Capital Annual Net GHG Reductions Energy Cost Reduction Cost (yr) Cost ($) Cost ($/Yr) (MT/Yr) ($/Therm)1 ($/MT)

20 $3,750,000 $280,000 810 $1.5 $276

1Since this project was assumed to reduce natural gas use, the lifecycle cost is reported in dollars per therm. scwd2 Desalination Program, GHG Reduction Project Assessments Page 8-1 K/J Project No. 0868005*03, version 10/6/11 76

Draft Project Assessment No. 8 – Food Waste to Energy Project

[Note: Kennedy/Jenks currently is conducting a Food Waste and Cogeneration Study (Study) for the City of Santa Cruz (City) Public Works Department (PW) to be located at the City Wastewater Treatment Plant (City WWTP). Since the results of the Study are not yet available, this project assessment contains preliminary food waste to energy estimates and will be finalized with project-specific details at a later date.]

Description This assessment estimates the energy production and GHG reduction potential from a FWTE project at the City WWTP. Depending upon how the project is structured, the GHG offsets could benefit SCWD, SqCWD, the City PW, or all three.

A food waste to energy (FWTE) project combines high-strength organic waste from foods with wastewater solids in a wastewater anaerobic digester with excess capacity to produce biogas. According to the US EPA, food waste produces approximately three times the amount of biogas compared to wastewater solids. Benefits of anaerobic co-digestion can include enhanced biogas production, improved biogas quality, improved biosolids dewaterability, and reduced residual biosolids. As an alternative to landfill disposal, food scrap and food processing wastes are ideal for anaerobic digestion at wastewater treatment plants, assuming there is excess digester capacity. Figure 1 illustrates the FWTE process.

Figure 1: Food Waste to Energy Process

A combustion generator operating on digester gas produces emissions, including CO2 and a small amount of other gases. However, these emissions are not accounted for as “GHG emissions” because they come from a non-fossil fuel source and are considered biogenic. The combustion generator process converts the more potent GHG (methane) to less potent GHG (carbon dioxide) while extracting energy in the process. The emissions of CO2 (and a small scwd2 Desalination Program, GHG Reduction Project Assessments Page 8-2 K/J Project No. 0868005*03, version 10/6/11 77 amount of other gases from the digester biogas combustion generator at the WWTP) would be released with or without the digester gas combustion generator system. Therefore, the energy produced from digester methane combustion generators is considered to be “GHG-free” energy.

Kennedy/Jenks currently is conducting a Food Waste and Cogeneration Study (Study) at the City WWTP for the City PW. The purpose of the Study is to help PW to better understand the amount of food waste available, investigate location options for a food waste receiving station, create a preliminary design for a receiving station, and analyze potential generation options. The current digester mixing system must be upgraded before PW implements a food waste co- digestion program, which is more fully described in Project Assessment #5 – Improved Mixing.

Vendors In general, food waste receiving facility designs are site specific. Land availability, waste characterization, waste hauler preferences, aesthetic concerns (visual, audible, odor related), and treatment plant configuration are some factors that are used to determine the ultimate configuration and design of the receiving facility. Several specialty engineering consultants such as Kennedy/Jenks have experience designing these types of facilities.

History and Technical Maturity A handful of wastewater treatment plants throughout the United States have been receiving food processing wastes, such as cheese whey, food processing rinse water, and tomato paste, in liquid form for over 25 years. Due to issues with sorting, transportation, and pre-processing, food waste in solid form has not been as an attractive feedstock as liquefied food waste or fats, oils, and grease. Plants in Europe have been digesting food scrap wastes more readily over the past few years due to European policies requiring 100% diversion of organic materials from landfills. The technological capabilities to pre-process and digest food waste are well understood and well established.

The United States Environmental Protection Agency (US EPA) estimates that a total of 243 million tons of municipal solid waste (MSW) was generated in 2009. The US EPA conducted a study that found that food waste accounts for 14.1 percent of the total MSW that is generated in the United States. This represents over 34 million tons of food waste generated in 2009 alone. Currently, only about 2.5 percent of food waste actually is diverted from landfills nationwide. The majority of food waste that is diverted is used for composting, which requires large amounts of land and releases volatile organic compounds into the atmosphere.

The California Energy Commission estimated that as of 2007, there were 22 animal and food waste digester facilities in California (CEC 2010). FWTE is a relatively new technology in California; however, the technology has proven to be effective. East Bay Municipal Utility District’s (EBMUD) main wastewater treatment plant in Emeryville, California has been a pioneer in successfully co-digesting food waste for several years. EBMUD has found that food waste produces over three times as much methane as municipal wastewater solids. EBMUD uses the additional digester gas to run three dual-fuel IC engines rated at 2.15 megawatts (MW) each for a total of 6.45 MW. Powering the plant with biogas-generated electricity and using recovered heat in the digesters (cogen) saves EBMUD about $2,000,000 annually (US EPA 2011).

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Reliability and Operational Complexity The reliability of a FWTE project can depend on the quality, quantity and consistent availability of food waste streams, which is currently being investigated in the Study. The challenges of creating energy from food waste relate to the receiving, conditioning, and feeding of the food waste into the anaerobic digester. Unfortunately, food wastes can have significant quantities of unsuitable material such as plastic and metals, which could harm waste treatment plant mechanical equipment. In general, source separated food wastes are most desirable since this type of waste requires minimal processing at the wastewater treatment plant. Once the food waste is sorted, it is important that it is metered into the digester to prevent an upset of the biological treatment process due to over-feeding.

A FWTE program should have a modest impact on operations. Impacts come from the construction, operations and maintenance of the receiving station, administration of the food waste program, and the O&M of the generation equipment. The receiving station could require an area for the hauler interconnection equipment and the drive-up pad. The receiving station and generation equipment pads would be modest in size. Careful consideration must be given to the design to minimize impacts on existing plant operations. The receiving and odor control equipment will require frequent cleaning and periodic maintenance.

There also is a risk that haulers could bring in toxic or other undesirable materials to the facility that could harm the digestion process. This risk can be mitigated either by clear rules, strict manifest requirements for waste haulers, and/or sampling of the waste received. Testing of the sampled waste usually is not done unless a hauler created a problem with the digester. However, this sampling technique has been used by other agencies as an effective risk management tool.

Project Life and Sustainability A FWTE program would continue to produce biogas and provide GHG reduction for the estimated 20 year life of the project. The project would be sustained by normal maintenance and repair.

Local Considerations Economic Collection of local food waste as a separate waste stream than garbage could provide some additional long-term services jobs.

Environment Air: Impacts to air quality related to receiving and processing food waste should be minimal. The most notable impact would be potential odor emissions from the food waste receiving area. Odor emissions can be mitigated by containing the receiving area in a building, and using equipment that minimizes the possibility of odor emissions. Food waste that is typically disposed of at the City’s Resource Recovery Facility on Dimeo Lane would instead be transported to the WWTP for processing and digestion. By having a receiving station that is centrally located, implementation of this project would result in a reduction in air pollution and GHG emissions from hauling a slightly shorter distance. For a conservative estimate, this assessment does not account for these reductions.

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Land: As compared to alternative disposal methods, receiving food waste at a wastewater treatment plant will require less land than landfill disposal or composting. Land requirement for the receiving facilities at wastewater treatment plants is relatively small (roughly 0.5 to 1.0 acre, including paved receiving area). There is also a co-benefit of extending the life of the local landfill. The facility would be located at the City WWTP, so there should be no additional land impacts.

Water: There are no anticipated water quality impacts, but the project will use a modest amount of process and clean-up water. Water usage for a waste receiving facility is minimal and is typically used for wash down and dilution liquid for food waste (approximately 2,000 gallons per day). This water can be treated effluent from the wastewater treatment plant. Impacts to surrounding surface water features should be minimal since run-off from the receiving facilities is contained and typically routed back to the plant for treatment.

Noise: Noise can be a concern for the receiving station, since the WWTP is located near a residential community, but can be mitigated by enclosing the area or providing a sound wall. Noise on surrounding surface streets could increase from additional truck traffic. If noise on surrounding surface streets is a concern, restricted hauling times can mitigate the impact. Potential noise from pre-digester food processing/grinding pumps would be confined to the WWTP site.

Aesthetic/Visual: Visually, the receiving area will not stand out from other industrial systems at the WWTP, creating little to no impacts. If aesthetics does become an issue, equipment can be screened or enclosed.

Waste by-product: The waste product that is generated from digestion of food waste is typically dewatered for further processing or disposal. Processed/digested food waste would have a smaller volume than raw food waste and could be used as a soil amendment.

Energy Savings and GHG Reduction Based on a recent survey of local food service establishments (FSEs), the quantity of source- separated food waste is estimated to be between 60 and 100 tons per week based on a seasonal average (slightly more during the summer, slightly less during the winter). This estimate includes local FSEs and additional food waste potentially available from other sources, such as UC Santa Cruz. Kennedy/Jenks’ Waste-to-Energy Model estimates that approximately 76,400 cubic feet per day (cfd) of digester gas can be created from 100 tons of food waste per week. This amount of gas is sufficient to generate approximately 160 kW of electricity, assuming an internal combustion (IC) engine with a 35% electrical efficiency.

The additional digester gas generated by the food waste could directly offset all or a portion of natural gas currently combusted in the existing engines, or could supply fuel for a new generator that could be installed by SCWD and/or SqCWD. The first scenario would directly offset the amount of natural gas currently combusted in the existing engines, whereas the second would offset the amount of electricity that SCWD and/or SqCWD purchase from the grid.

Assuming the additional gas offsets natural gas, the natural gas savings resulting from use of the additional digester gas is approximately 15,300 million BTU per year (MMBtu/yr), or 153,000 therms. Combusting the additional digester gas would also result in a reduction of approximately 800 metric tons of non-biogenic CO2 (MT CO2e) per year, as summarized in Table 2. Depending upon how the project is structured, SCWD and/or SqCWD could take credit scwd2 Desalination Program, GHG Reduction Project Assessments Page 8-5 K/J Project No. 0868005*03, version 10/6/11 80 for some or all of the GHG offsets. This project could produce up to 100% of the potential GHG reduction goals for SCWD and approximately 50% of the potential GHG reduction goals for SqCWD.

Table 2: Energy Savings and GHG Reduction from a Food Waste to Energy Project

Average Annual Annual GHG Reduction Lifetime GHG Reduction Energy Savings (kWh/yr) (MT CO2e/yr) (MT CO2e/yr)

0 810 16,200

Cost With proper maintenance of piping, equipment, and controls, a FWTE receiving and processing facility is estimated to operate for 20 years or more. Anaerobic digesters, which are not included in the capital cost estimate for this project, have life expectancies of 30 or more years. The IC engines recently underwent a major overhaul and, along with associated support systems, should have a life expectancy of at least 10 years.

Capital Cost: The 100 tons per week (14 tons daily average) of food waste quantified in the section above would likely arrive at the WWTP during 3 or 4 days per week, rather than on a daily basis due to MSW collection schedules; therefore, the receiving station would be sized to accept up to 50 wet tons per day of food waste. The capital cost of the project is based on locating a facility at the WWTP sized to receive source-separated food scrap and processing waste with minimal contamination. In general, this would include a storage tank, metering and mixing pumps, food waste grinder, glass-lined ductile iron pipe, odor scrubber, waste measuring equipment, and concrete receiving area for truck unloading. The probable cost has an accuracy of plus 50 percent to minus 30 percent.

O&M Cost: It is anticipated that staffing may permanently increase by one-FTE employee to operate and maintain the receiving facility at the WWTP. Receiving equipment and pumps would require daily to weekly maintenance. In addition, a portion of the material received would have to be screened out of the system prior to digestion (due to plastics, metals, etc.) and would need to be disposed of at a landfill. The screened material is anticipated to account for 10% of the overall material received and current disposal fees at the landfill are $75/ton. Tipping fees are not included in this analysis, since it has not yet been determined how disposal costs would be structured. In addition, operating a food waste receiving program would require additional staff for program administration.

Incentives: The funding incentives for installing a waste receiving facility are generally geared to the ultimate use of the digester gas that is produced. The improvements directly associated with waste receiving (i.e. pumps, tanks, and site improvements) are not eligible for incentives. However, energy efficiency incentives could be used to lower the cost of project components, such as premium efficiency pumps and motors.

Waste receiving can generate funds through tipping fees, which are charged to the haulers who use the waste receiving station. However, considering PW owns and operates MSW hauling for the service area, a reduction in tipping fees is not applicable for this FWTE program. If waste from outside of the PW MSW collection area is allowed, associated tipping fees may provide added revenue. Table 2 presents a summary of the program costs.

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Table 3: Estimated Costs for Food Waste to Energy Project

Life Capital Cost Avg Annual Net Lifecycle Energy Lifecycle GHG (yr) ($) Cost ($/Yr) Cost ($/Therm)1 Reduction Cost ($/MT)

20 $3,750,000 $280,000 $1.5 $276

1 Since this project was assumed to reduce natural gas use, the lifecycle cost is reported in dollars per therm.

Summary of Advantages and Disadvantages Adding a food waste receiving system would allow SCWD and/or SqCWD to take advantage of excess digester capacity to generate renewable energy. Below is a summary of advantages and disadvantages of adding food waste. Advantages:  Additional biogas production to produce “GHG-free” energy.  Optimized use of excess digester capacity.  Reduced truck traffic to nearby landfills.  Takes advantage of existing process and infrastructure at the WWTP.  Diverts food waste from landfills and sewer systems.  Potential to create local food waste collection jobs.

Disadvantages:  Increased loading on digesters.  Increase in O&M costs.  High capital expenditures.  Potential odor concerns.  Potential operational impact from haulers if receiving station not designed correctly.  Requires on-going set-up and oversight of a FWTE project.

References California Energy Commission. “Waste to Energy (WTE) & Biomass in California.” Updated May 2010. http://www.energy.ca.gov/biomass/

City of Santa Cruz, “Characterization of Disposed Waste for the Year 2009.” April 2010.

U.S. Environmental Protection Agency. “Turning Food Waste into Energy at the East Bay Municipal Utility District (EBMUD).” Updated June 2011. http://www.epa.gov/region9/waste/features/foodtoenergy/ebmud-study.html and http://www.epa.gov/region9/organics/ad/EBMUDFactSheet.pdf

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Executive Summary: Draft PA No. 9 – Renewables Purchase Programs

Description A renewables purchase program would invest in renewable energy projects around California or in the United States. The substitution of renewables for grid power provides a GHG reduction. This assessment specifically addresses the following types of renewables purchase programs:

• Equity purchase through a joint powers authority (JPA) • Direct power purchase agreement (PPA) • PPA through a community choice aggregation (CCA) • Renewable energy credits (RECs)

Amount of GHG Reduction SCWD and SqCWD could purchase any amount of renewable energy or RECs. For the purposes of this assessment, it is assumed that SCWD and SqCWD would purchase approximately 6,800 MWh per year, or 1,978 metric tons (MT) CO2e per year, which is the electricity use of the proposed desalination plant running at half capacity. Depending upon the extent of the project, this project has the ability to reduce 100% of the potential GHG reduction goals for SCWD and SqCWD.

Project Life and Sustainability JPA and PPA contract terms could be negotiated for various lengths of time. Since the life of the desalination project is expected to be 30 years, this assessment assumes the life of these contracts would also be 30 years. The contract could be renewed to maintain a sustainable project. RECs could be purchased annually each year for 30 years, once for the 30 year duration of the project, and anything in between. Project Cost Power costs start at less than PG&E but escalate at a slightly faster rate, and therefore end up after 30 years with a lifecycle cost that is marginally more than purchased power from PG&E. Table ES-1 summarizes the estimated costs of the potential projects discussed above.

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Table ES-1: Renewables Purchase Program Summary Lifecycle Annualized Average Lifecycle GHG Project GHG Capital Annual Net Energy Project 1 Cost Life Reduction Cost ($) Cost Cost ($/MT (MT CO2e/yr) ($/year) ($/kWh) CO2e) Join a JPA 30 1,978 $100,000 $200,600 $0.014 $48 Direct 30 1,978 $500,000 $86,409 $0.012 $42 Access PPA Join an 30 1,978 $100,000 $154,927 $0.009 $32 Existing CCA Create a 30 1,978 $3,000,000 $564,293 $0.050 $176 Local CCA Purchase 30 1,978 $0 $32,986 $0.003 $11 RECs 1 This represents the start-up cost of the various options.

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Draft Project Assessment No. 9 – Renewable Energy Purchase Programs

Description This assessment estimates the energy savings and GHG reduction potential from the purchase of energy and/or environmental attributes from renewable energy projects.

Background Investing in renewable energy projects to serve an electricity load instead of purchasing electricity from the PG&E grid, which is in large part produced from fossil fuels, provides a GHG reduction benefit. Renewable energy technologies include solar photovoltaic (PV), wind turbines, solar thermal, geothermal, biomass, and fuel cells.

Types of Projects A renewable energy purchase program can be developed through a number of avenues, including: • Equity Purchase

o Local renewable energy project venture o Non-local renewable energy project venture o Joint Powers Authority (JPA) • Power Purchase Agreement (PPA)

o Direct access o Community Choice Aggregation (CCA) • Renewable Energy Credits (RECs) The major difference between these approaches is the level of involvement and level of risk assumed by SCWD and SqCWD in obtaining the GHG reduction benefits through renewable energy purchase programs. The following sections describe each type of renewables purchase.

Equity Purchase Local Projects: Local equity purchases are not considered in detail in this assessment. Project Assessment No. 10 discusses local solar projects, and Project Assessment No. 11 discusses fuel cells. Other technologies are not being pursued by SCWD and SqCWD at this time as an equity purchase.

Non-Local Projects: SCWD and SqCWD could invest in and own all or a portion of a renewable energy project that is located in another part of the state or country (such as the Mojave Desert, which has high solar resources). In an equity partnership, SCWD and SqCWD would be responsible for construction, operations and maintenance, and would acquire risk for the project. However, equity purchases often entail small (approximately 1 MW) projects, which can be more expensive than large-scale (approximately 10 to 250 MW) developments because of economies of scale. Since SCWD and SqCWD have a preference to evaluate local projects, this assessment does not further investigate non-local equity purchase projects.

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Collaboration through a JPA: A joint powers authority (JPA) is an entity made up of several public agencies that owns and operates renewable energy projects through a joint equity purchase. SCWD and SqCWD would share risk and responsibility of owning the project with other members of the JPA. A higher level of management participation also would be required for equity partnership in a JPA. While terms of specific contracts vary, equity partners share the responsibility for the installation to meet performance requirements, and therefore they tend to participate in the decision-making and other aspects of the O&M of the installation.

Power Purchase Agreement Direct Access PPA: SCWD and SqCWD could purchase renewable energy through a direct access PPA, in which electricity and associated GHG reduction credits from a renewable energy project developed by a third party would be sold to SCWD and SqCWD for a contracted price and duration of time. Examples could include large-scale (approximately 10 to 250 MW) wind, solar, and hydropower projects.

One benefit of participating in a PPA is that SCWD and SqCWD would not have to develop expertise outside its existing water utility knowledge base or hire additional operational staff. In addition, PPAs could tap into locations with richer renewable resources, such as greater solar insolation in southern California and Arizona, or higher and more constant wind speeds in the Tehachapi Mountains. However, SCWD and SqCWD may prefer to invest in local renewable projects, which is possible but provides fewer options.

The requirements for direct access are highly complex. For instance, serving existing meters requires the creation of a Load Serving Entity (LSE), which would be expensive, difficult, and time-consuming to create. Even if the cost of renewable energy generation was low, SCWD and SqCWD could lose money for a number of years due to the set-up costs associated with the LSE contract.

SCWD and SqCWD could purchase renewable energy through a direct access structure. This scenario would be useful if magnitude of the project was small enough to serve the SCWD and SqCWD load. However, SCWD and SqCWD may want to consider founding or joining a (CCA) if they want to pursue a larger PPA or build larger local renewable projects.

Collaboration through a CCA: A community choice aggregation (CCA) is an entity or group of entities, such as a city or county or both, that purchases and/or generates electricity and sells it to the local community. CCAs allow communities to increase the amount of renewable energy in the portfolio. Pacific Gas & Electric (PG&E) would continue to delivery electricity through the grid and provide billing and customer services.

A benefit of developing a CCA is that it can serve as a business structure for procurement of direct PPAs for local renewable energy projects. There are a number of steps to start a CCA connected to PG&E, including an implementation plan, a service agreement, and exit fees. The Local Energy Aggregation Network (LEAN) organization provides information to help communities build their own CCAs. However, SCWD and SqCWD would have to develop the expertise and staff necessary to become an electricity provider. Another option would be to join an existing CCA, such as Marin Clean Energy.

Renewable Energy Credits RECs are tradable, non-tangible energy commodities that represent proof that 1 megawatt-hour (MWh) of electricity was generated from an eligible renewable energy resource. RECs

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represent the environmental attributes of the electricity produced and are sold separately from commodity electricity. For example, SCWD and SqCWD could buy RECs from a wind farm in southern California, which would include buying the greenhouse gas offsets. The RECs would have to be registered to ensure that no one else is claiming the environmental benefits.

One major benefit of RECs is the flexibility to buy them during the annual true-up process. For example, if SCWD and SqCWD operates the desalination plant more than anticipated in a given year and the normal GHG mitigation portfolio does not reduce or offset enough GHGs; SCWD and SqCWD could offset the remaining balance by purchasing RECs for one year. In addition, SCWD and SqCWD would not have to develop expertise outside existing water utility knowledge base or hire additional operational or administrative staff.

While certified RECs are legitimate and real, they are less tangible than equity ownership in a renewables generation project and could be more challenging politically.

History and Technical Maturity California’s Renewable Portfolio Standard (RPS) policy requires the state’s utilities, including PG&E, to increase the percentage of their portfolio generated from renewable electricity over time. PG&E and the State of California have numerous incentive programs that act as significant drivers promoting the development of renewable energy projects. Many private companies utilize some combination of the different forms of renewable energy purchasing to offset their GHG emissions. Public agencies have been more likely to select direct ownership of renewable energy infrastructure, such as installing PV panels on administration buildings or cogeneration facilities at wastewater plants. JPA: The Northern California Power Agency (NCPA) is a joint powers agency (JPA) founded in 1968 that currently has 14 members, including cities such as Palo Alto and Roseville, and water utilities such as Turlock Irrigation District and Placer County Water Agency. NCPA’s portfolio includes about 95% renewables, which includes geothermal, hydroelectric, and natural gas facilities that NCPA owns and operates. However, the total load of scwd2 may not be large enough to merit membership in NCPA. More information can be found at: http://www.ncpa.com/.

Direct Access PPA: PPAs have long been seen by private companies and a few large public agencies as an opportunity to reduce their exposure to volatile electricity prices. As a result of the California Solar Initiative in particular, numerous solar project developers have successfully partnered with public and private entities, and dozens of 10-to-30 year contracts are in place. For example, the San Francisco Public Utility Commission (SFPUC) has a PPA with Recurrent Energy on a 5 MW photovoltaic project located on the SFPUC Sunset Reservoir, which started up in December 2010. SCWD and SqCWD could enter into a PPA with a renewable energy developer, or could join a CCA that has an existing knowledge of acquiring PPAs. There are two important considerations when evaluating a PPA company – track record and PPA terms. Terms include the price per kWh that the third party charges SCWD and SqCWD for the electricity generated, the annual escalator on the price, the length (15 to 25 years) of the contract, and potential buyout terms. PPA providers include SunPower, SunEdison, Solar Power Partners, SolarCity, Enfinity, SunWize, and Real Goods. CCA: SCWD and SqCWD could join a CCA that has an existing knowledge of acquiring PPAs. Marin Clean Energy (MCE) is a CCA that has been serving customers since 2010. As of

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August 2011, MCE serves over 13,000 customers in the cities and County of Marin. MCE has comparable prices to PG&E, but the benefit is that customers get a higher percent of renewables in the energy portfolio. Regular customers get approximately 27% renewables (versus 15% renewable currently from PG&E), and customers that pay a 1 cent per kWh premium are able to receive 100% renewables. The goal is to achieve about 70% renewables by 2020. However, MCE has indicated that they may not accept members outside of their local geographic area. More information can be found at: http://marincleanenergy.info/.

RECs: A few public agencies purchase RECs, including the City of Santa Monica, which purchases RECs to offset 100 percent of their fossil fuel consumption (Munves). The development of and participation in the renewable energy purchasing marketplace has been hampered by insecurity over regulatory policy and long-term market value of RECs, but the National Renewable Energy Laboratory projects, even under a low-growth scenario, a 33.7 terawatt-hour (million MWh) annual REC market in the United States by 2015 (Bird).

RECs are offered for sale by various vendors, with varying degrees of quality control. REC quality has been an issue in the media, with various programs being criticized as “green- washing.” To ensure the purchase of real and verifiable RECs, vendors should be recognized by organizations such as Green-e (http://www.green-e.org/). Green-e is a project of the non-profit organization Center for Resource Solutions. Green-e researches and verifies the quality of RECs, ensuring that the benefits offered are real and lasting for the environment. Other tracking systems include WREGIS (http://www.wregis.org/).

Reliability and Operational Complexity The reliability of the technology would vary by type of renewable energy. However, nearly all PPAs and RECs are from either wind or solar PV, which are considered and reliable.

In general, renewables purchase projects should not impact the SCWD or SqCWD water operations. Minimal project administration would be required to monitor PPA and REC contracts. Creation of a local CCA, however, would require significant project administration. A higher level of management participation also would be required for equity partnership in a JPA.

Sustainability JPA and PPA contract terms could be negotiated for various lengths of time. Since the life of the desalination project is expected to be 30 years, this assessment assumes the life of contract also would be 30 years. The contract could be renewed to maintain a sustainable project.

RECs could be purchased annually for the 30-year duration of the project, and could continue to be purchased in the future.

Local Considerations Economy and Education Local renewables projects likely would benefit the local community by creating or help to sustain local jobs. Projects would temporarily support jobs to build the projects and could create longer term operation and maintenance and administrative jobs. Development of local renewable projects also could provide an educational opportunity for the community. SCWD and SqCWD could make it a priority to pursue PPAs and RECs that are local.

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Environment Potential environmental impacts would vary by type of renewable energy in the PPA and REC. However, nearly all PPAs and RECs are from either wind or solar PV.

Air: Solar PV and wind projects produce no air pollution or GHG emissions, and they prevent pollution and reduce GHG emissions by displacing conventional power generation sources. Water: Installed solar PV and wind power systems use no process water to operate, nor do they contribute to water pollution. PV panels will need periodic maintenance washing to remove dust and grime and should use a biodegradable non-toxic cleaning solution. Remotely-installed panels without water availability will require that water be hauled to the location. Wind turbines need no water for maintenance. Land: Land use and space availability for solar PV panel or wind installations can be major constraints. Larger solar PV projects require large, unobstructed, and unshaded areas, typically 100 square feet per kW. A 5 MW system would therefore require 500,000 square feet, or about 12 acres. Acceptable locations will need to be assessed on a case-by-case basis. Land impacts would be mitigated if the installation space is on land that is already disturbed or improved. For example, a solar array installed on a parking area that is no longer needed, integrated within new shade structures installed over existing parking lots, or on a brownfields site could mitigate the impacts. Large wind power installations require large, unobstructed areas with an adequate wind resource. Developers rely on the Wind Energy Resource Atlas of the United States and the U.S. Department of Energy’s Wind Powering America program resources to identify appropriate areas. Unlike solar PV, wind installations have been successfully combined with other land uses, such as agriculture, which adds helpful flexibility to siting options. Noise: Solar PV systems produce little noise pollution. Larger inverters can make a “humming” sound similar to transformers. The sound can be mitigated by locating inverters in an enclosure or within existing maintenance or electrical yards, and locating them away from residences. Wind turbines produce a low-frequency noise that can be bothersome to neighbors. The noise can be mitigated by locating them away from residences. Waste By-Products: Installed solar PV systems generate no waste by-products from their operation. Installed wind turbine systems generate very little waste by-products from their operation or manufacture. Lubricants are the main waste and need to be disposed of properly. Aesthetic/Visual: Visual impacts from solar PV installations coincide with space constraints, and solar PV systems impact a viewshed in proportion to the size of the project. Placement of the system is the main factor that affects visual impact. For example, roof-top systems integrating solar PVs into existing structures would minimize visual impacts, whereas utility-scale installations likely would occupy large open spaces that would be visible from a considerable distance. Visual impacts from wind turbine installations are significant and often controversial. This can be mitigated by locating installations far from residences and recreational areas. Wildlife, Habitat, and Endangered Species: California’s Desert Renewable Energy Conservation Plan (DRECP) is designed to offer guidance that will ensure endangered species protection while facilitating renewable energy project development. The DRECP is still under development but draft guidance has been issued, and the participation of all major regulatory

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jurisdictions ensures a streamlined approval process for projects. Any renewable energy purchase considered by SCWD and SqCWD should be verified to comply with DRECP guidelines. Wind turbine projects have additional wildlife concerns because of historical problems with bird and bat kills, although newer wind turbines are of less concern. Wind turbines should be located away from migratory flyways and important bird and bat habitats. California’s Guidelines for Reducing Impacts to Birds and Bats from Wind Energy Development report provides the necessary information to locate permittable wind installations that will minimize wildlife impacts.

Energy Production, Energy Savings and GHG Reductions A renewables project through an equity purchase or a PPA would produce renewable energy for use by SCWD and SqCWD. SCWD and SqCWD could choose to offset some or all of energy related to the SCWD and SqCWD desalination plant. The proposed desalination plant running at half capacity would use approximately 6,800 MWh per year, which could be produced by a 4.6 MW solar project or a 2.3 MW wind project, assuming respective rule-of-thumb capacity factors of 17 percent and 34 percent. This would result in an annual reduction of approximately 2,000 metric tons (MT) CO2e per year.

A REC program would purchase the carbon offsets from renewables energy projects but not the actual electricity commodity. SCWD and SqCWD could purchase medium and long-term RECs to build portfolios of reduction projects to meet GHG reduction goals, and/or could use REC purchases as an annual tool during the true-up process to meet GHG reduction goals. RECs may present less risk by providing an exact amount during the true-up process, whereas a solar or wind project may over or under perform in a given year.

Table 1 provides a summary of the energy production and GHG reduction from a renewables purchase program.

Table 1: Estimated Energy Production and GHG Reduction – Renewables Program Annual Energy Project Production Annual Metric Tons Lifetime Metric Tons (kWh/year) of CO2 reduced of CO2 reduced Join a JPA 6,800,000 1,978 59,347

Direct Access PPA 6,800,000 1,978 59,347 Join an Existing 6,800,000 1,978 59,347 CCA Create a Local 6,800,000 1,978 59,347 CCA Purchase RECs 0 1,978 59,347

Depending upon the extent of the project, this project has the ability to reduce 100% of the potential GHG reduction goals for SCWD and SqCWD.

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Cost For the potential projects discussed in this assessment (except RECs), the actual price is uncertain and unknown because prices vary based on projects and specific negotiations. The costs described below are examples of costs from similar types of projects and are meant to provide an order of magnitude cost estimate for a comparative tool in the GHG reduction project assessment process.

Capital/Startup Cost Creating a local CCA would be the most expensive project and would require legal, regulatory, and project administration costs. It is estimated that the capital/startup cost of creating a local CCA would be on the order of $3 million.

Obtaining a direct access PPA also would require some upfront costs, including regulatory and legal fees, setting up a Load Serving Entity, and potentially obtaining certification by the California Independent System Operator (ISO) to deliver the electricity. It is estimated that the capital/startup cost of obtaining a direct access PPA would be on the order of $500,000.

Joining an existing JPA or CCA is estimated to have a relatively smaller upfront cost on the order of $50,000.

There would be no capital cost associated with RECs, since they are purchased on an on-going annual basis. However, REC contracts can be designed to be prepaid, and bond proceeds possibly could be used to pay the up-front amount.

Annual Cost Electricity: The actual cost of electricity from a JPA, direct access PPA, or CCA varies significantly based on the project and negotiations. This section provides examples of costs and savings.

PPA pricing is currently estimated at 13 to 14 cents per kWh, and a JPA is expected to have similar costs. The cost of electricity for SCWD, as an example, from July 2010 to June 2011 varied from 9 to 32 cents per kWh (depending on the time of day) and averaged overall 15 cents per kWh. Purchasing 6,800 MWh/year of electricity from a PPA at 14 cents per kWh, versus purchasing from PG&E at an average of 15 cents per kWh, could save SCWD or SqCWD approximately $68,000 annually.

Unlike equity partnerships and PPAs, whose cost includes the generated power, RECs are “unbundled” from the electricity itself. In other words, a purchaser buys the GHG emissions reduction portion of the renewables project separately from the physical electricity commodity, so SCWD and SqCWD would not see any electricity cost savings.

Ongoing Program Administration: Creating a local CCA would require the most program administration for SCWD and SqCWD. It is expected that 2 FTEs would be needed to support a local CCA. A higher level of management participation also would be required for equity partnership in a JPA in decision-making and O&M aspects, which is estimated to require about 0.5 FTE.

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After program startup, it is expected that participating in a direct access PPA, existing CCA, and REC purchase program would require minimal effort, or approximately about 0.1 FTE to support the program.

RECs: REC prices are based on a somewhat volatile market. Green-e certified RECs have recently been sold in the range of $1 to $9 per REC, while, according to the U.S. Department of Energy Green Power Network, August 2010 REC prices ranged from $0.50 to $5.60 per MWh. Prices vary according to the type of renewables, location and whether they are vintage or new projects. New 100% wind RECs are estimated to cost between $0.50 to $2 per MWh, while new 100% solar RECs are estimated to cost between $2 and $5 per MWh. REC prices are anticipated to continue to increase, so if RECs are purchased at $2 per MWh, the annual program cost would be approximately $16,000 to offset the 8,000 MWh/year estimated use of the SCWD and SqCWD desalination plant.

PG&E Incentives PG&E and the State of California have numerous incentive programs that act as significant drivers promoting the development of certain renewable energy projects. Incentives are not available for REC purchases, but they are available for certain PPA purchases, such as solar PV. Table 2 provides a summary of the costs for a renewables purchase program. Annual costs are estimated to escalate similar to inflation.

Table 2: Estimated Renewables Purchase Program Costs Lifecycle Lifecycle CO2 Life Capital Avg Annual Project Energy Cost Reduction Cost (yr) Cost ($) Net Cost ($/Yr) ($/KWh) ($/MT) Join a JPA 30 $100,000 $200,600 $0.014 $48 Direct 30 $500,000 $86,409 $0.012 $42 Access PPA Join an 30 $100,000 $154,927 $0.009 $32 Existing CCA Create a 30 $3,000,000 $564,293 $0.050 $176 Local CCA Purchase 30 $0 $32,986 $0.003 $11 RECs 1Equity purchase costs (without a JPA) are discussed in Project Assessment No.10. 2For all costs (except RECs), price is assumed because PPA contract negotiations are uncertain. These costs provide an order of magnitude estimate.

Summary of Advantages and Disadvantages In general, purchasing renewable energy has several key advantages: • Solar PV and wind are mature technologies with low risk. • Depending upon the contract negotiated, a PPA could save SCWD and SqCWD money on their annual energy costs. • Environmental impacts are relatively low.

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For these types of renewable purchase programs, it is possible that the renewables projects would not be local. This could benefit SCWD and SqCWD by allowing them to tap into richer renewable resources elsewhere, but would not meet the preference/goal of evaluating local projects. Some of the major differences between types of renewable purchase programs are the responsibility/risk, and the cost. These are compared in Table 3 below.

Table 3: Renewables Purchase Program Comparison Matrix SCWD and SqCWD Project Project Cost Responsibility/Risk Administration Join a JPA High Low Low Direct Access PPA Medium Medium Medium Join an Existing CCA Medium Low Low Create a Local CCA Medium High High Purchase RECs Low Low Low

Additional type-specific advantages and disadvantages are discussed below.

Equity Purchase – Joining a JPA Disadvantages: • May not allow new, non-local participants.

PPA – Direct Purchase Disadvantages: • Purchase contract process can be complex.

Joining an Existing CCA Disadvantages: • May not allow new, non-local participants.

Creating a Local CCA Advantages: • Creates an ownership structure to fund local projects.

Disadvantages: • Significant project administration and start-up costs required. • SCWD and SqCWD would need to develop expertise in the energy utility business.

REC Purchase Advantages: • Useful during annual true-up process.

Disadvantages: • The general public does not understand how RECs are certified and often question whether RECs are real and permanent. SCWD and SqCWD may need to do public education about the rigor these RECs go through before pursuing a this option.

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References Bird, L., et al. May 2010. Voluntary Green Power Market Forecast through 2015. Technical Report NREL/TP-6A2-48158.

California Energy Commission, California Dept. of Fish and Game, U.S. Bureau of Land Management, and U.S. Fish and Wildlife Service. “Desert Renewable Energy Conservation Plan.” http://www.drecp.org/index.html

California Energy Commission. California Guidelines for Reducing Impacts to Birds and Bats from Wind Energy Development. October 2007. http://www.energy.ca.gov/2007publications/CEC-700-2007- 008/CEC-700-2007-008-CMF.PDF

U.S. Department of Energy. “National Retail REC Products.” http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=1. Updated August 2010.

Munves, Susan. Energy and Green Building Programs Administrator, City of Santa Monica. Personal communication, April 27, 2011.

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Executive Summary: Draft PA No. 10 – Local Solar Projects

Description A local solar program would entail installing solar photovoltaic (PV) panels on SCWD and SqCWD properties to provide an emissions-free renewable energy source that reduces the use of grid electricity and the associated indirect GHG emissions. This assessment included a preliminary review of SCWD and SqCWD properties to identify examples of potential solar PV project sites and understand the size requirements of potential projects. The example sites identified include the proposed scwd2 desalination facility (SCWD and SqCWD), the Bay Street Reservoir site (SCWD), numerous SCWD properties, SqCWD’s headquarters buildings, and SqCWD’s Fairway Drive property. Other sites could present additional project opportunities but would need to be evaluated further. Amount of GHG Reduction For the purpose of this assessment, the following projects were analyzed: • Solar PV panels could be installed on the roofs of several buildings at the proposed scwd2 desalination facility. The estimated space available would hold approximately 300kW, which could offset approximately 94 MT CO2e per year over 30 years. This project could be shared by SCWD and SqCWD based on their respective desalination plant operation.

• SCWD could offset approximately 388 MT CO2e per year over 30 years by installing 780 kW of solar PV panels on two tanks at the Bay Street Reservoir site and a total of 455 kW on several other sites (listed in Table 2). These projects could reduce approximately 55 to 90% of the potential GHG reduction goals for SCWD.

• SqCWD could offset approximately 268 MT CO2e per year over 30 years by installing 104 kW of solar PV panels on its administration building and 750 kW on its Fairway Drive property. These projects could reduce approximately 15 to 20% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability Local solar projects would continue to provide GHG reduction (and energy) for the life of the project and beyond. The project would be sustained by normal maintenance to repair any infrastructure deterioration. Project Cost Table ES-1 summarizes the estimated costs of the example projects discussed above.

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Table ES-1: Local Solar Program Summary Average Lifecycle Average Lifecycle Annual Capital GHG Space Example GHG Annual Energy Reduction Required Size Life Cost Projects Reduction Net Cost Cost Cost (1 kW/ ($ mil) 1 (MT ($/yr) ($/kWh) ($/MT 100 SF) CO2e/yr) CO2e) 2 scwd 300 desalination 30 94 $1.8 $70,000 $0.13/kWh $580 < 1 acre kW facility Bay Street 780 < 2 30 245 $4.7 $182,000 $0.13/kWh $580 (SCWD) kW acres Small 455 properties 30 143 $2.7 $106,000 $0.13/kWh $580 ~ 1 acre kW (SCWD) Admin Bldg 104 30 33 $0.6 $24,000 $0.13/kWh $580 < 1 acre (SqCWD) kW Fairway 750 < 2 30 235 $4.5 $175,000 $0.13/kWh $580 (SqCWD) kW acres 1Includes energy savings.

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Draft Project Assessment No. 10 – Local Solar Projects

Description This assessment estimates the energy generation and GHG reduction potential from the development of local solar photovoltaic (PV) projects. SCWD and SqCWD investment or participation in non-local solar and other renewable energy projects is discussed in Project Assessment No. 9. Rebate programs for residential and commercial solar projects are discussed in Project Assessment No. 3.

Background Solar energy refers to a number of technologies that derive their energy from the sun. This assessment focuses on PV solar electric systems, in which sunlight is converted directly into electricity using solar panels. A PV system includes PV panels, support structures to direct panels toward the sun, and components that covert the direct-current (DC) electricity produced by modules to alternate-current (AC) electricity.

A local solar program would entail installing solar photovoltaic (PV) panels on SCWD (or potentially the City of Santa Cruz) and SqCWD properties to provide an emissions-free renewable energy source that reduces the use of grid electricity and the associated indirect GHG emissions. Solar PV systems could be mounted on top of SCWD or SqCWD structures (such as buildings and water tanks, as shown in Figure 1), on other municipal-owned structures (such as parking garages), or mounted on the ground on property owned by SCWD or SqCWD. The solar PV systems could produce energy to directly provide power to SCWD or SqCWD facilities, or could connect to the overall electrical grid to indirectly provide power to SCWD or SqCWD facilities. When the solar PV system is not producing energy, electrical power would be obtained from the overall electrical grid through Pacific Gas and Electric (PG&E).

Figure 1: Existing Solar PV Installation on SCWD’s Graham Hill WTP

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With regard to coordinating with PG&E and connecting to the overall electrical grid, there are four categories of solar PV projects: 1) Behind the Meter; 2) Virtually Behind the Meter; 3) Virtual Meter Aggregation; and 4) In-front of the Meter. These categories are described below.

Behind the Meter A Behind the Meter project describes a solar PV facility that is sited at a facility where the electricity is consumed, all or in part by the account holder. The solar PV system connects to the facility behind the PG&E meter and replaces some or all of the power from PG&E. When the solar PV system is not producing energy, electrical power would be obtained from the overall electrical grid from PG&E.

Net energy metering (NEM) applies to Behind the Meter solar PV projects less than 1 MW in size. NEM is a method of metering the energy produced and consumed by a customer that has a renewable resource generation project, and it credits the customer with the value of the generated electricity. Effectively, the meter runs backwards, causing a credit on the customer’s bill. The benefit of NEM is the deferred cost of the electricity at the retail rate that SCWD/SqCWD would not have to purchase – an avoided cost. Net excess generation (NEG) beyond one month’s actual usage is carried over as a credit for a 12-month cycle, but is zeroed out after one year, so SCWD/SqCWD would not be paid for any remaining excess generation. A NEM Behind the Meter project should be sized so that the project does not create any NEG over the course of a year.

Virtually Behind the Meter A Virtually Behind the Meter project describes a solar facility that is sited at a location other than where some or most of the electricity is consumed. The electricity is transmitted over the overall electrical grid to the user. This approach is relatively new and was included in California Senate Bill (SB) SB1 and updated by California Assembly Bill (AB) AB510. Municipalities in California can install solar PV systems at facilities on different properties and can use the electricity generated to credit electricity bills at other properties (with some restrictions). Generally, if a facility produces more solar electricity than it uses, that excess energy can be used to credit the generation portion of another benefiting account. However, the same entity needs to be the account holder at both the point of generation and the benefiting account.

Therefore, electricity produced from a PV solar array at one SCWD or SqCWD facility location (within the SCWD or SqCWD geographic boundaries) can be used to offset the SCWD or SqCWD energy generation charges at other locations (per AB 2466, codified as Section 2830 of the California Public Utilities Code). This credits the generation portion of the utility bill, while the benefiting account still pays the transmission costs and other utility fees.

Virtual Meter Aggregation Another potential option is for SCWD and/or SqCWD, and other government entities (such as the City of Santa Cruz or school districts) to pool land resources and identify properties that have space and favorable characteristics for a PV system within SCWD/SqCWD geographical boundaries. This aggregation has some restrictions, but if there are municipal facilities with open roof tops and low electricity demands, a solar PV project could get credit via virtual net metering at other properties/accounts.

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In Front of the Meter An In-front of the Meter project describes a project in which the PV system is located at a site where there is no electricity use by the project owner, and the electricity produced by the solar facility is sold to a utility at wholesale rates through the Feed-in Tariff (FiT). These projects are generally larger (approximately 2 to 20 megawatts) to maximize efficiency. Since generated electricity is sold to PG&E, scwd2 would not get credit for KWh generated or for the associated GHG reductions. Since there are favorable Behind the Meter and Virtual Behind the Meter projects available, this assessment does not address potential In-front of the Meter projects.

History and Technical Maturity Solar PV cells were developed in the 1950s in the aerospace industry and have been used in utility-scale applications for nearly 30 years. Improved technology has allowed for the expansion of solar PV applications over time, and today there are many utility-scale and small- scale uses. Federal and state incentives have greatly increased the use of solar PVs as a renewable energy resource for electricity. In California, there are over 95,000 solar PV installations totaling almost 950 MW (http://gosolarcalifornia.org/). In the Santa Cruz area, over 2 MW of solar PV have been installed on local residences and businesses in the past 5 years under the California Solar Incentive (CSI) program (http://www.californiasolarstatistics.ca.gov/current_data_files/).

SCWD currently has two solar installations – a 74 kW system on the administrative office and 128 kW system on the operations building at the Graham Hill Water Treatment Plant (GHWTP).

Reliability and Operational Complexity Although research continues to improve the efficiency of solar arrays, this is considered a reliable and mature technology. The operational complexity of a solar PV system would be low. O&M activities would include periodically cleaning the PV panels and performing modest routine maintenance and testing.

Sustainability A local solar PV system would produce renewable energy for at least the life of the project, which is assumed to be 30 years. The project would be sustainable and could continue beyond the life of the project through routine maintenance and parts replacement as required.

Local Considerations

Economy Local solar PV systems could benefit the local economy through job creation, and training of PV system installers and service providers. The local PV systems could provide reliable energy at a low impact to the environment. Local projects would reduce local energy use and could provide opportunities to help to educate the community on renewable energy.

Table 1 provides a partial list of companies that have been involved in the sale and installation of solar PV equipment in the Santa Cruz area. The average size of the local projects is approximately 5 kW.

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Table 1: Local Solar Vendors Contractor Location Average System Size # of Projects Real Goods Energy Tech Inc. Santa Cruz 4.9 kW 258 Solar Technologies Santa Cruz 4.8 kW 229 REC Solar, Inc. San Francisco 4.2 kW 36 Solcon Solar Construction Santa Cruz 3.8 kW 25 Akeena Solar, Inc. Campbell 3.7 kW 25 SolarCity San Mateo 11.4 kW 24 Anderson Solar Controls Scotts Valley 4.6 kW 17 Santa Cruz Solar Santa Cruz 3.6 kW 11 Suns Up Solar (Putt Construction) Santa Cruz 4.6 kW 7 Full Circle Energy Cooperative, Inc. Fresno 5.2 kW 7 Petersen-Dean, Inc. Los Gatos 5.1 kW 7 Borrego Solar Systems, Inc. Oakland 4.5 kW 6 Renewable Power Solutions Inc. San Jose 5.8 kW 5 Poco Solar Energy, Inc. Santa Clara 4.6 kW 5 Gregory Heitzler Design Santa Cruz 6.0 kW 5 Source: California Public Utility Commission and California Energy Commission “Go Solar California” website: http://www.californiasolarstatistics.ca.gov/search/contractor/

Environment Air: Solar PV systems do not produce air pollution or GHG emissions, and they prevent pollution by displacing conventional power generation sources.

Land: Larger solar PV projects require large, unobstructed, and unshaded areas, typically 100 square feet per kW. A 100 kW system would require approximately 10,000 square feet, or approximately one quarter acre of land. Land impacts would be mitigated if the installation space is on land that is already disturbed or improved (ie – on rooftops or parking lot shade structures).

Water: Solar PV systems use only a modest amount of water during periodic cleaning.

Noise: Solar PV systems produce little noise pollution. Larger inverters can make a “humming” sound similar to transformers. The sound can be mitigated by locating inverters in an enclosure or within existing maintenance or electrical yards, and locating them away from residences or offices.

Aesthetic/Visual: Visual impacts from solar PV installations coincide with space constraints, and solar PV systems impact a viewshed in proportion to the size of the project. Placement of the system is the main factor that affects visual impact. For example, roof-top systems integrating solar PVs into existing structures would minimize visual impacts, whereas utility-scale installations would likely occupy large open spaces that would be visible from a considerable distance.

Waste By-products: Installed solar PV systems generate no waste by-products from their operation.

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Energy Production and GHG Reductions The PVWatts calculator, developed by the National Renewable Energy Laboratory, estimates electricity production in terms of kilowatt-hour (kWh) per year per kilowatt (kW) installed at a selected location and can be found at: http://www.nrel.gov/rredc/pvwatts/. Using meteorological weather data for a selected location, PVWatts determines the solar radiation, which is then converted into energy. According to the PVWatts calculator, a 1 kW PV installation in the Santa Cruz area would generate approximately 1,200 kWh per year for a fixed-tilt system on a roof top and facing due south. The actual output of existing SCWD projects was approximately 110,000 kWh at the administration offices and 146,000 kWh at GHWTP, which are close to the estimates by PVWatts.

Potential Solar PV Projects This assessment included a preliminary review of SCWD and SqCWD properties to identify examples of potential solar PV project sites and understand the size requirements of potential projects. The example sites identified include the proposed scwd2 desalination facility (SCWD and SqCWD), the Bay Street Reservoir site (SCWD), numerous SCWD properties, SqCWD’s headquarters buildings, and SqCWD’s Fairway Drive property. Other sites could present additional project opportunities but would need to be evaluated further. scwd2 SCWD and SqCWD could choose to offset some or all of energy related to the scwd2 desalination plant. The proposed desalination plant running at half capacity would use approximately 6,800 MWh per year. At 1,200 kWh per kW installed, approximately 5,700 kW of solar PV would be needed to offset this energy usage. This translates into approximately 13 acres.

Based on the preliminary layout of the proposed scwd2 desalination facility, there appears to be approximately 30,000 square feet of roof space on the MF/UF, SWRO, and Control buildings. At 12 kWh per year per SF, the PV panels could provide approximately 323,000 kWh per year or about 5%.

SCWD Bay Street Reservoir (Virtual Behind the Meter): Based on information from SCWD, the Bay Street tank site (at 200 Cardiff Place) will have two, 223-foot diameter concrete tanks that will provide a total roof area of approximately 78,115 square feet. There would not be a significant space available for ground-mounted panels. At 12 kWh per year per SF, the Bay Street tank roofs could provide approximately 841,000 kWh per year.

Various Identified SCWD Properties (Behind the Meter or Virtual Behind the Meter): In 2006- 2007, an assessment of the solar potential for SCWD-owned facilities was conducted. Table 2 lists the sites identified with the best potential for installing solar PV systems. In addition to those shown in Table 2, SCWD identified and ruled out other sites based on size, access, shading, and other issues. The estimated combined square footage available at the potential future sites totals approximately 45,500 SF, or over 1 acre. At 12 kWh per year per SF, these sites could provide approximately 546,000 kWh per year combined.

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Table 2: Assessment of Solar Potential for SCWD Properties Estimated Area Actual/Estimated Energy Location Available (SF) Generation (kWh/yr) Existing Locations Graham Hill WTP 12,300 146,000 Administration Bldg 7,400 110,000 Total Existing 19,700 256,000 Potential Future Locations Graham Hill WTP – Lab 2,000 24,500 Parking Lot 1 – Soquel/Front 8,400 101,000 Parking Lot 2 – Locust Garage 8,400 101,000 Golf Lodge Delaveaga 7,200 86,400 Municipal Wharf 6,200 74,400 Recycling Center at Landfill 5,200 62,000 Corp yard 4,800 57,000 Sanitation Shop Corp Yard 3,300 39,300 Total Potential 45,500 546,000 Source: Santa Cruz Water Department Memorandum, February 2007.

In addition to the sites identified in the 2006-2007 assessment and shown in Table 2, the SCWD has several other smaller properties (including reservoirs, wells, and pump stations) with small electricity needs that could be assessed in the future.

Additional Potential Areas of Exploration (Virtual Behind the Meter): SCWD properties were evaluated with the goal of identifying several properties that are large enough to develop a substantial solar array ranging in size from 500 kW (1 acre) to 5,700 kW (13 acres). The sites also need to be a reasonable distance from a transmission line and have little shading.

SCWD owns over 100 properties, ranging in size from less than 100 SF to over 1,000 acres. The largest properties lie outside the agency’s geographic boundaries in the upper watershed areas of Newell, Laguna, and Zayante creeks, but are located within Santa Cruz County’s Timber Preserve Zones. A solar array potentially could be developed on these properties, but several elements must be considered: • Proximity to transmission lines. • If the properties are outside the service territory, the energy generated cannot be wheeled to agencies’ electricity meters. • The properties may need to be rezoned. • A timber harvest plan may be required. (The public may respond unfavorably to harvesting trees in order to build a solar PV project.)

SqCWD Table 3 lists some of the sites identified by SqCWD staff as potential locations for solar PV projects.

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Table 3: Operations Department Initial Assessment Potential SqCWD Locations for Solar Notes Main Headquarters Administration and Maintenance Buildings Garnet Well and Opal Treatment Plant

Country Club Well Large parcel Altivo Well

Mar Vista Tanks and Boosters (Tank 2) Substantial electrical usage Madeline Well

Seascape Tank and Boosters

Bonita Well Large parcel Ledyard Well

Fairway Tank

San Andreas Well

Cornwell Tank and Boosters

Aptos Booster Station

Aqua View Tanks and Boosters Substantial electrical usage Aptos Creek Well Substantial electrical usage Tannery Well and Treatment Plant

Seascape Well

Austrian Tank and Boosters

Main Street Well and Treatment Plant limited space T. Hopkins Well and Treatment Plant limited space Papermill Vacant lot not planned for future development Suncatcher Court Vacant lot not planned for future development Rincon Vacant lot not planned for future development Hillcrest Vacant lot not planned for future development

SqCWD Headquarters (Virtual Behind the Meter): SqCWD is interested in installing solar PV panels on the roofs of the administration and maintenance buildings at its main headquarters. The areas of the roofs are approximately 5,800 SF and 4,600 SF, respectively. At 12 kWh per year per SF, this could provide approximately 112,000 kWh per year.

Fairway Drive (Virtual Behind the Meter): Similar to SCWD, SqCWD owns many properties within their upper watershed areas with similar site considerations. SqCWD has a property on Fairway Drive (APN 040-431-06) that is approximately 2.8 acres in size (Figure 2). This property houses a storage tank, but the remainder of the property appears to be mostly open space with good sun exposure. A ground-mounted solar array of 500 kW to 1 MW potentially could be constructed at this site. Assuming 1,200 kWh per year produced per kW installed, a 750 kW project at this site could generate approximately 809,000 kWh per year.

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Figure 2: Potential SqCWD Site for Ground Mounted Solar Array

Potential Additional Areas of Exploration (Behind the Meter): This assessment included a cursory review of SqCWD’s land holdings. Fairway had the ideal characteristics for siting a solar facility, but additional properties may meet these criteria. As a next step, SqCWD would undertake a more detailed review and rank each of their properties by its ability to successfully house a solar array.

Since solar PV systems do not produce GHG emissions, the projects would offset the indirect GHG emissions associated with the purchase of electricity from PG&E. Table 4 summarizes the potential energy production and GHG reductions for analyzed solar PV projects.

Table 4: Estimated Energy Production and GHG Reduction for Solar PV Projects Average Annual Average Annual GHG Lifetime GHG Project Size Energy Production Reduction (MT Reduction 1 1,2 (kWh/yr) CO2e/yr) (MT CO2e/yr) 2 scwd 300 desalination 323,000 94 2,800 kW facility Bay Street 780 841,000 245 7,300 (SCWD) kW Small properties 455 491,000 143 4,300 (SCWD) kW Admin Bldg 104 112,000 33 980 (SqCWD) kW Fairway 750 809,000 235 7,100 (SqCWD) kW 1Includes decline of energy production due to degradation of equipment over 30 years. 2 Based on 2009 PG&E emission factor of 641.35 lbs CO2e/ MWh.

This project could reduce approximately 55 to 90% of the potential GHG reduction goals for SCWD, and 15 to 20% of the potential GHG reduction goals for SqCWD.

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Cost According to data available on the Go Solar California website, 2,400 PV projects (including residential, commercial, and governmental) were completed under the CSI program in the first 6 months of 2011. The average installation cost of these projects was $5.40 per watt.

Capital Cost: Average PV module prices are currently approximately $3.00 per watt, and installation costs can range from $2.00 to $4.50 per watt. The variation in this price range is dependent upon the size of the system (economies of scale), physical location, new versus existing structure, and siting challenges (i.e. equipment, penetrations, slope). This assessment assumes a conservative $6.00 per watt installed cost for the Santa Cruz area.

The cost estimate for a potential project includes photovoltaic panels, fixed-tilt solar arrays, inverters, wiring, engineering, installation, utility grid interconnect, warranty, 5 years of maintenance, and 5 years of performance monitoring and reporting service (an eligibility requirement by some of the financial incentive programs).

O&M Cost: Maintenance requirements depend upon the system size. Regular maintenance is minimal over the life of the system and includes periodically cleaning the panels, as well as testing and cycling the inverters. The lifetime of most PV arrays is between 20 and 30 years, and failures that require replacements are rare. PV arrays degrade at a rate of approximately less than one percent of total system capacity per year, since energetic particles from the sun produce physical damage to silicon-based solar cells. Manufacturer warranties and PPA’s usually take this degradation into account. However, the inverter needs to be replaced every 10 years for approximately $0.70 per watt installed, and this cost is usually included in the vendor maintenance agreement. (http://www.solarbuzz.com/Inverterprices.htm)

Incentives and Rate Structures: A part of the Go Solar California campaign, the California Solar Initiative (CSI) offers rebates to customers in California's investor-owned utility territories. CSI rebates vary according to system size, customer class, and performance and installation factors. The subsidies decline in "steps" based on the volume of solar megawatts confirmed within each utility service territory. In 2011, the CSI rebate applicable to a 100 kW array is the Performance Based Incentive (PBI), which pays out an incentive based on actual kWh production over a period of five years. Currently, the CSI program is oversubscribed, and new CSI projects are not guaranteed an incentive at this time (http://www.csi-trigger.com/).

Lifecycle Cost: The average energy cost for the resource, assuming a project life of 30 years, with a 5 percent bond, and NEM rate structure (retail rate of $0.15/KWh escalating at 2%), would be approximately $0.14/kWh. This is similar to the levelized cost of utility power from PG&E of $0.14/kWh.

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Table 5: Estimated Solar PV Project Costs Capital Average Lifecycle Lifecycle GHG Life Project Cost Annual Net Energy Cost Reduction Cost (yrs) 1 ($ mil) Cost ($/yr) ($/kWh) ($/MT CO2e) 2 desalination scwd 30 $1.8 $70,000 $0.13/kWh $580 facility Bay Street 30 $4.7 $182,000 $0.13/kWh $580 (SCWD) Small properties 30 $2.7 $106,000 $0.13/kWh $580 (SCWD) Admin (SqCWD) 30 $0.6 $24,000 $0.13/kWh $580

Fairway (SqCWD) 30 $4.5 $175,000 $0.13/kWh $580 1 Includes energy savings, but not CSI incentives. The CSI incentive program is currently oversubscribed and all un-confirmed projects are not guaranteed an incentive.

Summary of Advantages and Disadvantages Advantages • Creates local jobs. • Mature technology with low risk. • Environmental considerations are low. • Low O&M requirements and costs. • No fuel costs.

Disadvantages • Relatively large space or land requirements. • Limited sites available for SCWD/SqCWD. • Financial incentives (CSI) may not be available for new solar PV projects. • High purchase/installation costs per kW relative to other forms of electricity. • Non-local solar projects could take advantage of better solar insolation resources. For example, a 1 kW PV installation near Barstow, California is estimated to produce almost 1,500 kWh per year versus 1,200 kWh per year in the Santa Cruz area.

References California Public Utility Commission and California Energy Commission. “Go Solar California” website: http://www.californiasolarstatistics.ca.gov/search/contractor/ MC Solar Engineering. “Report on Solar Resources for the Santa Cruz Water Department.” December 2006. National Renewable Energy Laboratory. PVWatts Calculator. http://www.nrel.gov/rredc/pvwatts/ Santa Cruz Water Department Memorandum. 21 February 2007. “Solar Projects at City Sites for Desal Offset.”

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Solarbuzz. “Inverter Prices.” http://www.solarbuzz.com/facts-and-figures/retail-price-environment/inverter- prices Solar Energy Industries Association (SEIA). http://www.seia.org/ State of Rhode Island Office of Energy Resources: www.energy.ri.gov/programs/renewable.php, January 2010. U.S. Department of Energy (DOE). Energy Efficiency and Renewable Energy. Accessed online 1/04/10 at https://www1.eere.energy.gov/solar/photovoltaics.html. U.S. Department of Energy. “National Retail REC Products.” http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=1. Updated August 2010.

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Executive Summary: Draft PA No. 11 – Fuel Cells

Description This assessment estimates the energy generation and potential GHG reduction potential from the development of local fuel cell projects. Fuel cell systems could be installed on property owned by SCWD or SqCWD. The fuel cell systems could produce energy to directly provide power to the desalination facility, to other SCWD and SqCWD facilities, or could connect to the overall electrical grid to indirectly provide power to SCWD or SqCWD facilities.

Amount of GHG Reduction Fuel cells can use natural gas or biogas to produce energy, water, heat and GHGs including CO2, and a small amount of other gases. The GHG emissions from a SCWD or SqCWD fuel cell system project would be compared to the PG&E emission factor to determine the potential net GHG reduction from a fuel cell energy source. The GHG emission factors of natural gas- supplied fuel cells, while less than the US average grid electricity emission factor, are in most cases higher than the PG&E emission factor. This is because PG&E grid electricity has a higher percentage of renewable and non-fossil fuel energy than many other utilities. Therefore, in comparison to grid electricity from PG&E, the fuel cell systems with natural gas would not provide a reduction in GHG emissions. Currently, local biogas sources are being used for energy production, therefore local biogas fuel cell projects do not appear to be feasible for GHG reduction.

Project Life and Sustainability A fuel cell project would provide energy for the life of the project. The project would be sustained by normal routine maintenance and periodic replacements of the fuel cell stacks as necessary. However, this project would not provide GHG reductions (as noted above).

Project Cost Cost information for a lease for a SOFC fuel cell (Bloom) and a MCFC fuel cell (FCE) are provided in ES-1. There is no capital cost since the systems are leased. Since the fuel cells’ GHG emission factors are higher than PG&E’s emission factors, there are no GHG reductions and the lifecycle GHG reduction cost is not applicable. Since the energy and fuel costs for the Bloom fuel cell are lower than the PG&E energy costs, there is an average annual net savings and a negative lifecycle energy cost. The energy cost from the FCE fuel cell is similar to the PG&E energy costs. However, the additional cost for labor and the different between the estimated inflation and utility/fuel cost escalator rates cause the FCE fuel cell to be slightly more expensive than the energy savings each year, resulting in an average annual net cost.

Table ES-1: Estimated Fuel Cell Costs Average Lifecycle Lifecycle GHG Life Capital Fuel Cell Type Annual Net Energy Cost Reduction Cost (yr) Cost ($) Cost ($/Yr) ($/KWh) ($/MT) $0 SOFC (Bloom) 20 -$8,300 -$0.0024 N/A Lease MCFC (FCE) $0 20 $157,000 $0.0131 N/A without heat recovery Lease

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Draft Project Assessment No. 11 – Fuel Cells

Description This assessment estimates the energy generation and potential GHG reduction potential from the development of local fuel cell projects. Background A local fuel cell project would entail installing fuel cells on SCWD (or potentially the City of Santa Cruz) and SqCWD properties to provide a local energy source that reduces the use of grid electricity and potentially the associated indirect GHG emissions. Fuel cell systems could be installed on the ground on property owned by SCWD or SqCWD. The fuel cell systems could produce energy to directly provide power to SCWD or SqCWD facilities, or could connect to the overall electrical grid to indirectly provide power to SCWD or SqCWD facilities. If or when the fuel cell system is not producing energy, electrical power could be obtained from the overall electrical grid through Pacific Gas and Electric (PG&E).

With regard to coordinating with PG&E and connecting to the overall electrical grid, there are four options for fuel cell projects, similar to solar photovoltaic projects: 1) Behind the Meter; 2) Virtually Behind the Meter; 3) Virtual Meter Aggregation; and 4) In-front of the Meter. These categories are described in detail in the Local Solar Project Assessment.

Fuel Cell Technology

Generally, fuel cells use natural gas (methane) as a fuel source and produce energy, water, heat and GHGs including CO2, and a small amount of other gases. Fuel cells work like batteries, making electrical energy from chemical energy without combustion. Compared to a natural gas combustion generator, a fuel cell can produce the same amount of energy using less natural gas fuel and producing fewer emissions. A fuel cell system could produce fewer GHGs than electricity from the grid depending on the emission factor of the utility providing electricity over the grid. This is discussed in more detail below.

In a fuel cell, a catalyst known as the “fuel reformer” is generally required to extract hydrogen from the methane gas. Fuel reformers break the methane molecule and separate the hydrogen for use by the fuel cell. Natural gas is the cleanest and preferred fuel if pure hydrogen gas is not available. However, other hydrogen rich gases such as propane, or methane from biological processes, could also be used as a source for fuel cells.

Like a battery, a fuel cell has one positive electrode (the cathode) and one negative electrode (the anode) with an electrolyte between them. The hydrogen is fed to the anode and air (oxygen) is fed to the cathode. A catalyst on the surface of the anode splits the hydrogen into protons (hydrogen ions) and electrons. As the hydrogen ions move from the anode to the cathode through the electrolyte, electricity is created. Electrons cannot flow through the electrolyte and, as a result, flow through an external circuit as an electric current. At the cathode, a catalyst on the surface recombines the hydrogen ions and electrons with oxygen to produce water and heat. A diagram of a typical fuel cell is shown in Figure 1.

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Figure 1: Diagram of Fuel Cell Technology

Source: U.S. Dept. of Energy: http://www1.eere.energy.gov/hydrogenandfuelcells/fuelcells/fc_types.html

The fuel cell process is different than the traditional process of combustion in which fuel first is burned and the subsequent heat is used to produce power. Avoiding this two-step process makes the fuel cells more efficient than combustion technologies.

A single fuel cell generates a small amount of electricity, so in practice many fuel cells are typically assembled into a stack to generate the desired power output. Fuel cells produce direct current (DC) electricity and use a power inverter to convert from DC to alternating current (AC) for consumptive uses.

Types of Fuel Cells

Fuel cells differ based on type of electrolytes and operating temperatures. The four primary fuel cell technologies are described below.

Phosphoric Acid Fuel Cells (PAFC): PAFCs use liquid phosphoric acid as the electrolyte. The PAFC is the oldest technology used today. Generally, PAFCs have higher capital costs and lower efficiencies than other types of fuel cells such as MCFC and SOFC. PAFCs are generally large and heavy and require warm-up time, making them most appropriate for stationary applications. Efficiencies of approximately 35 to 45 percent are achievable with PAFCs.

Molten Carbon Fuel Cells (MCFC): MCFCs use an electrolyte composed of a molten carbonate salt mixture. These fuel cells operate at high temperatures and have efficiencies as high as 45 to 60 percent. However, the high operating temperatures accelerate component breakdown and corrosion, decreasing the life of the cell and increasing operating cost.

Solid Oxide Fuel Cells (SOFC): SOFCs use a hard ceramic compound as the electrolyte. SOFCs also operate at high temperatures, with efficiencies approximately 45 to 60 percent. This

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technology is still at a relatively early stage of development compared with other fuel cell technologies, and is not as commercially available.

Proton Exchange Membrane Fuel Cells (PEMFC): Development of PEMFCs has generally been driven by the automotive sector because of their low temperature operation, which allows them to start quickly. Their light weight also makes them advantageous for automobile use. PEMFCs use a thin solid membrane for an electrolyte. They are generally good candidates for smaller applications and have efficiencies of approximately 35 to 50 percent.

Vendors

More than 60 companies worldwide are involved in the development of fuel cells. Generally, most companies focus on one of the primary types of fuel cell technologies. Example companies for each type of fuel cell include:

Table 1: Types of Fuel Cells and Associated Vendors

Type of Fuel Cell Vendors • UTC Power (UTC) PAFC • Fuji Electric Company • Mitsubishi Electric Corporation • Fuel Cell Energy (FCE) MCFC • Hitachi • Siemens Westinghouse Power Corporation • SOFCo SOFC • ZTEK Corporation • Bloom Energy (Bloom) • UTC Power • ReliOn PEMFC • Ballard Generation Systems • Nuvera Fuel Cells

This assessment evaluates the MCFC fuel cells provided by Fuel Cell Energy (manufactured in Connecticut), the PAFC fuel cells provided by UTC Power (manufactured in Connecticut), and the SOFCs provided by Bloom Energy (manufactured in California). These types of fuel cells have operating experience at commercial and municipal facilities.

Capacity of Fuel Cells

Fuel cells are generally modular units and the amount of energy produced depends on the type of fuel cell and the configuration. SOFC fuel cells by Bloom can be purchased starting with a 200 kW unit, then additional increments of 100 kW. MCFC fuel cells by Fuel Cell Energy are available in a 1,400 kW unit. Fuel Cell Energy also has a 300 kW unit available, but these are only available as a special order and are in limited production. This limitation makes these units much more expensive per kW than the 1400 kW unit, and therefore the 300 kW units are not included in this evaluation. UTC Power has a 400 kW unit available which can be deployed in multiple units to provide additional energy.

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Fuel Cell GHG Emissions with a Natural Gas Source

Fuel cells produce energy, water, heat and GHGs including CO2, and a small amount of other gases. The GHG emissions from a SCWD or SqCWD fuel cell system project would be compared to the PG&E emission factor to determine the potential GHG reduction from a fuel cell energy source. In implementing the agency-specific Energy Minimization and GHG Reduction Plans for the Project, the actual PG&E emission factor for each year would be used to determine the actual GHG reduction.

Indirect GHG emissions associated with electricity from the grid in Santa Cruz were calculated using PG&E California Climate Action Registry reported and verified electricity CO2e emission factors. The annual report can be found at: https://www.climateregistry.org/CARROT/Public/Reports.aspx. As shown in Figure 2, the emission factor fluctuates annually and is often greater in dry and drought years due to less available hydropower. The PG&E emission factor is less than the California average and significantly less the US average emission factors. This is due to PG&E’s relatively larger percentage of renewable and non-GHG energy sources. The 2008 PG&E emission factor is the most recent as of this analysis.

Figure 2 PG&E CO2e Emission Factor, 2003 – 2008

Source: PG&E, 2009 Corporate Responsibility and Sustainability Report.

Table 2 below provides the manufacturer provided emissions factor for the different types of fuel cells assuming natural gas is used a fuel source. The US and CA average, and the 2003 to 2008 range of PG&E grid electricity emission factors are also tabulated for comparison.

Note that fuel cell GHG emission factors, while less than the US average grid electricity, are in most cases higher than the PG&E emission factor. Therefore, in comparison to grid electricity from PG&E, the fuel cell systems with natural gas would not provide a reduction in GHG emissions. The MCFC fuel cell from FCE could potentially incorporate the recovery of waste heat from the fuel cell process to help offset other energy requirements. FCE provided a

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potential high and low range of emission factors for their MCFC fuel cell with a heat recovery system (shown in Table 2). With waste heat recovery, the FCE fuel cell may or may not reduce GHG emissions compared to PG&E energy depending on the actual emission factors. The SOFC fuel cell from Bloom and PAFC fuel cell from UTC do not create useable amounts of waste heat.

Table 2: Energy Source and Fuel Cell System GHG Emission Factors GHG Emissions Factor Energy Source / Fuel Cell Type (lbs CO2/MWh) US Average Grid Electricity 1,329 CA Average Grid Electricity 724 PG&E Grid Electricity 456 to 641 SOFC (Bloom) 773 MCFC w/o heat recovery (FCE) 980 MCFC w/ heat recovery (FCE) 680 (high emissions) MCFC w/ heat recovery (FCE) 520 (low emissions) PAFC (UTC) 1,100

Fuel Cell GHG Emissions with a Biogas Source

If digester gas is used as the source of methane, it must first be cleaned to remove impurities such as siloxanes and hydrogen sulfide. Impurities can poison the fuel cell catalyst, which limits its ability to ionize hydrogen and reduces the fuel cell efficiency, or can result in catastrophic failure. A fuel cell operating on biogas produces emissions including CO2, and a small amount of other gases. However, these emissions are not accounted for as “GHG emissions” because they come from a non-fossil fuel source. The fuel cell process simply converts the more potent GHG (methane) to less potent GHG (carbon dioxide) while extracting energy in the process.

The same reasoning is applied to combustion generation of biogas. For example, the emissions of CO2, and a small amount of other gases from the digester biogas combustion generator at the Santa Cruz wastewater treatment plant (WWTP) are not accounted for as “GHG emissions” because they come from a non-fossil fuel source, and would be released with or without the digester biogas combustion generator system. Therefore, the energy produced from biogas methane fuel cells and combustion generators is considered to be “GHG free energy.”

History and Technical Maturity Primitive fuel cells were invented over 100 years ago. The space program drove their commercial development in the1960s. In 1997, a PAFC was the first modern fuel cell operated on digester gas at a wastewater treatment plant in New York. Since that time an increasing number of fuel cells have been installed using digester gas, most using either PAFC or MCFC technologies. Today, there are about 50 fuel cell installations in California totaling over 25 MW, about 10 MW of which is at wastewater treatment plants. The largest fuel cell plant in the world is a 5.6 MW FCE plant in Korea. About 90% of FCEs U.S. installations in the past several years are fueled by digester gas.

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The Eastern Municipal Water District installed three MCFC 250 kW fuel cells by Fuel Cell Energy that operate on digester gas at their Moreno Valley Regional Water Reclamation Facility. The fuel cells provide the District with enough energy to operate 40 percent of the plant at peak hours. They have indicated that the capacity factor of the fuel cells has been in the mid- ninety percent over the past year and half.

SOFC (Bloom Energy) cells have been installed in numerous locations, with some being in operation for more than 2 years. Heat output is negligible. Kennedy/Jenks had conversations with two of Bloom Energy’s current customers who have been using the Bloom cells for more than 2 years, and they indicated that there have been no interruptions in power output aside from scheduled maintenance. They stated that even though the Bloom cells are a relatively new immature technology, the systems have run well.

Reliability and Operational Complexity While fuel cell technology is relatively new and has had a poor performance record in the past, the technology seems to have recently matured sufficiently to provide reliable power to businesses and municipal agencies. Vendors have overcome poor performance by only leasing and not selling fuel cells. Vendors also include an accompanying Operation and Maintenance (O&M) contract as part of the lease. This enables the vendors to have complete control over the fuel cell and sell the power output to the host agency/business through a Power Purchase Agreement (PPA).

The service agreement provided by FCE provides all O&M requirements for these systems. With this arrangement very little staff time would be required. This would also be true under the Energy Service Agreement (ESA) with UTC Power, or the PPA with Bloom Energy.

Sustainability A fuel cell project would continue to provide energy for the life of the project. The project would be sustained by normal routine maintenance and periodic replacements of the fuel cell stacks as necessary. Based on the fuel cell and PG&E emission factors, the projects do not appear likely to reduce GHGs unless they are fueled by biogas.

Local Considerations Economy The SOFC (Bloom) fuel cells are manufactured in California; the others are manufactured predominantly on the east coast (especially Connecticut). Purchasing an SOFC cell would bolster the California economy by supporting local (Silicon Valley) manufacturing. Vendors would use local contractors for installation, which would further benefit the California economy. If a fuel cell system were installed at a SCWD or SqCWD facility, the City or District could create a potentially very popular local educational experience. Education materials as bill stuffers, information on websites, sign boards or an electronic kiosk at the facility could be used. Tours of the facility to the public could also be made available.

Environmental Impacts

Air: Fuel cells emissions include water, CO2, and a small amount of other gases. With respect to impacts on air quality, fuel cells produce fewer emissions than other fossil fuel generation options. Because air emissions from fuel cells are very low, they are currently exempt from many Clean Air Act permitting requirements.

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Land: The standard configuration for the MCFC 1.4 MW fuel cell (FCE) requires an area of approximately 2,500 square feet, plus a small amount of additional space for maintenance access. A 1.4 MW SOFC (Bloom) system requires an area of approximately 5,700 square feet, and 1.4 MWs of PAFC fuel cells (UTC PureCell 400s) would require an area of approximately 4,200 square feet (including maintenance access). Both Bloom and UTC Power sell smaller increments of fuel cells (100 KW for Bloom and 400 KW for UTC Power) and they would take up proportionately less space.

Water: The 1.4 MW MCFC fuel cell (FCE) requires approximately 5,800 gallons per day during full power operation. A significant portion of the water evaporates, and the remaining water is discharged at approximately 2,900 gallons per day. Typically the water can be discharged directly to the sanitary sewer. The SOFC (Bloom) fuel cells require minimal water use only at start-up (approximately 120 gallons).

Noise: Fuel cells are relatively quiet. At the distance of three feet, noise emissions from a MCFC fuel cell (FCE) are expected to be just above the level of sound of a normal human conversation. Noise from the SOFC fuel cell (Bloom) is expected to be less than 70dBA at 6 feet. Noise from the PAFC (UTC Power) fuel cell is expected to be less than 65 dBA at 33 feet (without heat recovery), and less than 60 dBA at 33 feet (with heat recovery).

Aesthetic/Visual: Visual impacts from installation of a fuel cell depend on the location of the project, but in general they would have a low aesthetic/visual impact. If the fuel cell were located within the existing footprint of a water treatment plant, or the scwd2 desalination plant; there would be no tall emissions stacks or visible emissions and the aesthetic/visual impacts would be very low.

Waste By-Products: The waste by-products produced by fuel cells are discharge water (depending on the fuel cell chosen) and the fuel cells stacks. The fuel cell stacks need to be replaced every 3 to 5 years and are 100 percent recyclable.

Energy Production and GHG Reductions

Potential Local Natural Gas Fuel Cell Projects SCWD and SqCWD could choose to offset some or all of energy related to the scwd2 desalination plant using natural gas fuel cells at the desalination facility or at other SCWD or SqCWD facilities. The proposed desalination plant, running at half capacity, would require a fuel cell system with an instantaneous generation capacity of approximately 0.8 MW and would use approximately 6,800 MWh per year. At full capacity, the proposed desalination plant would require a fuel cell system with an instantaneous generation capacity of approximately 1.6 MW and would use approximately 13,600 MWh per year.

As a first level of analysis, this project assessment evaluated a potential fuel cell system that would be located at the desalination facility to offset up to the full capacity of the facility. When the desalination plant is running at a lower capacity, the energy from the fuel cell system could be used to offset other SCWD or SqCWD energy demand through a virtual net metering approach.

Table 3 below summarizes the energy that could be produced and the associated GHG emissions difference between the natural gas fuel cells and PG&E grid electricity. While all the natural gas fuel cell systems could produce sufficient energy to meet the majority of the scwd2 Desalination Program, GHG Reduction Project Assessments Page 11-8 K/J Project No. 0868005*03, version 9/21/2011 115 desalination facility power requirements, these systems would create more GHG emissions than PG&E grid electricity. Table 3 shows an increase in GHG emissions as a negative GHG reduction.

Like the proposed larger systems, smaller fuel cell systems running with natural gas at other SCWD or SqCWD facilities would also create GHG emissions as compared to PG&E grid electricity.

Table 3: Estimated Fuel Cell Energy Production and GHG Emissions Average Annual Annual GHG Emissions Lifetime Metric Fuel Cell Total Metric Tons of CO2 KWh Factor Tons of CO Type MW 2 Produced (Lbs CO /MWh) Net Net Reduced 2 Reduction Increase PG&E Grid -- -- 641 ------Electricity 1.4 SOFC (Bloom) 11,650,800 773 696 N/A MW MCFC w/o heat 1.4 recovery 11,650,800 980 1,790 N/A MW (FCE) MCFC w/ heat recovery 1.4 (FCE) 11,650,800 680 204 N/A MW (high emissions) MCFC w/ heat recovery 1.4 11,650,800 520 640 12,800 (FCE) MW (low emissions) PAFC 1.4 11,650,800 1,100 2,415 N/A (UTC) MW

Potential Local Biogas Fuel Cell Projects Local Santa Cruz area sources of biogas sources include landfill methane from the Santa Cruz Municipal Landfill and methane from the digesters at the Santa Cruz WWTP. The Santa Cruz Municipal Landfill currently uses combustion generators to produce energy from landfill biogas and has a long-term contract to supply the renewable energy to another agency.

The Santa Cruz WWTP currently uses combustion generators to produce energy from digester biogas to offset energy at the facility. Improvements to enhance the energy production from the biogas at the Santa Cruz WWTP are discussed in the Food Waste to Energy project assessment.

Therefore, since local biogas is currently not available, fuel cell projects using local biogas do not appear to be feasible for GHG reduction.

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Cost There are substantial incentives available for fuel cells through the California’s Self Generation Incentive Program (SGIP) and from federal tax incentives. Because SCWD and SqCWD are tax exempt entities and cannot take advantage of the federal tax incentives; it makes purchasing fuel cells uneconomic (if they were available for sale). This is partially why the fuel cell manufacturers, or third party installers, will install fuel cell systems under a lease option. Under a lease arrangement, the manufacturer or third-party installer can take advantage of the available tax credits, and roll these into the lease costs, resulting in lower costs than if a tax exempt customer were to purchase a fuel cell without the available tax credits.

Unfortunately, there is uncertainty related to future SGIP incentive payments. The program rules are currently being revised and the program only has appropriated funding through December 31, 2011. There is an on-going conversation at the legislature about if and how much of these incentives should be continued into 2012 and beyond. It is likely that the incentives for fuel cells will continue but at a lower amount, with an overall program cap on the total amount of incentives available, and potentially under different rules (i.e. – incentives based on GHG reductions rather than KWh generated). This means that the cost of fuel cells in the near future has the potential to go up from the estimates included herein.

Lease agreements typically include all the equipment necessary for operation – this is called a turn-key project. Typical project contracts include: the fuel cell stacks and reformer, fuel clean- up system, water treatment system (if necessary), heat recovery equipment, shipping, installation, commissioning, and on-going regular maintenance. Depending on the location, the lessee may need to make upgrades to their electrical system so that it can handle the electrical output of the fuel cell. For this assessment, it is assumed that the electrical system at the desalination facility is adequate for connection to the fuel cell system, and no additional cost for an electrical system upgrade is required.

The lease agreements also includes the cost of replacement stacks every 3-5 years and remote monitoring in order to provide full-time operating support. Under a lease agreement there are typically no up-front costs to the lessee. The SCWD or SqCWD would be responsible for paying the predetermined cost of electricity through the lease, and with the Bloom fuel cell the cost of fuel (natural gas). It is further assumed that the lease would be renewed after 10 years for a total project life of 20 years.

Cost information for a lease of a SOFC fuel cell (Bloom) and a MCFC fuel cell (FCE) are provided in Table 5. There is no capital cost since the systems are leased. The PAFC (UTC) fuel cell manufacturer did not supply costs for their lease agreement, thus, are not included. Since the fuel cells’ GHG emission factors are higher than PG&E’s emission factors, there are no GHG reductions and the lifecycle GHG reduction cost is not applicable.

The cost of electricity from the SOFC fuel cell from Bloom starts at $0.13/KWh and escalates at 4% per year. This includes the cost of the natural gas fuel and the lease costs for the fuel cell system. PG&E electricity purchases start at $0.15/KWh and escalates at about 2% per year. Since the energy and fuel costs for the Bloom fuel cell are lower than the PG&E energy costs, there is an average annual net savings and a negative lifecycle energy cost. Because there are no GHG reductions the lifecycle GHG reduction cost is not applicable.

The cost of electricity from the MCFC fuel cell from FCE would start at $0.15/KWh and escalates at 3% per year. This includes the cost of the natural gas fuel and the lease costs for the fuel cell system. PG&E electricity purchases start at $0.15/KWh and escalates at about 2% scwd2 Desalination Program, GHG Reduction Project Assessments Page 11-10 K/J Project No. 0868005*03, version 9/21/2011 117 per year. The additional cost for labor and the different between the estimated inflation and utility/fuel cost escalator rates cause the FCE fuel cell to be slightly more expensive than the energy savings each year, resulting in an average annual net cost. Because there are no GHG reductions the lifecycle CO2 reduction cost is not applicable.

Table 5: Estimated Fuel Cell Costs Average Lifecycle Lifecycle GHG Life Capital Fuel Cell Type Annual Net Energy Cost Reduction Cost (yr) Cost ($) Cost ($/Yr) ($/KWh) ($/MT) $0 SOFC (Bloom) 20 -$8,300 -$0.0024 N/A Lease MCFC (FCE) $0 20 $157,000 $0.0131 N/A without heat recovery Lease

Summary of Advantages and Disadvantages Advantages:  Large financial incentives available to lesser (but not available to the tax exempt City or District) make lease costs of electricity competitive with grid electricity from PG&E.  More efficient power production than conventional IC engines.  O&M is provided by manufacturer/installer through a renewable on-going contract that relieves the O&M burden and risk.

Disadvantages:  In most circumstances by using natural gas, fuel cells emit more GHG emissions than purchasing electricity from PG&E.  Emerging technology that still needs to prove its reliability and technical maturity.  Cannot purchase, own and operate a fuel cell; only leases are available. References U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. “Types of Fuel Cells.” http://www1.eere.energy.gov/hydrogenandfuelcells/fuelcells/fc_types.html Accessed August 2011.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 11-11 K/J Project No. 0868005*03, version 9/21/2011 118 Executive Summary: PA No. 12 – Micro-hydro at Graham Hill Water Treatment Plant

Description A micro-hydro project at SCWD’s Graham Hill Water Treatment Plant (WTP) would replace an exisiting non-operational hydropower turbine at the Graham Hill WTP to generate renewable energy and reduce indirect GHG emissions from purchased electricity. A portion of the source water to the Graham Hill WTP comes from Loch Lomond through the Newell Creek Pipeline. The hydraulic energy in this water from Loch Lomond could produce energy through a new hydropower turbine. Other water sources to the Graham Hill WTP do not have available hydraulic energy.

Amount of GHG Reduction Historical and projected flow data for Loch Lomond was provided by SCWD. The micro-hydro project could offset approximately 76 MT CO2e per year if the turbine runs with current Loch Lomond flows, generating electricity approximately 85% of the time. This project could reduce approximately 10 to 20% of the potential GHG reduction goals for SCWD.

Project Life and Sustainability A micro-hydro project at the Graham Hill WTP would continue to provide GHG reductions for the estimated 20 year life of the project and beyond. The project would be sustained by normal routine maintenance.

Project Cost Table ES-1 summarizes the project cost and cost per metric ton of GHG emissions reduced. Modifying the flows to run the project at a higher capacity factor of up to 85% could generate more electricity which would in turn create more revenue. With the additional revenue the benefits exceed the costs of the project, resulting in an overall net benefit which is represented by a negative lifecycle cost.

Table ES-1: Micro-hydro Project Summary Average Annual Average Lifecycle Lifecycle GHG Life Capital GHG Reductions Annual Net Energy Cost Reduction Cost (yr) Cost ($) (MT/Yr) Cost ($/Yr) ($/KWh) ($/MT) 20 76 $180,363 -$21,163 -$0.062 -$212

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-1 K/J Project No. 0868005*03, version 9/22/2011 119 Draft Project Assessment No. 12 – Micro-hydro at Graham Hill Water Treatment Plant

Description This assessment estimates the energy generation and GHG reduction potential from the development of a micro-hydro project at the SCWD Graham Hill Water Treatment Plant (WTP).

Background: In general, hydroelectric power is created by converting the energy of falling or flowing water to mechanical energy which in turn can perform work such as turning an electric generator. To determine the amount of electricity from a particular site, the flow and elevation change, or head, must be calculated, and the pipeline losses must be subtracted. Given the flow and effective head at a site, one can calculate the potential kilowatts that can be generated at the site. Hydropower sizes commonly are defined as large (> 30 MW), small (< 30 MW), mini (< 1 MW), and micro (< 100 KW).

The type of turbine must also fit the site’s characteristics. There are two general categories of hydro turbines – impulse and reaction. Impulse turbines, such as Pelton and Turgo turbines, are used in situations with high head and low flow. Impulse turbines derive power from the change in momentum of the flowing water as it strikes the turbine blades. Reaction turbines, such as the Francis, Kaplan, and cross-flow turbines are used in situations with low head and high flow. Reaction turbines operate by harnessing reactive forces of the flowing water. Reaction turbines can be utilized in situations with heads as low as 2 feet but require much higher flow rates than impulse turbines. Because of the low head at Graham Hill WWTP the turbines in this assessment are reaction turbines, similar to the existing turbine previously installed at this location. Figure 1 below shows a general reaction hydro turbine installation and a cut away picture of a hydro turbine.

Figure 1: Typical Reaction Turbine System and Cut-away View of a Reaction Turbine

Sources of water to the Graham Hill WTP: The Graham Hill WTP receives surface water from the SCWD North Coast Diversions, from the San Lorenzo River, and from the Loch Lomond Reservoir. Water from the North Coast and San Lorenzo River diversions is pumped up to the Graham Hill WTP and does not have available hydraulic energy. Water from Loch Lomond flows through the Newell Creek Pipeline, with assistance for the Felton Booter Pump Station, and

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-2 K/J Project No. 0868005*03, version 9/22/2011 120 arrives at the Graham Hill WTP with approximately 260 feet of head, or hydraulic energy. See Figure 2 below.

While water from Loch Lomond has available hydraulic energy, the water in Loch Lomond is an important part of the SCWD system for drought supply and meeting habitat conservation requirements, and diversions from Loch Lomond to the Graham Hill WTP are limited to approximately 1,000 million gallons per year.

Previous Micro-Hydro Installation at Graham Hill WTP: A micro-hydro reaction turbine was installed at the Graham Hill WTP in 1987 and operated for over 20 years until 2008. Discussions with SCWD personnel indicate that the turbine operated satisfactorily but was not able to handle variable flows and had become inefficient. When a solar PV array was installed on the roof of the plant in 2008, PG&E requested a change in the connection wiring to meet current interconnection guidelines, and the turbine was disconnected to prevent a delay in the solar system coming on-line.

Figure 2 shows a schematic of the Graham Hill WTP source water system, including the micro- hydro turbine. Water is drawn from the Loch Lomond Reservoir through the Newell Creek Pipeline and the Felton Pump Station, where it is pumped over a hill to the Graham Hill WTP.

Figure 2: Graham Hill WTP Micro-hydro Turbine Supply Arrangement

600 ft

Newell Creek Dam Loch Lemond Reservoir 320 ft 262 ft Graham Hill Water Treatment Plant New Microhydro Felton Pump Turbine Station

The non-operational turbine is a Cornell Model 6TR3-F10X and appears to be oversized for the average amount of water passing through the Newell Creek Pipeline. The design point of this turbine was 3.9 mgd and 260 feet of head. Currently the average flow at the Graham Hill WTP from Loch Lomond through the Newell Creek Pipeline is about 1.3 mgd. The average of the annual permitted diversion from Loch Lomond is approximately 2.7 mgd.

Figure 3 shows the projected flow for the Newell Creek Pipeline for 2012. Both historical data and flow projections, with monthly flow from 2006 to 2031, were provided by SCWD for this analysis. In addition to the flow projection data, probability distributions were provided showing the likelihood of a particular flow rate over the course of a year. Probability data was provided for 2015 and 2030 both with and without desal.

Figure 4 shows the average monthly flow from Loch Lomond. A new turbine in the Newell Creek Pipeline would be sized to better recover energy from the flow. A Cornell 4TR3 turbine can generate around 35 kW at a flow of 1.3 MGD with the available 280 ft of head. The probability data provided shows that this flow rate will be available over 85% of the time. It may be

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-3 K/J Project No. 0868005*03, version 9/22/2011 121 possible to add a second turbine to capture additional energy from the pipeline, but this smaller turbine would only operate a few months out of the year, during the summer.

Figure 3: Average Daily Flow – Newell Creek Pipeline, Projected for 2012

Figure 4: Average Monthly Flow – Newell Creek Pipeline, 2006 through 2032

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-4 K/J Project No. 0868005*03, version 9/22/2011 122 Vendors: Many hydro turbines are custom built to precisely match the flow and head conditions expected at a particular site. Canyon Industries, a micro-hydro system manufacturer based in Deming, Washington, provides custom designed systems, as well as systems utilizing off-the- shelf turbines. Other examples of manufacturers include Dependable Turbines (Surrey, British Columbia) and St. Onge Environmental Engineering (Amsterdam, New York).

Figure 5: Example Canyon Industries Micro-Hydro Turbine

Installation: Some manufacturers provide off-the-shelf turbines that can be matched to common flow and head scenarios. These turbines are often less expensive than the custom built turbines. For example, Cornell Pump Company produces Francis turbines for heads between 30 to 700 feet and flows up to 15 cubic feet per second (cfs). Energy Systems and Design produces a small, ultra low head turbine (LH-1000) that produces power in flow conditions between 2 to 10 feet and 450 to 1000 gallons per minute (gpm). The LH-1000 can be placed in situations with only 18 inches of water above the turbine, as long as the total drop (surface of the water above the turbine to the surface of the outlet water) is 2 to 10 feet.

History and Technical Maturity Water power has been used throughout history as a renewable resource. Hydroelectric turbines are used to provide approximately 8% of the electricity generated in the United States. California is the second largest producer of hydroelectric power in the United States, generating 33,876 megawatt hours of electricity in 2010, according to the Energy Information Administration. Independent power producers generated 1,478 megawatt hours of electricity during 2010 and many of those systems were in-pipe potable water micro-hydro systems.

Hydroelectric turbines have been used in place of pressure reducing valves in potable water systems for more than 20 years. Turbines have been placed in new installations as well as replacing pressure reducing valves in existing systems. Turbines are reliable and have maintenance requirements similar to pumps. The technology is well known and is similar to conventional hydro turbine installations. The turbine shown in Figure 6 was installed in place of a pressure reducing valve in a potable water system near Las Vegas.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-5 K/J Project No. 0868005*03, version 9/22/2011 123 Figure 6: Example Micro-hydro Installation

Reliability and Operational Complexity The micro-hydro system would reliably produce energy and reduce indirect GHG emissions. Operationally, adding a new micro-hydro turbine to replace the existing non-operating system would have minimal effect on the system operations Major design issues that would still need to be investigated include: • Analysis to determine if additional equipment is necessary to prevent damage to the pipeline from a potential surge created by the turbine. Surges can result from a loss of utility power or malfunction in the electrical connection that causes the turbine to speed up instantaneously – a condition known as turbine runaway. • Electrical interconnection to the grid. • Bypass capacity available for system operation when the turbine is down for maintenance. • Local and Federal Energy Regulatory Commission (FERC) permitting issues.

Sustainability A micro-hydro project at the Graham Hill WTP would continue to provide GHG reductions for the estimated 20 year life of the project and beyond. The project would be sustained by normal routine maintenance.

Local Considerations Adding a new efficient micro-hydro turbine on the flow from the Newell Creek Pipeline at the Graham Hill WTP will benefit the local community by reducing the amount of energy SCWD uses to treat potable water and will take advantage of a Non-Utilized resource.

Air: Hydroelectric turbines do not have any air emissions.

Land: Since this project involves replacing a non-operational unit with a new unit of the same function and similar size, no change or impact is anticipated.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-6 K/J Project No. 0868005*03, version 9/22/2011 124 Water: Hydroelectric turbines do not consume water or create any water pollution.

Noise: Hydroelectric turbines do produce some noise, similar to any rotating equipment. Based on other installations, placing equipment in a vault minimizes the noise to below local noise ordinance levels. Further sound proofing maybe required in areas sensitive to noise.

Aesthetic/Visual: The turbine would be placed inside the existing building and therefore no change or impact is anticipated.

Waste by-product: Some hydroelectric turbines utilize grease to lubricate bearings in the generator which will need to be disposed of properly.

Energy Production and GHG Reductions From discussions with PG&E we infer that a new micro-hydro turbine in normal operations would not feed the grid and the generated electricity would be used on-site. However, in the instance where part of the WWTP load were to fall off electricity could flow back onto the grid. The turbine connection to the grid would be required to meet PG&E’s interconnection requirements for self generation in the Net Metering Program, similar to the addition of a stand- by generator.

The turbine is assumed to operate 85% of the time based on the flow data shown in Figures 3 and 4, and the energy production values assume that the flow and head are constant through the turbine. This project could reduce approximately 10 to 20% of the potential GHG reduction goals for SCWD.

Table 1: Estimated Energy Production and GHG Reductions for a Micro-Hydro Project Annual Energy Annual GHG Reduction Flow (MGD) Head (ft) Max kW Produced (kWh/yr) (MT CO2e) 1.30 289 65.0 260,610 76

Cost The capital cost of a micro-hydro project, including: engineering, mechanical, electrical, site development, markups, and installation is estimated at approximately $180,000. The turbine itself is expected to cost approximately $45,000, based on a typical cost of $1,300/kW for this size turbine. Operation and Maintenance cost should be similar to a pump, and average $0.005/kWh, plus about 0.1 FTE. With proper maintenance, a turbine should have a lifetime of 20 plus years.

Since there is a possibility of electricity flowing back onto the grid this assessment assumes that this micro-hydro project will use the Net Energy Metering (NEM) program. NEM applies to micro-hydro projects as long as the project is behind the meter and a maximum of 1 MW in size. Net metering is a method of metering the energy consumed and produced by a utility customer that has a renewable resource generator, and credits the customer with the retail value of the generated electricity. Effectively, the meter runs backwards, causing a credit with the utility. Net metering’s benefit is the deferred cost of the electricity that SCWD does not have to purchase, providing the full retail value of the electricity produced (on average 15 cents/KWh). Net excess generation (NEG) beyond that month’s actual usage is carried over as a credit for a 12-month cycle, but at the end of the 12-month period, any NEG is zeroed out and SCWD will not be paid for that generation. It therefore becomes important to correctly size the project so that over the course of a year the project does not create any NEG.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 12-7 K/J Project No. 0868005*03, version 9/22/2011 125 However, in the unlikely event that this project were to create NEG virtual net metering would allow SCWD to realize the value of the NEG. California Assembly Bill (AB) 2466 (codified as Section 2830 of the Public Utilities Code), was signed into law in September 2008 and allows a local governments & special districts to install renewable generation of up to 1 MW at one location within its geographic boundary (water service area) and to generate credits that can be used to offset the generation charges at one or more other locations within the same geographic boundary. This billing arrangement is called virtual net metering (VNM). But unlike NEM, VNM only credits the generation portion of the utility bill and the benefiting account will still pay the transmission and other utility fees. At this time, it is assumed that the energy generating facility needs to be in the same county as the benefiting account. However, in this analysis, we assumed that all of the project’s generation would be used on-site.

The cost of the project and the GHG reductions are shown in Table 2 below. This table shows that running the project a capacity factor of 85% would result in a negative cost, or benefit, because the project would generate substantially more electricity thereby creating more revenue than the cost of the project.

Table 2: Estimated Micro-hydro Project Costs Lifecycle GHG Life Capital Cost Average Annual Net Lifecycle Energy Reduction Cost (yr) ($) Cost ($/Yr) Cost ($/KWh) ($/MT CO2e) 20 $180,363 -$21,163 -$0.0617 -$212

Summary of Advantages and Disadvantages Advantages: • Take advantage of a renewable resource not currently utilized. • Lower lifecycle costs than utility power. • Indirect GHG reductions. • Mature, low risk, well understood technology. • Modest FTE requirements and low impact on operations. • Local benefit from the GHG reductions coming from within the local community.

Disadvantages: • Modest capital expenditures. • Uncertainty about cost and generation. Need to confirm flow and time-of-use rates, and if additional equipment is necessary due to potential surges.

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Executive Summary: Draft PA No. 13 – Hydropower Project at Lake Nacimiento

Description This project would purchase the renewable energy output from the Lake Nacimiento (LN) small hydro power project.

Amount of GHG Reduction Since this is an existing project and does not include expansion or acceleration, it cannot be considered additional and would not be a valid GHG reduction project for the scwd2 Desalination Program. This is a fatal flaw; therefore, the LN project has been withdrawn at this time from further consideration as a GHG reduction project. However, SCWD or SqCWD may choose to consider this project as a separate renewable energy investment opportunity in the future.

Project Life and Sustainability A power purchase agreement (PPA) for the energy from the Lake Nacimiento hydropower project most likely would last for 15 to 25 years. The PPA could be renewed and could be a long-term, sustainable energy source.

Project Cost The project cost is unknown at this time. MCWRA issued an RFP for this project but did not provide any cost information. Creation of a Load Serving Entity for direct access would be expensive, and the potential “bidding war” for the RFP could make purchase price uneconomical for scwd2.

Table ES-1: Lake Nacimiento Hydropower Project Summary Annualized Lifecycle Average Project GHG Capital/Setup GHG Cost Space Annual Cost Life Reduction Cost ($) ($/MT Requirements ($/year) (MT CO2e/yr) CO2e) Unknown. Unknown. Potential Creation of a None – this “bidding war” Load Serving 30+ years project is not environment Entity for N/A None (sustainable) additional could make direct access (fatal flaw) purchase could be price expensive. uneconomical.

scwd2 Desalination Program, GHG Reduction Project Assessments Page 13-1 K/J Project No. 0868005*03, version 9/21/2011 127

Draft Project Assessment No. 13 – Hydropower Project at Lake Nacimiento

Description This assessment estimates the energy generation and GHG reduction potential from the purchase of the renewable energy output from the Lake Nacimiento small hydro power project.

Hydroelectric power is a renewable resource generated by converting the energy of falling or flowing water to mechanical energy, which can then be used to perform work, such as turning a generator. The Monterey County Water Resources Agency (MCWRA) owns and operates an existing 4 megawatt (MW) hydropower facility on Lake Nacimiento (LN) in northern San Luis Obispo County, California. The LN hydropower project was built in 1987 and has been operating continuously ever since. The electricity was sold to Pacific Gas and Electric (PG&E) under a 20- year power purchase agreement (PPA) and, since 2007, under a temporary purchase contract. MCWRA issued a Request for Proposal (RFP) in May 2011 to find a new buyer for the electricity and its associated environmental benefits under a 15 to 25 year PPA.

At first glance, the LN hydropower project appeared to be a potential greenhouse gas (GHG) reduction project for the scwd2 Desalination Program. However, the following fatal flaw and additional concerns have been identified, and it is recommended that scwd2 withdraw the LN project at this time from further consideration as a GHG reduction project.

History and Technical Maturity The LN hydropower project was built in 1987 and has been operating continuously ever since.

Reliability and Operational Complexity The complexity of direct access, the lack of certification by California ISO, and the mismatched supply and demand create reliability issues and operational complexities for this potential project.

Mismatched Supply and Demand: As shown in Figures 1 and 2, the load profile of LN does not match well with the estimated load profile of the desalination plant. In several winter months, the LN project would not serve the full electricity demand of the desalination plant; scwd2 would have to purchase additional electricity from the grid. In summer months, LN would produce electricity in excess of the scwd2 demand. scwd2 would have to find additional customers or partners so as not to lose money paying for unused electricity. This adds complexity and cost to the LN project.

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Figure 1 – Estimated LN Supply vs. Desalination Demand in a Non-Drought Year

Note: Average LN monthly data from January 1997 through March 2008, provided by FMY Associates, Inc.

Figure 2 – Estimated LN Supply vs. Desalination Demand in a Drought Year

Note: Average LN monthly data from January 1997 through March 2008, provided by FMY Associates, Inc. scwd2 Desalination Program, GHG Reduction Project Assessments Page 13-3 K/J Project No. 0868005*03, version 9/21/2011 129

Complexity of direct access: Participation in the LN hydro project would require scwd2 to purchase the output via a direct access arrangement. However, the requirements for direct access are highly complex. For instance, serving existing meters requires the creation of a Load Serving Entity (LSE), which would be expensive, difficult, and time-consuming to create. Even if the cost of the hydropower generation was low, scwd2 could lose money for a number of years due to the set-up costs associated with the LSE contract.

Lack of certification by California ISO: An electricity generation project has to be certified by California Independent System Operator (ISO) to deliver the electricity from LN to scwd2. LN has been certified in the past under its contract with PG&E but would have to be recertified under a new contract. scwd2 may be required to lead this process, which would be a complex and time-consuming endeavor.

Timing: MCWRA is interested in entering into a long-term contract in the next few months, but scwd2 is not interested in entering into a long-term contract at this time, since the scwd2 desalination plant is currently in the environmental review process and, if constructed, is not expected to be in operation until 2015.

Sustainability A power purchase agreement (PPA) for the energy from the Lake Nacimiento hydropower project most likely would last for 15 to 25 years. The PPA could be renewed and could be a long-term, sustainable energy source.

Local Considerations This project would use renewable energy from a fairly local resource. As a renewable energy investment opportunity, this project could allow scwd2 and/or the communities of Santa Cruz and Soquel creek to serve their energy load with renewable energy.

Energy Savings and GHG Reduction Eligibility criteria for renewable energy projects have been developed by the US Department of Energy and state agencies such as the California Energy Commission (CEC) Emerging Renewables Program. GHG reduction projects pursued by scwd2 should meet these eligibility criteria in order to be recognized by regulatory agencies.

One of the evaluation criteria for a GHG reduction project is additionality. The concept of additionality was introduced in the Kyoto Protocol in Article 12.5, which states that “emission reductions resulting from each project activity shall be certified by DOEs (Designated Operational Entities) on the basis of ... reductions in emissions that are additional to any that would occur in the absence of the certified project activity.” In other words, new emissions reductions have to be created by a project.

If scwd2 were to directly purchase LN hydropower-generated electricity (rather than purchasing energy from the grid or a new renewable energy project), the amount of indirect GHGs created would not necessarily change for the following reasons: • The LN project has been creating emissions-free energy since 1987, so no new emissions reductions would occur if scwd2 were to purchase this energy. • Although scwd2’s power load would be served by LN, PG&E may have to serve fossil fuel-generated electricity to users that were formerly supplied by LN power. (Note that

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this scenario oversimplifies the resource portfolio of PG&E’s energy and is for demonstration purposes only.) • Removing the LN hydropower resource from PG&E’s portfolio would not necessarily force PG&E to replace LN with another renewable resource to meet its RPS requirement. Therefore, the LN project cannot be considered additional and would not be considered a valid GHG reduction project (in accordance with the Kyoto Protocol) for the scwd2 Desalination Program.

Cost The project cost is unknown at this time. MCWRA issued an RFP for this project but did not provide any cost information. MCWRA appears to be actively soliciting offers for the purchase of the LN project output. This may create a “bidding war” environment that is likely to increase the purchase price of energy, which could make this option uneconomic for scwd2. In addition, creation of a Load Serving Entity for direct access would be expensive.

Summary of Advantages and Disadvantages Advantages: • For several months during the year, the LN project could provide enough energy to meet the load of the proposed scwd2 desalination plant • Could provide SCWD or SqCWD with renewable energy for overall operations, other than just the desalination project.

Disadvantages: • Lack of additionality – Fatal Flaw as GHG reduction project • Mismatched supply and demand • Complexity of direct access • Lack of certification by California ISO • Poor timing • Potentially inflated cost

Although this project will no longer be considered as a potential GHG reduction project for the scwd2 Desalination Program, the Santa Cruz Water Department and Soquel Creek Water District may consider this project as a separate renewable energy investment opportunity in the future.

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Executive Summary: PA No. 14 – GHG Offset Purchases

Description A GHG offset purchase program would entail purchasing GHG offset projects that give SCWD or SqCWD the sole legal right to claim the GHG emission reductions from the project. There are a numerous types of GHG offset projects but they can include: direct reductions of the use of fossil fuels, methane capture at a landfill or wastewater treatment plant, or a reforestation project, among others.

SCWD and SqCWD could use GHG offset purchases to build a portfolio of medium and long- term offsets to meet the agencies reduction goals, and/or as an annual “true-up” tool, in which the number of GHG offsets could change each year based on the amount of GHG reduction needed to meet the agencies’ desired GHG reduction goals.

Amount of GHG Reduction

One GHG offset represents a reduction of one metric ton of carbon dioxide equivalent (CO2e). So, 100 GHG offsets equals 100 metric tons (MT) of CO2e. In the offset market place SCWD and SqCWD could buy as many GHG offsets as needed to meet their GHG reduction goals.

Project Life and Sustainability A GHG offset purchase program would provide GHG reductions for the length of the contract term of the offset purchase, and the term can range from one year to the life of the offset (i.e. – 1 to 20 years). SCWD and SqCWD would chose the life of the offset and could buy either short- term, medium-term or long-term offsets to meet their needs.

Project Cost GHG offset costs vary depending on the type and source of the offset. This assessment assumes that SCWD and SqCWD would purchase certified offsets. The price of an offset currently is approximately $10-$13 per MT CO2e and is likely to increase over time. To offset 100 MT CO2e per year, the average annual cost would be approximately $5,700 for 20 years, for 250 MT about $8,200 per year, and for 1,000 MT about $21,000 per year. There is a substantial one-time set-up cost (from legal fees and staff time) that is approximately the same regardless of the amount of offsets purchased. So, of one were to purchase a larger amount of offsets, this one-time fee is spread over more offsets, and the cost per offset is reduced. The table below shows that the lifecycle cost per MT of CO2e drops from $48 for 100 MT to $17 for 1,000 MT.

Table ES-1: GHG Offset Purchase Summary Lifecycle Average Avg Annual Lifecycle GHG Life Capital Annual GHG Energy Project Reduction (yr) Cost ($) Net Cost Reductions Cost Cost ($/Yr) (MT/Yr) ($/KWh) ($/MT) GHG Offsets (100 MT) 20 $30,800 $5,659 100 N/A $48 GHG Offsets (250 MT) 20 $62,000 $8,213 250 N/A $27 GHG Offsets (1,000 MT) 20 $218,000 $20,981 1,000 N/A $17

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Draft Project Assessment No. 14 – GHG Offset Purchases

Description Greenhouse gas (GHG) offsets, or a carbon offsets, are a tradable commodity representing the reduction of one metric ton of carbon dioxide equivalent (MT CO2e). GHG offsets may be purchased by SCWD and SqCWD to counteract the direct and indirect emissions from the desalination plant.

A global compliance market place already exists since the establishment of the European system in 2005. In 2007 that market traded 2,918 million MT of offsets valued at over $66 billion dollars. The market for compliance offsets already exists in the eastern US through the Regional Greenhouse Gas Initiative (RGGI). In 2008, 72 million MT of offsets were traded with a value of $263 million. The compliance market will come into existence in California with the implementation of California’s cap & trade system (the basic rules for the cap & trade system were approved in December 2010). The system could be up and running in 2012. The market for voluntary offsets and carbon reduction projects exist now and in 2008 123 million MT were traded with a value of $705 million. There are essentially three markets or three types of offset projects that exist or are expected to be created in the future regulatory environment: • Compliance Offsets • Voluntary Offsets • Carbon Reduction Projects

In order to categorize an offset one needs to look at the offset project specifics and determine which standard the project meets. The standard for each of these types of offset projects is different. Compliance offsets are meant to be traded in the regulatory cap & trade environment and thus must meet the highest standard in order to qualify. These projects must meet all the eligibility criteria set forth in AB 32: additional, real, permanent, quantifiable, verifiable, and enforceable and be based on a an approved protocol (see discussion below) and registered with the California Climate Action Registry. Voluntary offsets are outside the regulatory cap- and-trade system, meet the AB 32 criteria, but are not covered by an approved protocol nor would they be registered. These types of projects are usually set-up through a contract between the project developer and the buyer (e.g., a bi-lateral contract). Carbon reduction projects are offsets that cannot necessarily meet the AB 32 criteria or are not covered by any approved protocol, but are projects that intuitively known to cause reductions in GHGs. An example might be materials recycling programs.

This assessment focuses only on compliance and voluntary offsets because it is likely they will be the type of offsets that regulators will accept for the scwd2 Energy Minimization and GHG Reduction Plan. This would be consistent with what the regulators did for Poseidon’s Carlsbad 50 MGD desalination project.

Compliance and voluntary offsets must be certified, and there are numerous entities that have established processes to certify offset projects:

• California Climate Action Reserve (CAR) • Chicago Climate Exchange (CCX) scwd2 Desalination Program, GHG Reduction Project Assessments Page 14-2 K/J Project No. 0868005*03, version 9/21/2011 133

• Gold Standard (GS) • Voluntary Carbon Standard (VCS)

There are numerous other participants in the voluntary marketplace that sell offsets (e.g., NativeEnergy), and large brokers that develop, certify and sell offset project (e.g., 3Degrees and EcoSecurities). The US Department of Energy’s (DOE) Energy Efficiency and Renewable Energy (EERE) Green Power Network lists over 30 different retailers nationwide (http://apps3.eere.energy.gov/greenpower/markets/carbon.shtml). In addition, CAR’s CRT marketplace lists a variety of carbon credit retail, wholesale, brokers, and exchanges (http://www.climateactionreserve.org/how/crt-marketplace). The organizations help customers buy, sell, and market environmental commodities including verified carbon offsets. Many organizations are based in California, such as 3Degrees, which is headquartered in San Francisco.

There is a rigorous process that an offset project must go through in order to be certified by any one of these entities. Every offset must be certified and verified by an independent third-party. As part of the submittal of a project for certification it must: • Describe the GHG offset project and the project developer’s qualifications. • Explain how the project meets the AB 32 eligibility criteria: additional, real, permanent, quantifiable, verifiable, and enforceable. • Explain the methodology/protocol for calculating the project emission reductions, including the quantification of the baseline and the project’s incremental emission reductions • Monitoring and verification plan

Most certifying entities have restrictions about what types of offsets they will accept and certify; and some like CAR limit their acceptance to only projects that have fully vetted, peer reviewed, and approved protocols and methodologies. For instance, CAR currently only has protocols for nine types of offset projects: • Forests (sequestration) • Urban Forests (sequestration) • Landfills • Livestock • Coal-Mine Methane • Organic Waste Composting • Organic Waste Digestion (ie – wastewater digesters) • Nitric Acid Production • Ozone Depleting Substances

An agricultural protocol is currently in the scoping process. Developers of these project types must register their GHG reduction projects with a third party verification agency, such as CAR. For certified and verified offset projects CAR will issue carbon offset credits known as Climate Reserve Tonnes (CRT). Once the GHG offsets have

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been registered, project owners may sell the offsets as compliance offset. However, since the regulatory compliance market and cap-and-trade system will not be established for California until 2012, offsets are currently only traded in the voluntary market.

There are two ways that SCWD and SqCWD likely would use offsets: 1. Purchase short-term to long-term offsets (i.e., 1 to 20 years) to help build a portfolio of GHG reduction projects to meet their GHG reduction goals.

2. Use offset purchases as an annual tool to meet their annual GHG reduction target. On an annual basis SCWD and SqCWD will need to calculate the necessary MT of CO2 it will need to reduce. To perform this calculation, SCWD and SqCWD will obtain the latest PG&E emission factor from the annual web-based California Air Resources Board (CARB) Emissions Report. SCWD and SqCWD will gather electricity usage data and then calculate the necessary metric tons of offsets required for the subject year. The subject year’s calculated metric tons of net emissions will be compared to the amount of metric tons of offsets previously acquired by SCWD and SqCWD to determine if SCWD and SqCWD have a positive or negative balance of net GHG emissions for the subject year. If there is a positive balance of net GHG emissions, SCWD and SqCWD can purchase offsets to eliminate the positive balance. If there is a negative balance of net GHG emissions, the surplus offsets may be carried forward into subsequent years or sold by SCWD and SqCWD on the open market. This annual “true-up” process will enable SCWD and SqCWD to meet each year’s need by purchasing or banking short- term one-year offsets.

GHG offsets do not include renewable energy credits (RECs), which represent the environmental attributes of the power produced from renewable energy projects (RECs are discussed in Project Assessment No. 9), nor energy efficiency projects.

History and Technical Maturity California is the furthest along with respect to creating a regulatory framework for dealing with climate change and GHGs. In 2006, they passed the AB 32 the “Global Warming Solutions Act” which created GHG reduction goals, established a mandatory emissions reporting requirement, required the state to develop a plan to achieve the reduction goals, and called for a cap-and- trade system as part of the many measures needed to meet their GHG targets. CARB is currently working closely with six other western states and four Canadian provinces through the Western Climate Initiative (WCI) to design a regional cap-and-trade program. The program and rules are scheduled to go into effect and be legally enforceable by January 1, 2012. The cap- and-trade system will create a relatively small compliance market for carbon offsets. AB 32 also embraced most of the offset criteria initially established by the Kyoto Treaty. AB 32 also required that all offsets must be: additional, real, permanent, quantifiable, verifiable, and enforceable. Offsets also must be certified, verified and registered.

At the federal level, the US Environmental Protection Agency (EPA) has established a mandatory reporting program, and has the authority to regulate GHGs. They are currently in the process of developing that regulatory program.

In the earlier history of offsets there were offsets offered for sale did not meet the standards that they need to meet today. Rightfully, this caused the public to be quite skeptical of offsets, and first impressions are difficult to erase. However, since that time there has been an incredible amount of work to establish the certification rules and infrastructure that was described above.

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Given the amount of rigor offsets now need to go through to become certified they have become increasingly more legitimate. While some may still be skeptical, once they become familiar with the rules and infrastructure they become more accepting of offsets. Today most people consider offsets as mature and legitimate.

Reliability and Operational Complexity The purchase of GHG offsets presents minimal operational complexities to SCWD and SqCWD. The program will require some administrative assistance and management. The certification and verification process painstakingly developed over the past decade requires a monitoring and verification program that ensures that the GHG emission reductions are quantifiable, real and permanent.

Sustainability A GHG offset purchase program would provide GHG reductions for the length of the contract term of the offset purchase, and the term can range from one year to the life of the offset (i.e. – 1 to 20 years). SCWD and SqCWD would chose the life of the offset and could buy either short- term, medium-term or long-term offsets to meet their needs.

Local Considerations Retailers and vendors of carbon credits offer either a part of their portfolio of offset projects or a project-specific GHG offset. In either case, SCWD and SqCWD would know where the offsets are coming from. SCWD and SqCWD may elect to purchase GHG offsets from only local projects. This would however be subject to the timing and availability of local projects.

By purchasing GHG offsets from local projects, SCWD and SqCWD would be investing in a project that directly benefits the local community. Such projects may include: forestry set-aside projects, urban forestry projects, re-forestation of areas damaged by recent fires, biogas production projects at local livestock farms and/or wastewater treatment plants, diversion of organics from local landfills, methane capture at a local landfill, and restoration of coastal wetlands. The benefit to the local community would be the creation of jobs, enhanced awareness and education, and reduction of local GHG emissions. Depending on the type of project, there may also be reductions in local energy consumption and local waste.

For example, currently there are a total of 42 projects either listed or registered with CAR in California. There is only one registered project located within Santa Cruz County – the Lompico Forest Carbon Project (http://www.sempervirens.org/climate.php) – which was developed in conjunction with PG&E and their Climate Smart program. The 425-acre forest preservation project was one of the first registered in the state of California under CAR’s Forestry Protocol. In accordance with the Forestry Protocol’s carbon accounting standards, this project sequesters 11,708 MT CO2e (or approximately 28 MT CO2e per acre). None of these offsets are currently available for purchase by SCWD or SqCWD.

If no local projects are available at the time of purchase, SCWD and SqCWD could pursue GHG offset project elsewhere in California or elsewhere in the country. Alternatively, SCWD and SqCWD could do its own RFP to solicit local qualified offset projects, thereby stimulating the supply of local projects. While this of course will take some effort and time to put out an RFP; it will increase the likelihood that the offsets will be local.

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The specific environmental impacts of the purchasing of GHG offsets will depend on the type of GHG offset project. For example, methane capture at a landfill will have positive impacts to air and land, whereas a re-forestation project will be beneficial to air, land, water, and aesthetics. In general, all GHG offset projects will have positive environmental impacts.

Air: Most projects do not create air pollution, some actually enhance air quality, and any reduction in electricity use would also reduce GHG emissions.

Land: Most qualified projects would occur within the footprint of an existing facility and would not have a land impact. Forestry and urban forestry projects could possibly have positive impact on land use.

Water: Most offset projects would have little to no impact on water use; however, forestry related project will need water for irrigation. With proper design and care, projects should not have an impact on water quality.

Noise: Most offset project would have construction noise issues, and any methane recovery for electricity generation projects and composting operations could create significant noise issues.

Aesthetic/Visual: Most qualified projects would occur within the footprint of an existing facility and would not have an aesthetic/visual impact. Forestry and urban forestry projects could possibly have positive impact.

Waste by-product: Most offset projects would not have waste by-products. Forestry project will have slash from thinning, and landfill projects would probably not create additional leachate. Livestock projects, wastewater digestion projects, and composting projects will likely result in a reduction or beneficial use of the waste by-products.

Energy Savings and GHG Reductions A GHG offset project would not produce or save energy. The amount of GHG reduction would be based on how many carbon credits are purchased. Again, one GHG offset represents a reduction of one metric ton of carbon dioxide equivalent (CO2e).

SCWD and SqCWD could choose to offset some or all of their direct and indirect emissions related to the scwd2 desalination plant. For planning purposes, this assessment estimates the amount of offsets required to offset the annual indirect GHG emissions from the proposed desalination plant running at half capacity, which equates to approximately 2,000 MT CO2e per year.

Table 1: Estimated GHG Reductions for GHG Offset Purchases Annual GHG Lifetime GHG Annual Energy Project Reduction Reduction Produced or Saved (MT CO2e/yr) (MT CO2e) GHG Offsets (100 MT) 0 100 2,000 GHG Offsets (250 MT) 0 250 5,000

GHG Offsets (1,000 MT) 0 1,000 20,000

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Cost In the aftermath of the California Air Resources Board’s (ARB) positive vote on a cap & trade system in December 2010, the price of pre-compliance offsets increased to $13/MT for the week of January 3-7, 2011. Compliance offset prices would likely command a higher price than this price for pre-compliance projects. For instance, in the well established and mature European Union’s Emissions Trading Scheme (EU-ETS) the current trading price is about 14.38 Euros (about $18.70/MT at current exchange rates). The prices in the EU-ETS have dropped since the first half of 2008 when there were at 20 Euros/MT (about $27/MT). Prices reached 22 Euros/MT (about ($29/MT) at the end of the second half of 2008, and fell to 13 Euros/MT (about $17/MT) in the first half of 2009.

Recent studies done by the Congressional Budget Office (CBO) and the U.S. Environmental Protection Agency (EPA), both of which were completed in June 2009, estimated a system price for a national cap & trade system. These studies provide reasonable price estimates for SCWD and SqCWD even though they are estimate for a national system based on the 2009 Waxman/Markey bill and somewhat dated. There are to our knowledge no better price forecasts available. Both the CBO and EPA estimate 2015 starting price at around $12-$16/MT. They differ in their escalation rates (EPA at a flat 5% per year, and CBO starting at 17% per year in 2016 and dropping to 10% by 2020), and therefore end up at different 2020 price estimates (EPA at just over $15/MT and CBO at over $22/MT). Estimates for the future 2020 price in the EU-ETS are in the range of 22-30 Euros/MT ($28/MT to $39/MT at today’s exchange rates). Table 2 summarizes the current market prices and forecast for 2015 and 2020 prices.

Table 2: Current and Estimated Future Offset Market Prices Market Price California Voluntary Market $13 per MT (2011) $19 per MT (2011) EU-ETS $28 to $39 per MT (2020) $12 per MT (2015) EPA $15 per MT (2020) $12 per MT (2015) CBO $22.40 per MT (2020)

Many factors influence the price of carbon offsets including the type of project, location, and certifying protocol and/or agency. This assessment assumes that SCWD and SqCWD would purchase certified offsets. This assessment assumes a 2012 price of about $10.40/MT, escalating at 5% per year, resulting in a 2015 price of $12.04. This is reasonable and is consistent with the EPA and CBO studies, and consistent with recent California market prices. However, recent prices for offsets have dipped into the $2/MT CO2e, and it is possible with the lack of action at the federal level and on the California cap-and-trade system the price could again fall to single digit price levels. Using a $10.40/MT starting price would be a conservative assumption.

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To offset 100 MT CO2e per year, the average annual cost would be approximately $5,700 for 20 years, for 250 MT about $8,200 per year, and for 1,000 MT about $21,000 per year. There is a substantial one-time set-up cost (from legal fees and staff time) that is approximately the same regardless of the amount of offsets purchased. So, of one were to purchase a larger amount of offsets, this one-time fee is spread over more offsets, and the cost per offset is reduced. The table below shows that the lifecycle cost per MT of CO2e drops from $48 for 100 MT to $17 for 1,000 MT. Table 3 provides a summary of the estimated costs of a GHG offset program. There are no incentives for the purchase of GHG offsets.

Table 3: Estimated GHG Offset Project Costs Average Lifecycle Lifecycle GHG Life Capital Project Annual Net Energy Cost Reduction (yr) Cost ($) Cost ($/yr) ($/kWh) Cost ($/MT) GHG Offsets (100 MT) 20 $30,800 $5,659 N/A $48

GHG Offsets (250 MT) 20 $62,000 $8,213 N/A $27

GHG Offsets (1,000 MT) 20 $218,000 $20,981 N/A $17

Summary of Advantages and Disadvantages Advantages: • Relatively low cost projects ($/MT). • Minimal up-front capital requirement. • Operationally simple. Minimal staffing to track and administer the program over time. • Flexibility. Can purchase various amounts for various lifetimes. Can be an effective tool during the annual true-up process. Disadvantages: • Risk that costs ($/MT) could be higher than the estimate in future years. • Potential lack of available, cost-effective local projects. If none are available in the market, it may require SCWD and SqCWD to do a RFP to stimulate its own set of local offset projects. • The general public does not understand how GHG offsets are certified and often question whether offsets are real and permanent. SCWD and SqCWD may need to do public education about the rigor these offsets go through before pursuing a GHG offset purchase program.

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Executive Summary: Draft PA No. 15 – Fleet Fuel Reduction Program

Description A fleet fuel reduction program would change the composition of SCWD and SqCWD vehicle fleets, use alternative fuels, and implement other fuel savings strategies, such as behavioral changes, to reduce the GHG emissions of the fleets.

Amount of GHG Reduction SCWD’s 53-vehicle fleet uses approximately 27,000 gallons per year of fuel, and SqCWD’s 30- vehicle fleet uses approximately 9,200 gallons per year of fuel. It is estimated that SCWD could offset approximately 41 MT CO2e per year by purchasing alternative vehicles, utilizing B-20 biodiesel fuel, and implementing driver behavioral changes. By implementing similar changes, SqCWD could offset approximately 14 MT CO2e per year. This project could reduce approximately 6 to 10% of the potential GHG reduction goals for SCWD, and 1% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability Without the scwd2 Desalination Program, it is assumed that SCWD and SqCWD would replace their fleet vehicles with alternative vehicles at a rate of 5% per year for 20 years. The accelerated portion of this program assumes a replacement rate of 20% per year for 5 years, so the program can only claim the difference between the two. This program would have decreasing GHG offsets over time and would expire after 20 years.

Project Cost Table ES-1 summarizes the estimated project costs.

Table ES-1: Fleet Fuel Project Summary Annual GHG Lifecycle GHG Life Capital Average Annual Agency Reductions Reduction Cost (yr) Cost ($) Net Cost ($/Yr) (MT/Yr) ($/MT) SCWD 20 41 $5.4 million $403,000 $7,700

SqCWD 20 14 $3.5 million $290,000 $16,000

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Draft Project Assessment No. 15 – Fleet Fuel Reduction Program

Description This project assessment considers GHG reduction opportunities from potential changes in the composition of the SCWD and SqCWD vehicle fleets, the use of alternative fuels, and other fuel savings strategies. SCWD’s 53-vehicle fleet currently uses approximately 27,000 gallons per year of fuel, and SqCWD’s 30-vehicle fleet uses approximately 9,200 gallons per year of fuel.

This assessment looks at the GHG emissions associated with the lifecycle of different transportation fuels, or “well-to-wheel” emissions, which includes both the direct GHG emissions associated with the combustion of transportation fuels for vehicle operation (“tank-to-wheel” emissions), as well as the indirect GHG emissions associated with the production and distribution of these transportation fuels (“well-to-tank” emissions). This approach allows for like comparisons of the GHG consequences among various alternative vehicle and fuel technologies.

Baseline Elements

Low Carbon Fuel Standard (LCFS): The California Air Resource Board (CARB) has adopted a Low Carbon Fuel Standard (LCFS) that requires transportation fuel providers to reduce the well- to-tank carbon intensity of both gasoline and diesel by 10% by 2020. This assessment includes LCFS as part of the baseline, since scwd2 will have to meet this standard regardless of the project.

Alternative Vehicle Procurement: Transitioning SCWD and SqCWD’s current fleets of vehicles to cleaner fuels and more efficient vehicles could provide significant well-to-wheel GHG reductions. This assessment assumes that within each vehicle class, SCWD/SqCWD would gradually increase the number of vehicle miles traveled by alternative vehicle types, while decreasing the vehicle miles traveled by baseline vehicle types. The baseline rate of transition is assumed to occur evenly over a 20-year period—that is, each year 5% of baseline vehicle miles will be replaced with alternative vehicle miles. When a vehicle class has more than one alternative vehicle substitute, it is assumed that the alternative vehicle miles are split equally among those substitutes.

The table below shows how baseline vehicle type GHG intensity per mile travelled (well-to- wheel grams CO2e/mile) compares to the alternative vehicle substitutes evaluated in this assessment.

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Table 1: 20-year Average Well-to-Wheel Carbon Intensity of Conventional and Alternative Vehicles by Vehicle Class Well-to-Wheel Well-to-Wheel Conventional Vehicle Alternative Vehicle grams CO2e/mile grams CO2e/mile Class 1 Gasoline Light Trucks 835 Electric Vehicle 143 (e.g. Ford Ranger) 349 (ULSD) Class 1 & Class 2a Diesel 338 (B-20) Gasoline Light and 888 Light-duty Truck Gasoline Hybrid Electric 292 (e.g. Dodge Ram 1500) Compressed Natural Gas 295 555 (ULSD) Class 2b Diesel 539 (B-20) Gasoline Commercial 1,266 (Gasoline) Light Truck 966 (Diesel) Hybrid Electric 464 (e.g. Dodge Ram 2500) Compressed Natural Gas 470 Classes 3-5 1,263 (Gasoline) Liquid Natural Gas 998 Diesel and Gasoline 1,317 (ULSD) Light-Heavy Truck 1,020 (ULSD) 1,191 (B-20) Diesel Hybrid Electric (e.g. Chevrolet Silverado) 991 (B-20) Liquid Natural Gas 1,289 Classes 6-8 2.128 (ULSD) Diesel Heavy-Heavy Truck 1,156 (ULSD) 1,924 (B-20) Diesel Hybrid Electric (e.g. F 750 Dump) 1,122 (B-20)

• Electric Vehicles: Electric vehicles (EVs) are propelled by electric motors powered by rechargeable batteries. EVs can be recharged on conventional electrical circuits in about eight hours or in as little as 15 minutes with a higher rated electrical service. EVs already exist in the marketplace, including the Nissan Leaf. Other passenger substitutes to gasoline light truck vehicles include hybrid electric vehicles, like the Toyota Prius, or plug-in hybrid electric vehicles, like the Chevrolet Volt.

While electric vehicles (EVs) emit no direct tailpipe GHG emissions, there are indirect emissions associated with the generation of electric power that charges the batteries. While the difference between EV emissions and the emissions from other Class 1-2a alternative vehicle options (diesel, gasoline hybrid electric and compressed natural gas) are not huge, there is still value to the larger community, through demonstration, in early adoption of this emerging technology.

In addition, SCWD/SqCWD could consider the actual use of its Class 1 and Class 2a light trucks to confirm their use for hauling. In this analysis, we assumed that all trucks were necessary for hauling capacity. However, if there are any trucks that are used for passenger transport, SCWD/SqCWD could transition to electric passenger vehicles, which have even lower wheel to well emissions, and potential for further GHG reductions, than the options we evaluated.

• Light Duty and Commercial Light Trucks: For gasoline powered Class 1 light trucks (LTs), Class 2a light-duty trucks (LDTs) and Class 2b commercial light trucks (CLTs), the assessment assumes that the current vehicles are gradually replaced by a combination of clean diesel, gasoline hybrid electric, and compressed natural gas (CNG) powered trucks.

Hybrid electric LDTs, like the Chevrolet Silverado Hybrid, already exist in the marketplace. While new CARB-compliant clean diesel LDTs are not currently available in the U.S., each U.S. automaker has developed a market ready half-ton diesel pickup prototype, expected to

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be brought to market as the economy strengthens. While LDTs must be retrofitted with after-market conversion kits to be powered by CNG, they are available for a wide range of LDT makes and models and fully converted models are available direct from many dealerships.

As a result of recent improvements in diesel engine technology, CARB-compliant clean diesel CLTs are currently available in the marketplace including the Chevrolet Silverado 2500/3500. No hybrid electric CLTs are currently available in the U.S., however as state and federal fuel economy rules are extended to this vehicle class, more market choices should become available. Like LDTs, CNG powered CLTs must be retrofitted but are readily available through many dealerships.

• Light-Heavy and Heavy-Heavy Trucks: The assessment assumes that heavier gasoline and diesel trucks in Classes 3 through 7 are gradually replaced with liquid natural gas (LNG) and diesel hybrid electric powered vehicles.

At least 20 models of hybrid electric light-heavy and heavy-heavy trucks are currently available in the market in a range of chassis types, such as box vans, utility trucks, and long-haul tractors. Hybrid electric utility trucks hold particular promise for significant GHG reductions since auxiliary equipment, like vacuums and pumps, can operate solely on the truck’s battery. LNG powered light-heavy and heavy-heavy trucks are available both as after-market conversions as well as factory built options.

Accelerated or Additional Program Elements Accelerated Alternative Vehicle Procurement: An accelerated program would replace SCWD and SqCWD’s current fleets of vehicles at a rate of 20% over 5 years. The difference between the baseline rate and the accelerated rate would be accounted for in GHG reduction.

It should be noted that this assessment does not consider operational constraints (e.g. towing capacity) that must be considered when selecting a particular vehicle make and model. However, while certain alternatives may not be suitable for SCWD/SqCWD’s specific application, in general, the technologies underlying the alternatives have the potential to exceed the power and torque performance of conventional vehicles.

It is estimated that implementing this strategy could reduce SCWD/SqCWD well-to-wheel fleet emissions by approximately 670 MT CO2e over a 20-year period.

Biodiesel (B-20): Switching from diesel fuel to B-20 fuel (20% biodiesel, 80% diesel) could reduce SCWD/SqCWD’s well-to-wheel fleet GHG emissions by approximately 63 MT CO2e over a 20-year period. The benefit is not significant, since conventional, soybean-based biodiesel still has relatively large well-to-tank GHG emissions. If the biodiesel used in the blending were derived from alternative feedstock, such as used cooking oil, the GHG reductions could be significantly greater.

Behavioral Changes: Implementing educational programs that encourage drivers to operate fleet vehicles more efficiently and deploying technologies, such as telematics, that enable fleet mangers to optimize vehicle dispatching or monitor vehicle operation can yield considerable GHG emission reductions.

In this assessment, it is assumed that a behavioral change policy would consist of driver behavioral changes, including no-idle policy and avoiding rapid acceleration/deceleration, as

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well as keeping tire properly inflated and vehicles maintained, but does not include telematics. This is estimated to sustain an average fuel economy improvement of 5% per year. Achieving this rate of fuel savings could reduce SCWD/SqCWD well-to-tank GHG emissions by approximately 304 MT CO2e over a 20-year period.

Vendors A number of organizations can provide technical assistance and financial support for implementing fleet fuel strategies, including:

• CALSTART (http://www.calstart.org/Homepage.aspx): Works with business, fleets, and government to develop and implement clean, efficient transportation solutions. CALSTART manages the California Hybrid Truck User Forum and the Natural Gas Vehicle Co-Op, and administers the California Hybrid Truck and Bus Voucher Incentive Project.

• Environmental Defense Fund Green Fleet Project (http://business.edf.org/projects/fleet- vehicles): Sponsor private sector partnerships to reduce fleet GHG emissions. Publishes Fuel-Smart Driver Training curriculum.

• California Natural Gas Vehicle Coalition (http://www.cngvc.org/): Association of natural gas vehicle manufacturers. Publishes Natural Fueling Station Directory for California.

History and Technical Maturity

In recent years, municipal utilities and other public fleets have been increasingly adopting goals to reduce their GHG emissions. The water utility in the City of Austin, Texas has adopted a goal of reducing fleet GHG emissions by 20% by 2020. The Las Vegas Valley Water District has converted more than 80% of its 1,800-unit fleet to alterative-fueled vehicles, including bio-diesel, CNG and hybrid electric. SCWD has already implemented telematics on three vehicles.

Not all types of alternative vehicles, like clean diesel LDTs, are currently available in the marketplace. However, at least one market-ready substitute technology is currently available for each vehicle class.

Reliability and Operational Complexity

One operational challenge of a fleet fuel consumption program is the existence of adequate fueling infrastructure. Currently, commercial refueling stations are limited, so successful implementation would require installing on-site fueling infrastructure at SqCWD facilities to accommodate natural gas or biodiesel refueling. Partnering with other public agency fleets may provide cost-saving opportunities. Another operational challenge is staff acceptance of behavioral driving changes.

Sustainability

Without the scwd2 Desalination Program, it is assumed that SCWD and SqCWD would replace their fleet vehicles with alternative vehicles at a rate of 5% per year for 20 years. The accelerated portion of this program assumes a replacement rate of 20% per year for 5 years, so the program can only claim the different between the two. This program would have decreasing GHG offsets over time and would expire after 20 years.

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Local Considerations

Economy and Education

In addition to the global benefits of GHG reductions, SCWD/SqCWD will benefit from this project through the direct and local reduction of GHGs and other vehicle tailpipe emissions. The transition to alternative vehicles recommended in this analysis provides a local GHG emissions reduction of approximately 1,040 MT CO2e over 20 years.

In addition, it is likely that a fleet fuel adjustment project would have a beneficial impact on local air quality, primarily through reductions in gasoline consumption, transitioning diesel consumption to clean diesel technologies, and increasing the use of cleaner burning natural gas.

Environment

Air: This program would improve local air quality through reductions in PM and NOx emissions.

Land: EV charging stations would require a small amount of land.

Water: There is no anticipated water impact.

Noise: Since some alternative vehicles produce less noise than traditional vehicles, there could be reduced engine noise.

Aesthetic/Visual: There are no anticipated aesthetic or visual impacts.

Waste by-product: There is no anticipated waste by-product impact.

GHG Project Eligibility Criteria Compliance This section describes the six eligibility criteria that a fleet fuel adjustment project must meet in order to be considered a regulatory compliance GHG offset project.

Additional: This program would take credit for the additional, accelerated alternative vehicle procurement at a rate of 20% over 5 years, minus the baseline rate of 5% over 20 years. The purchase of B-20 versus ULSD also likely meets the implementation barrier test. These two strategies also likely meet the common practice test, since most utility fleets are still dominated by conventional vehicles and fuels.

Quantifiable: GHG reductions realized through the procurement of alternative fueled vehicles and the purchase of B-20 can be readily established using existing GHG inventory methodologies. In the end, the quantification of GHG reductions comes down comparing alternative fuel consumption to business as usual fuel consumption. This can be done by comparing the emissions from alternative fuels to the emissions associated with an equivalent amount of conventional fuel.

Verifiable: With adequate recordkeeping, GHG reductions realized through the procurement of alternative fueled vehicles and the purchase of B-20 could be readily verified by a third-party.

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Enforceable: Only the tank-to-wheel portion of GHG reductions realized through the procurement of alternative fueled vehicles and the purchase of B-20 would meet the standard for enforceability.

Real: The difference in the carbon intensity of different fuels is clearly established in the scientific literature. Since the GHG reductions realized through the procurement of alternative fueled vehicles and the purchase of B-20 would be based on measured changes in the types of fuels combusted for transportation, there is high confidence that the emissions reduction would be real.

Permanent: There is no risk of reversibility, as the GHG reductions realized through the procurement of alternative fueled vehicles and the purchase of B-20 would be based on instantaneous fuel substitutions. Once a unit of alternative fuel is combusted, there is no chance that a unit of conventional fuel would combusted instead.

Estimated GHG Reductions The SCWD/SqCWD cumulative well-to-wheel GHG emissions total approximately 1,040 MT of CO2 for the 20-year period. This project could reduce approximately 6 to 10% of the potential GHG reduction goals for SCWD, and 1% of the potential GHG reduction goals for SqCWD. Table 2 shows how the various potential reduction options could reduce the well-to-wheel carbon footprint.

Table 2: Estimated GHG Reduction – GHG Offset Program Average Annual GHG Reduction Lifetime GHG Reduction

(MT CO2e/yr) (MT CO2e) SCWD Accelerated Alternative 26 500 Vehicle Purchase Biodiesel (B20) 2 47 Behavioral Changes 12 227 Total 41 775 SqCWD Accelerated Alternative 9 170 Vehicle Purchase Biodiesel (B20) 1 16 Behavioral Changes 4 77 Total 14 263 Source: Well-to-tank emissions factors are based on data from CARB’s Low Carbon Fuel Standard program (http://www.arb.ca.gov/fuels/lcfs/workgroups/workgroups.htm#pathways). SqCWD Fleet Fuel Consumption from July 2010 – June 2011 data. SCWD Fleet Fuel Consumption from watervehfuel.xls provided by Keith Van Der Maaten. This analysis is of on-road and in-use vehicles and does not take into consideration tractors, generators, or other machinery, or any vehicles with zero fuel consumption in the baseline year. Also excluded from this analysis is any fuel recorded as “gas card” and not attributed to a specific vehicle.

Note that this project assessment only considers direct GHG emissions. While these strategies reduce the use of gasoline and diesel, they also increase the use of other fuels. Specifically, plug-in hybrids use electricity, and some alternative vehicles use CNG. However, because these strategies reduce the use of fuels that emit the most GHG, there is overall a greater reduction of GHG emissions over time (even if the greater reduction is not counted as part of this project due to additionality).

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Cost Capital Cost: In general, the up-front purchase price of alternative vehicles will be greater than that of conventional vehicles. However, over the lifetime of ownership alternative vehicles offer cost savings through reduced fuel consumption that tends to offset these higher up-front costs. In addition, alternative vehicles tend to have higher resale values.

The primary capital cost is alternative vehicle procurement. SCWD would replace 53 vehicles and SqCWD would replace 30 vehicles, at vehicle costs estimated to range from approximately $50,000 to over $200,000, depending upon the vehicle class. In addition, staff would have to be trained in behavioral changes. The capital cost is estimated to be approximately $5.4 million for SCWD and $3.5 million for SqCWD.

Annual Costs: Annual costs will include reduced fuel costs from alternative vehicle replacement, switching to B-20 fuel, and behavioral changes. These savings are estimated to save approximately $22,000 per year for SCWD and $8,000 per year for SqCWD. It is estimated that one quarter FTE would run this program for each agency.

Table 3 summarizes the estimated program costs.

Table 3: Fleet Fuel Program Costs Lifecycle GHG Project Life Capital Cost Average Annual Net Reduction Cost (yrs) ($) Cost ($/yr) ($/MT CO2e) SCWD 20 $5.4 million $403,000 $7,700

SqCWD 20 $3.5 million $290,000 $28,000

Summary of Advantages and Disadvantages Advantages: • Reduction of direct and indirect fleet GHG emissions.

Disadvantages: • High capital cost associated with accelerated purchases of alternative vehicles

References Tiaxx, LLC (2010). Comparative Costs of 2010 Heavy-Duty Diesel and Natural Gas Technologies at http://www.tiaxllc.com/reports/HDDV_NGVCostComparisonFinalr3.pdf

McKinsey & Company (2010). A Portfolio of Power-Trains for Europe: A Fact-Based Analysis: The Role of Battery Electric Vehicles, Plug-in Hybrids, and Fuel Cell Electric Vehicles at http://www.zeroemissionvehicles.eu/uploads/Power_trains_for_Europe.pdf

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Executive Summary: Draft PA No. 16 – Carbon Dioxide Addition for Post Treatment

Description

A carbon dioxide (CO2) addition project would use CO2 for post-treatment and corrosion control 2 of the reverse osmosis (RO) permeate at the proposed scwd desalination facility. The CO2 would be purchased from a facility that recovers and purifies the CO2 from the waste streams of industrial production facilities that would otherwise be released to the atmosphere, therefore offsetting direct GHG emissions.

Amount of GHG Reduction 2 The proposed scwd desalination facility would use approximately 250 pounds of CO2 per million gallons of water treated. Based on projected operation of the desalination plant, a CO2 addition project is estimated to offset approximately 15 MT CO2 per year for SCWD and 55 MT CO2 per year for SqCWD. This project could reduce approximately 10 to 15% of the potential GHG reduction goals for SCWD, and 4 to 5% of the potential GHG reduction goals for SqCWD.

Project Life and Sustainability

A CO2 addition project would continue to provide GHG reduction for the life of the project and beyond. The project would be sustained by normal maintenance to repair any infrastructure deterioration.

Project Cost For the estimated life of the project (30 years), the average annual cost would be approximately $52,000 per year, or about $472 per MT CO2.

Table ES-1: Carbon Dioxide Addition Project Summary Annualized Average Lifecycle Project GHG Capital Annual GHG Space Agency Life Reduction Cost ($) Net Cost Reduction Requirements (MT CO2/yr) ($/yr) Cost ($/MT) Part of SCWD 30+ years 15 $500,000 $52,000 $472 desalination (sustainable) SqCWD 55 facility footprint

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Draft Project Assessment No. 16 – Carbon Dioxide Addition for Post Treatment

Description This assessment estimates the GHG reduction potential through the use of carbon dioxide (CO2) for post-treatment and corrosion control of the reverse osmosis (RO) permeate at the proposed scwd2 desalination facility.

Background

CO2 has many uses in our society, including corrosion control at potable water treatment plants and carbonation of “soda” beverages. The CO2 provided for these uses is “food grade” or NSF 60-certified for addition to potable water. In a post-treatment of the desalination process, CO2 will be added to the RO permeate in combination with calcium carbonate (limestone) to form soluble calcium bicarbonate, which adds hardness and alkalinity to the potable water for distribution system corrosion protection. The chemistry of the water allows CO2 to be sequestered in soluble form as calcium bicarbonate. Because the pH of the potable water distributed for potable use is in a range at which CO2 remains in a soluble bicarbonate form (pH of 7.8 to 8.5), the CO2 introduced in the RO permeate would remain permanently sequestered.

Depending on the supplier, CO2 is produced one of three ways:

• CO2 Recovery: CO2 recovery plants produce CO2 by recovering it from the waste streams of other industrial production facilities which emit CO2-rich gasses: breweries, commercial alcohol (i.e., ethanol) plants, hydrogen and ammonia plants, refineries, etc. Typically, if these gases are not collected via a CO2 recovery plant and used in other facilities, such as the desalination plant, they are emitted to the atmosphere and therefore, constitute a GHG release.

• Atmospheric CO2 Concentration: An atmospheric CO2 concentration plant takes air from the atmosphere and produces compressed and liquefied gases for commercial uses. The natural gases in the atmosphere are separated out to produce nitrogen, oxygen, argon, and others including CO2.

• CO2 Generation: CO2 generation plants use various fossil fuels (natural gas, kerosene, diesel oil, etc.) to directly produce CO2 by fuel combustion.

Vendors A number of commercial suppliers, including Praxair, Airgas, the Linde Group and Air Liquide, 2 could supply “food grade” NSF 60-certified, bulk liquid CO2 to the proposed scwd desalination facility. These four vendors would supply CO2 from CO2 recovery plants located in Richmond, Benicia, or Martinez, California. Airgas also distributes CO2 supplied by Dyno Nobel that is collected from the atmosphere in conjunction with the production of other atmospheric gases. However, this product is distributed from farther away in St. Helens, Oregon.

History and Technical Maturity

CO2 storage, feed, and control equipment have been in use for many years at water treatment plants for this type of application. Typically, bulk CO2 is supplied and stored in liquid form. The liquid CO2 would be vaporized into gas and dissolved into the RO permeate water to react with the calcium carbonate which adds hardness (calcium) and alkalinity (HCO3) into the potable

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water for distribution system corrosion protection. During the treatment process, the calcium carbonate (calcite – CaCO3) reacts with the CO2 injected in the water and forms completely soluble calcium bicarbonate [Ca(HCO3)2] as shown in the following chemical reaction:

CaCO3 (solid) + CO2 (gas) + H2O (liquid) → Ca(HCO3)2 (liquid solution)

At the typical pH range of potable water (pH of 7.8 to 8.5), the CO2 will remain in the potable water in soluble form (see Figure 1), and the entire amount (100 %) of the injected CO2 will be completely dissolved.

Figure 1 – Forms of CO2 at Different pH Levels

Source: Center for Educational Technologies. “The Chemistry of Alkalinity.” November 2004. http://www.cotf.edu/ete/modules/waterq3/WQassess3b.html

This chemical reaction and information are taken from texts on the basic chemistry of water. See the American Water Works Association (AWWA) (2007) Manual of Water Supply Practices, M46.

This process also has been thoroughly outlined in the approved Energy Minimization and Greenhouse Gas Reduction Plan for the Carlsbad Desalination Plant (Poseidon Resources):

Once the desalinated potable water is delivered to individual households, a portion of this water will be ingested directly or with food, and a portion of the water will be used for other purposes, such as human consumption, personal hygiene, or irrigation. The calcium bicarbonate ingested by humans will be dissociated into calcium and bicarbonate ions. The bicarbonate ions will be removed by the human body through the urine (Washington University). Since the CO2 is sequestered into the bicarbonate ion, human consumption of the desalinated water will not result in release of CO2. The bicarbonate in the urine will be conveyed along with the other sanitary sewerage to the wastewater treatment plant. Since the bicarbonate is dissolved, it will not be significantly impacted by the wastewater treatment process and ultimately will be discharged to the ocean with the wastewater treatment plant effluent. The ocean water pH is in a range of 7.8 to 8.3, which would be adequate to maintain the originally sequestered CO2 in a soluble form, as shown in Figure 1.

Other household uses of potable water, such as personal hygiene, do not involve change in

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potable water pH, as demonstrated by the fact that pH of domestic wastewater does not differ significantly from that of the potable water.

A significant amount of the calcium bicarbonate in the potable water used for irrigation would be absorbed and sequestered in plant roots. The remaining portion of calcium bicarbonate would be adsorbed in the soils and/or would enter the underlying groundwater aquifer. (Stolwijk et al)

Reliability and Operational Complexity

The operational complexity of a CO2 system would be low to moderate. Operation of the CO2 storage and feed system equipment would be mostly automated. O&M activities would include receiving chemical deliveries and performing routine maintenance activities and would be similar to other chemical systems used at water treatment plants.

Sustainability RO permeate post-treatment would occur for the life of the proposed scwd2 desalination facility, which is assumed to be 30 years, so GHG reduction from a CO2 addition project also would occur for that time period. The project would be sustainable and continue for a longer period of time through routine maintenance and sustained operation of the desalination facility.

Every delivery of CO2 to the proposed desalination facility would be accompanied by a certificate that states the quantity, quality, and origin of the CO2. It will also indicate that the CO2 was recovered as a site product from an industrial application of known type of production and was purified to meet the requirements associated with its use in potable water applications (NSF-60 approved). The desalination facility would archive the certificates for verification 2 purposes. scwd would place conditions in its purchase agreements with CO2 vendors that 2 require transfer of CO2 credits to scwd and otherwise ensure that the CO2 is not accounted for through any other carbon reduction program so as to avoid “double counting” of associated carbon credits.

Local Considerations Economy

Since the CO2 for post-treatment and corrosion control likely would come from suppliers in the San Francisco Bay Area, the program may benefit local vendors who provide water treatment chemicals and supplies.

Environment

Air: GHG emissions would be reduced by the CO2 recovery process in the local San Francisco Bay Area direct GHG emissions.

Land: Since the equipment would be located at the proposed scwd2 desalination facility, there would be no significant additional land impact.

Water: There is no impact on water quality.

Noise: Since the equipment would be located at the proposed scwd2 desalination facility, there would be no significant additional noise impact.

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Aesthetic/Visual: Since the equipment would be located at the proposed scwd2 desalination facility, there would be no additional aesthetic or visual impact.

Waste By-Products: This process would not create waste by-products. The CO2 recovery process would reduce the waste stream of industrial processing facilities.

GHG Project Eligibility Criteria Compliance

This section describes the six eligibility criteria that a CO2 addition project must meet in order to be considered a regulatory compliance GHG offset project.

Additional: This program would be additional because it would not occur without the proposed scwd2 desalination facility.

Quantifiable: The amount of CO2 injected into the RO permeate would be known and quantifiable.

Verifiable: With adequate recordkeeping, GHG reductions realized through a CO2 addition project could be readily verified by a third-party.

Enforceable: To make the project enforceable, scwd2 would place conditions in its purchase 2 agreements with CO2 vendors that require transfer of CO2 credits to scwd and otherwise ensure that the CO2 is not accounted for through any other carbon reduction program.

Real: The CO2 would be purchased from a facility that recovers and purifies the CO2 from the waste streams of industrial production facilities that would otherwise be released to the atmosphere, therefore offsetting real GHG emissions.

Permanent: There is no risk of reversibility, since the pH of the potable water distributed for potable use is in a range at which CO2 remains in a soluble bicarbonate form (pH of 7.8 to 8.5), so the CO2 introduced in the RO permeate would remain permanently sequestered. The permanence is further described above in the History and Technical Maturity section.

GHG Reductions

The use of CO2 for post-treatment and corrosion control would reduce GHG emissions by creating an additional demand for CO2 that would otherwise be released into the atmosphere. 2 The scwd desalination facility would use approximately 400 pounds per day (ppd) of CO2 when operating at an average flow of 1.6 mgd, which equals 250 pounds of CO2 per million gallons of 2 water treated. The amount of GHG emissions from the delivery of CO2 to the scwd desalination facility would be minimal and is included in this estimate.

Table 1 shows the estimated annualized GHG reduction based on the projected annualized operation of the desalination plant.

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Table 1: Estimated GHG Reduction for CO2 Addition Project Projected Annualized Annualized GHG Reduction Agency 1 Operation (MGY) (MT CO2/yr) SCWD 131 15 SqCWD 485 55 1Assuming a 7 year drought cycle with 5 non-drought and 2 drought years. Annualized over life of project, based on projected operation of the desalination plant from the Energy Projections and Potential Greenhouse Gas Reduction Goals report, July 2011.

This project could reduce approximately 10 to 15% of the potential GHG reduction goals for SCWD, and 4 to 5% of the potential GHG reduction goals for SqCWD.

Cost

Capital Cost: The CO2 system is estimated to cost approximately $500,000 and would include a storage tank, vaporizer, injector, diffuser, and instrumentation, as well as sitework, a concrete slab, piping, and electrical installations.

Operations Cost: Local distributors of CO2 provided budgetary quotes for delivered CO2 ranging between $110 and $240 per ton. Additional delivery charges are expected to cost approximately $60 per delivery. Based on an average use of 400 ppd and a delivery every other month, the annual cost of the delivered chemical would be approximately $12,000 per year. The energy use and labor cost is already included in the overall desalination facility cost.

Table 2 below summarizes the cost for a CO2 addition program. The average annual net cost is the annual operating costs plus the debt service on the capital cost over the life of the project.

Table 2: Estimated Costs for CO2 Addition Program Lifecycle GHG Project Life Average Annual Net Cost Capital Cost ($) Reduction Cost (yrs) ($/yr) ($/MT CO2) 30 $500,000 $52,000 $472

Summary of Advantages and Disadvantages Advantages: • CO2 system is part of the desalination facility. • GHG reduction by creating demand for recovered CO2 that would otherwise be released into the atmosphere.

Disadvantages: • None

References American Water Works Association (AWWA) (2007) Manual of Water Supply Practices, M46.

Center for Educational Technologies. “The Chemistry of Alkalinity.” November 2004. http://www.cotf.edu/ete/modules/waterq3/WQassess3b.html

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Kennedy/Jenks Consultants. Energy Projections and Potential Greenhouse Gas Reduction Goal. July 2011.

Poseidon Resources. Carlsbad Desalination Plant Energy Minimization and Greenhouse Gas Reduction Plan. July 2008.

Stolwijk, J.A.J. and Kenneth V. Thimann. “On the Uptake of Carbon Dioxide and Bicarbonate by Roots, and Its Influence on Growth.” February 1957. http://www.pubmedcentral.nih.gov/pagerender.fcgi?artid=540973&pageindex=1.

Washington University in St. Louis. “The Carbonic-Acid-Bicarbonate Buffer in the Blood.” 2004. http://www.chemistry.wustl.edu/~courses/genchem/Tutorials/Buffers/carbonic.htm.

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7 October 2011 scwd2 Evaluation Criteria Scoring and Weighting Sensitivity Analysis

To: Susan O’Hara, City of Santa Cruz Water Department

From: Julia Sorensen, Todd Reynolds, and Alan Zelenka

Subject: scwd2 Desalination Program Energy Study K/J 0868005*03

Introduction The purpose of this memo is to provide an overview of the scoring parameters and weighting sensitivity analysis for the evaluation and ranking of the sixteen potential GHG reduction projects for the scwd2 Desalination Program Energy Technical Working Group (ETWG) Workshop in October 2011. The potential GHG reduction projects are broadly categorized as: • Water and energy efficiency projects • Renewable energy projects • GHG reduction projects The objective of the workshop is to narrow the sixteen potential GHG reduction projects to a group of approximately 6 to 8 projects that would be used to develop project portfolios that would meet the range of potential GHG reduction goals for the scwd2 Desalination Program.

GHG Reduction Project Evaluation Criteria The following evaluation criteria were reviewed by the ETWG and subsequently approved by the scwd2 Task Force: • Cost / Cost Effectiveness • Amount Produced or Mitigated • Sustainability / Project Life • Local Considerations • Technical Maturity • Reliability and Operational Complexity

Proposed Criteria Scoring Approach The criteria are scored on a scale of 1 to 10; in which 1 is the lowest or least favorable score and 10 is the highest or most favorable score. The criteria of Cost/Cost Effectiveness, Amount Produced/Mitigated, and Sustainability/Project Life have quantifiable values and are scored in relationship to the respective values. The criteria of Local Considerations, Technical Maturity,

© Kennedy/Jenks Consultants, Inc. 155 Kennedy/Jenks Consultants

Memorandum Susan O’Hara, City of Santa Cruz Water Department 7 October 2011 0868005*03 Page 2 and Reliability/Operation Complexity do not have quantifiable values and therefore will be evaluated and scored based on a relative set of performance factors described below. The following sections describe how each criterion is proposed to be scored.

Cost / Cost Effectiveness

Based on cost effectiveness (in dollars per MT CO2e reduced), potential projects are grouped into the following scoring bins. The bins have varying range of costs to help differentiate projects over a wide range of cost effectiveness (from -$215 to $75,000 per MT CO2).

Cost Effectiveness ($/MT CO2e reduced) Score Min Max -$250 -$100 10 -$99 $0 9 $0 $50 8 $51 $100 7 $101 $300 6 $301 $500 5 $501 $700 4 $701 $900 3 $901 $1,100 2 $1,101 $75,000 1

The conceptual capital cost of the projects will also be taken into account during the project ranking and sensitivity analysis phase.

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Amount Produced or Mitigated

Based on amount of annual GHG reduction (in MT CO2e reduced per year), potential projects are grouped into the following scoring bins.

Amount Reduced (MT CO2e reduced / year) Score Min Max 0 100 1 101 200 2 201 300 3 301 400 4 401 500 5 501 750 6 751 1,000 7 1,001 1,250 8 1,251 1,500 9 1,501 2,000 10

Sustainability / Project Life The sustainability of the project is the ability of the project to provide GHG reductions over a long period of time, assuming proper maintenance to the system. Based on the maximum number of years (up to 30 or more) that a project is estimated to last (assuming proper maintenance to the system), projects are grouped into the following scoring bins.

Score Description 10 Project can provide GHG reductions for 30 or more years and can be renewed. 8 Project can provide GHG reductions for 15 to 29 years and can be renewed. 4 Project can provide GHG reductions for less than 15 years and cannot be renewed.

Local Considerations This criterion considers the local benefits and impacts of the proposed project to the community. Local benefits include: • Helping to improve the local economy through local construction, job creation, and training • Helping to educate and inform the community on water, energy and sustainability issues

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• Reduction of local energy consumption and/or reduction of local GHG emissions • Reduction/reuse of local waste generation • Impacts to air, land, water, noise, and visual/aesthetic • Construction impacts to the community The projects are scored according to the following local consideration factors.

Score Description Likely to have significant local benefit for both jobs and environment, and provides 8 – 10 educational opportunity for public benefit. Reduces local water use and/or energy use and/or GHG emissions. 6 – 7 Likely to have moderate local benefit. 4 – 5 Only a relatively minor local benefit. 1 – 3 Unlikely to have local benefit. Potential impacts on air, land, noise, etc.

Technical Maturity This criterion considers the proven performance and stage of research and/or development. The projects are scored according to the following factors.

Score Description 8 – 10 History of proven performance 6 – 7 Relatively new project but proven performance on municipal scale. 4 – 5 Proven on pilot scale but lacks proven performance on a larger municipal scale. 1 – 3 Still under development. Lacks proven performance or not commercial.

Reliability and Operational Complexity This criterion considers the reliability and operational complexity of the proposed projects. Reliability of the project is the ability of the project to produce the expected GHG reductions. Operational complexity includes: • Number of different processes and equipment, • Level of automation and ease of operation • Ownership by SCWD or SqCWD • Staffing and maintenance requirements by SCWD or SqCWD • Level of interagency collaboration

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The projects are scored according to the following factors.

Score Description 8 – 10 High reliability, low risk, and/or easy to implement and operate. 6 – 7 Medium reliability and risk, moderate operational complexity. Relies on customers to sign up/install once, or provides operational complexities for 4 – 5 SCWD/SqCWD staff. Difficult to implement. GHG reduction is not as reliable. For example, if project relies on customers to 1 – 3 continuously implement. Difficult to implement.

Project Ranking through Criteria Weighting and Sensitivity Analysis Once the scoring of the sixteen projects has been completed, the approved weightings will be applied to each criterion to create a total score for each project. The total score will identify the favorability of the projects. Several sensitivity analyses will be run on the weighting to evaluate the effect on the project rankings of different weightings that focus more weight on different criteria.

Kennedy/Jenks worked with SCWD and SqCWD staff to identify a proposed weighting range for each evaluation criterion. Based on feedback from the Task Force and the ETWG, the range for each criterion was refined to a recommended weighting. In addition, several proposed sensitivity analyses were developed to vary the weight of some of the factors. The recommended weightings of the evaluation criteria and example potential sensitivity analysis weightings are shown in the table below.

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Recommended Weighting and Example Sensitivity Analysis Weightings for Evaluation Criteria

Proposed Sensitivity Analyses Recommended Evaluation Criteria Weighting Cost- Local- Weighting Other Range Focused Focused Local Benefit 15 to 20% 20% 10% 50% 20% Energy Produced or 10 to 15% 10% 5% 10% 15% GHG Reduced Technical Maturity 15 to 25% 10% 5% 10% 15% Sustainability 10 to 15% 5% 2.5% 2.5% 10% Reliability and Operational 5 to 10% 5% 2.5% 2.5% 5% Complexity Cost/Cost 15 to 50% 50% 75% 25% 35% Effectiveness Total 100% 100% 100% 100%

Additional Sensitivity Analysis Considerations The following additional factors will also be used to evaluate the effect on the project rankings of different weightings that focus more weight on different criteria.

• Capital Cost • Eliminates or reduces City of Santa Cruz CAP opportunities • GHG Reduction Reliability (Customer Behavior) • Energy/Water Nexus Focus • Reliability/Operational Complexity Focus • Reduce direct Agency energy use

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