Third-Party Implemented Program Policies and Procedures Manual for Business

Transcription

1 Third-Party Implemented Program Policies and Procedures Manual for Business Version 1.6 April 1, 2011 Utility Administrator: Southern California Edison Section 1 of this Manual supersedes ONLY Section 1 of the 2010 Statewide Customized Offering Procedures Manual (Addendum A) for Business and supplement section 3 of Addendum A (DR TA/TI). Sections 1 and 2 of this manual also supplements Section 1 of the 2010 Statewide Deemed Offering Procedures Manual for Business (Addendum B). Note: The Measurement & Verification (M&V) adder described in the Statewide Manuals is not applicable to Third-Party Implemented Programs. The Standard Pay-for-Performance (PFP) Third-Party Implemented Program (the Program) is administered by Southern California Edison (SCE) within its service territory. The incentive rates, incentive limits, and statewide program requirements are identical to those of Pacific Gas & Electric and San Diego Gas & Electric within their respective service territories. The Statewide program packaging and individual offering may vary slightly between the utilities (Utility Administrators). Subject to all applicable federal, state, and local laws and to CPUC rulings, SCE reserves the right to approve otherwise eligible Energy Efficiency (EE) projects by waiving project steps and/or sequencing guidelines. If SCE determines program influence and can establish appropriate baseline and post operating conditions, with or without a pre- or post-inspection and including energy savings calculation, SCE reserves the right to make appropriate and reasonable business decisions regarding project eligibility and approvals. Third-Party Implemented Programs Ver. 1.6 April 1, 2011

2 Revision History Third Party Implemented Programs Policies and Procedures Manual for Business Program Years Effective Date Version Document Owner 4/1/ Anne Miller- George Updates / Comments - Changed SMART references to SCE s Invoice and Reporting Tool Added Project Scoping Document context into Project Submission Revised Equipment Order Description Added Project Scoping Document into the Project Submission Process Added overview of Project Scoping Document Revised PFS description Revised description for Proof of Equipment - Added Appendix C: Industrial/Commercial Process Flow - Appendix C Added Process Flows into Section - Changed Implementer to Consultant Third-Party Implemented Programs Ver. 1.6 April 1, 2011

3 Contents of This Manual Section 1 Standard PFP Program Overview and Policies Appendix A Advanced Lighting Technical Requirements Appendix B EEG Cost Documentation Section 2 Turnkey Program Overview and Policies Addendum A 2010 Statewide Customized Offering Procedures Manual for Business Addendum B 2010 Statewide Energy Efficiency Business Rebates Manual Third-Party Implemented Programs Ver. 1.6 April 1, 2011

4 Section 1: Offering Overview and Policies for Standard Pay-for- Performance Third-Party Implemented Program 1.1 Introduction How the Program Works Eligibility for Participation Qualifying Energy Efficiency Measures Direct Savings and Multiple Measures Aggregating Customer Project Sites Verification Requirements (EE) Incentive Payments Project Submission Process Other Important Terms and Conditions Appendix A: Advanced Lighting Technical Requirements Appendix B: Project Cost Documentation Requirements Appendix C: Industrial / Commercial Process Flow.1-22 Third-Party Implemented Programs Ver April 1,, 2011

5 1.1 Introduction The Standard Pay-for-Performance (PFP) Third-Party Implemented Program provides technical services to identify opportunities, develop project feasibility studies, provide project management assistance, and perform all measurement and verification services as necessary for the installation of high-efficiency equipment, and/or process system efficiency improvements to obtain incentives from SCE. SCE implements this program utilizing Consultant s with Purchase Order agreements targeted at specific market segments. Nonresidential Customers that install energy-saving and Demand Response technologies are eligible for incentives based on calculated energy savings, permanent peak demand reduction, and temporary load reduction. Energy Efficiency incentives are paid on the energy savings and permanent peak demand reduction that exceeds baseline energy performance. Baseline energy performance includes state- and federally-mandated codes, industry-accepted performance standards, and other baseline energy performance standards as determined by SCE. For Demand Response (DR) incentives, customers that purchase and install technologies that reduce electricity use during peak periods can receive reimbursements of up to $125 per kw of verified load reduction. Customers can be eligible for up to $300 per kw of verified load reduction for purchasing and installing technologies that reduce electricity use during peak periods without manual intervention (Automated Demand Response Auto DR). To receive incentives, a non-residential customer must submit a project through the Third-Party Consultant for the installation of eligible energy efficiency and Demand Response measures through the Standard PFP Third-Party Implemented Program process. The Standard PFP Third-Party Implemented Programs began on January 1, Completed projects will be accepted until October 31, 2012, or until SCE s incentive funds are fully committed. Administered by Utilities -- The Standard PFP Third-Party Implemented Programs are administered by Southern California Edison Company (SCE) in its service territory. Designed for Non-Residential Customers -- The Standard PFP Third-Party Implemented Programs serve non-residential customers that receive energy services from Investor-Owned Utilities (IOUs), such as SCE, and pay into the Public Purpose Program (PPP) surcharge (for energy efficiency incentives only). Offering Materials -- Incentive payments are based on adherence to the offering. Therefore, be sure to read all of Section 1, Offering Overview and Policies of the Standard PFP Third-Party Implemented Programs, before starting a project. 1.2 How the Program Works The Main Players The Standard PFP Third-Party Implemented Programs involve five key parties: Customer - An eligible non-residential Ratepayer who is applying for incentives through a Third-Party Implemented Program. Contract Program Manager (CPM) - The CPM manages all aspects of the program and makes final decisions. ` Third-Party Implemented Programs Ver April 1,, 2011

6 Consultant - The Consultant is authorized by SCE and is responsible for identifying projects, making program presentations, submitting a Project Document, preparing the Project Feasibility Study (PFS), completing the Installation Report, and performing all steps required to ensure the viability of submitted projects. The consultant is also responsible for ensuring that all the required paperwork is submitted correctly and for ensuring that the project is completed. Reviewer - The reviewer is responsible for reviewing the PFS, Installation Reports, and other project documentation to ensure project viability, and energy efficiency savings calculations (Addendum A, Section 2) and for verification of load reduction (Addendum A, Section 3) Utility Administrator - SCE administers the program in its service territory The Basic Process The Standard PFP Third-Party Implemented Program works as follows: 1. Project Submission. The consultant submits a Project Scoping Document, Program Agreement (PA), Project Feasibility Study (PFS), including M&V Plan (Customized Measures only), W-9, and all other supporting documentation through SCE s Invoice and Reporting Tool. For DR measures, the consultant will confirm customer eligibility with the reviewer at the time of PA submission, which will then create an IDAR (Interval Data Analysis Report) for use by the Consultant. The consultant must then submit a Form 2B with the PFS. Note: Before the initial meeting with a customer, the consultant must contact SCE's Business Customer Division (BCD) so that a BCD representative has the opportunity to coordinate the meeting. 2. Project Review. The SCE-assigned reviewer evaluates the project documentation and conducts a pre-installation site inspection. The reviewer will evaluate and may revise the submitted estimated energy savings, DR load reduction, and/or incentive calculation. In addition, the reviewer will evaluate and may revise the submitted M&V plan. 3. Project Approval. If the PFS is approved by the CPM, SCE will send the consultant a Customer Agreement to be signed by the Customer that defines the estimated energy savings and DR load reduction (if DR measures exist), estimated incentive payment, and Terms & Conditions of the Program. After SCE's review and approval, an SCE signed copy will be sent to the customer and the incentive funding will be committed. Installation may start only after the Project Feasibility Study (PFS) has been approved by SCE. 4. Equipment Order. The consultant will provide Proof of Equipment Ordering by submitting approved documentation. Approved documentation must detail equipment being procured which includes: a customer's Purchase Order to a vendor for equipment, Bill of Lading (listing equipment), and/or Equipment Invoice. For Consultant s acting in the capacity as Prime Contractor for the customer, additional documentation will be required for Purchase Orders placed by the consultant on behalf of the customer. Such documentation may include Vendor s Equipment Proposal to the Prime Contractor. SCE, at their discretion may contact the Vendor to confirm status of equipment purchase. For turn-key projects, all labor charges and equipment costs must be separated on the documentation submitted. 5. Project Installation Report. The consultant submits a signed Installation Report package after all project measures have been installed, fully commissioned, and are fully operational. The Installation Report and all required documentation/data are required before review as stated in the SCE approved Project Feasibility Study. For DR measures, the consultant will include a completed Form 5.2 along with the Installation Report. Third-Party Implemented Programs Ver April 1,, 2011

7 6. Installation Review. After receiving the Installation Report package, the reviewer will evaluate the submittal package and may conduct a post-installation inspection to verify project installation and ensure the scope of work has not been altered from the agreed-upon PFS. For projects with DR measures, a verification/demonstration of the load shed capability and functionality of the equipment will be performed during the post-inspection. 7. Incentive Payment. After SCE approves the Installation Report, the designated payee receives the applicable incentive payment. 1.3 Eligibility for Participation Customer Eligibility The Standard PFP Third-Party Implemented Program is open to any non-residential customer who receives electric services from SCE and pays the Public Purpose Programs (PPP) surcharge on the electric meter for which the energy efficient equipment is proposed Project Eligibility In order for a project to be eligible for the Standard PFP Third-Party Implemented Program it must meet the following criteria: Any existing equipment required to establish the project baseline must be operating and available for inspection. New equipment/systems must not be installed. Installation cannot begin until SCE has the opportunity to inspect and approve the project. When non-utility supply is involved, any energy savings for which incentives are paid cannot exceed the net potential benefit provided to SCE. Non-utility supply, such as cogeneration or deliveries from another commodity supplier, does not qualify as usage from the utility (except for Direct Access customers or customers paying departing load fees for which SCE collects PPP surcharges). For DR eligibility, see Addendum A, Section 3.1 Under special circumstances, SCE may, at its sole discretion, waive certain project eligibility conditions. Furthermore, SCE reserves the right to allow authorized third-party vendors to pursue projects outside their primary NAICS codes in accordance with the following guidelines: 1. Projects outside of the primary NAICS codes per the Purchase Order may not exceed 49% of the total gross kwh and kw goals as set forth in the Purchase Order. 2. Consultant must notify SCE via SCE s Invoice and Reporting Tool project notes for customer projects having NAICS codes outside of their awarded Targeted Purchase Orders. 3. BCD representatives must be consulted when multiple Consultants are pursuing a single customer. The BCD representative will work with the customer and Consultants to decide the appropriate Consultant for the project. 4. When a vendor conflict arises from No. 1 above, SCE reserves the right to resolve the conflict based on the following guiding principles. Third-Party Implemented Programs Ver April 1,, 2011

8 BCD representative input; SCE customer preference; Consultant's historical relationship with SCE customer; Vendor's past performance in NAICS code; PFS submittal date as shown in SCE s Invoice and Reporting Tool; and/or Other relevant factors specific to the project. 1.4 Qualifying Energy Efficiency Measures Examples of Eligible Measures See the 2010 Statewide Customized Offering Policies and Procedures Manual (Addendum A) and the 2010 Statewide Deemed Offering Policies and Procedures Manual (Addendum B) Summary of Ineligible Measures Table 1-4 summarizes the types of measures that do not qualify for program incentive funds. This table provides an illustrative (not a comprehensive) list of ineligible efficiency measures. Table 1-4. Ineligible Measures T8 and T5 fluorescent lighting retrofits where the proposed equipment does not meet the CRI and Lamp Life requirements (Table 1-2) Compact fluorescent lamps not equipped with electronic ballasts. LED luminaries that are not listed or do not comply with the testing standards and requirements described in Appendix H. (The table of approved fixtures includes Energy Star rated, DLC approved, and Utility Approved fixtures) Screw-In CFLs Incandescent to incandescent retrofits (including halogen incandescent) Packaged or split system air conditioning units and Water Source Heat Pumps (WSHP) of any size. Technologies where there is no significant replacement/installation of equipment or modification to existing equipment, as determined by the Utility Administrator Measures that are not permanently installed and can be easily removed, as determined by the Utility Administrator Measures that save energy because of operational changes (not including control system modifications i.e. programming or re-programming) Cool roof systems Fuel-switching measures that do not meet the Utility s three-prong test Self-generation or cogeneration projects (i.e. measures that are replacing or installing self-generation or cogeneration equipment) Power correction or power conditioning equipment Pre-owned equipment that doesn t meet specific conditions (please contact the Utility Administrator for eligibility) Plug Load Sensors Power Controllers for Non-Perishable Refrigerated Coolers Third-Party Implemented Programs Ver April 1,, 2011

9 1.4.3 Non-Operational Existing Equipment Eligibility Non-operational, existing equipment replaced or retrofitted with higher efficiency equipment will be eligible for incentives, if: 1. All proposed equipment meets all other requirements of the program and exceed Title 24 or industry standards; 2. The baseline is Title 24 or industry standards of the proposed equipment type; and 3. Measure costs are the incremental costs above similarly configured standard efficiency equipment. Measure costs are the total costs associated with the installation of the measure. Sections to See the 2010 Statewide Customized Offering Policies and Procedures Manual (Addendum A) and the 2010 Statewide Deemed Offering Policies and Procedures Manual (Addendum B). 1.5 Direct Savings and Multiple Measures See the 2010 Statewide Customized Offering Policies and Procedures Manual (Addendum A) and the 2010 Statewide Deemed Offering Policies and Procedures Manual (Addendum B). 1.6 Aggregating Customer Project Sites See the 2010 Statewide Customized Offering Policies and Procedures Manual (Addendum A) and the 2010 Statewide Deemed Offering Policies and Procedures Manual (Addendum B). 1.7 Verification Requirements (EE) The Standard PFP Third-Party Implemented Program may require additional means of determining the energy savings from Customized Measures (Calculated) for a given project and verifying that those energy savings are achieved. Short-term monitoring, spot measurements, production data and/or other forms of verification will be required to confirm savings estimates The Measurement & Verification (M&V) Process A Measurement and Verification (M&V) Plan will include pre- and post-monitoring procedures/requirements. This M&V plan shall lay out how the baseline and post installation operating conditions and performance will be captured to generate the savings potential and how the consultant will verify the savings post installation. This M&V plan will be applied to Customized Measures (Calculated), as required by SCE and as outlined in the Statement of Work, Appendix D, Definition of Deemed and Customized Measures and in Task 3D, item 6. The M&V process begins after SCE's CPM approves the submitted PFS. The M&V process proceeds as follows: 1. M&V Plan Development The consultant develops a M&V plan as part of the submitted PFS based on the M&V options outlined in below. 2. PFS M&V Plan Approval The PFS, which includes the M&V plan, is evaluated by the reviewer and adjusted as necessary to verify the project's energy savings. In the course of the review the duration of pre- and post-m&v is determined. Third-Party Implemented Programs Ver April 1,, 2011

10 If post-m&v activities are required and exceed 60 calendar days in duration (extended M&V), the incentive payment will be paid in two payments (in a percentage split of 60/40). The reviewer submits the recommendation to the CPM for approval. 3. Project Installation. The consultant submits a signed Installation Report after all project measures have been installed, are fully commissioned, and are fully operational. Included in the Installation Report will be all required M&V data (M&V plans with duration of 60 calendar days or less) as stated in the approved PFS. M&V plans with extended durations that exceed 60 calendar days will require a second Installation Report at the conclusion of the M&V data collection. 4. Installation Report Review. After receiving the Installation Report, the reviewer will evaluate the package and conduct a post-installation inspection to verify project installation and ensure that the scope of work was not altered from the agreed-upon PFS. For projects with DR measures, a verification/demonstration of the load shed capability and functionality of the equipment will be performed during the post-inspection. 5. Incentive Payments. For projects with M&V durations of 60 calendar days or less, the Customer, upon approval of the Installation Report by the CPM, receives 100% of the Installation Report approved incentive. For projects with M&V durations exceeding 60 calendar days (extended M&V) the customer, upon approval of the Installation Report by the CPM, receives a first incentive payment of 60% of the Installation Report (IR1) estimated approved incentive. Upon completion of M&V plans exceeding 60 calendar days, the consultant will prepare and submit a Final Installation Report (IR2) to the reviewer for verification of final project savings and recommendation to the CPM. The savings in IR2 will be used to calculate the final project energy savings, customer incentive, and consultant payment. Incentive for DR Measures on projects with extended M&V will not be paid until SCE approval of IR2. 6. Project Performance Period. The consultant performs the agreed-upon M&V activities on the new operating equipment for the duration as stated in the CPM approved PFS M&V Options M&V procedures for the program generally derive from the 2009 International Performance Measurement and Verification Protocol (IPMVP). The four main options are: Option A - Measurement of Key Parameters. Predicts savings using short-term or continuous measurements of the key operating parameters and/or estimated values. Key performance parameters are defined as the factors that affect the energy use of the Energy Conservation Measures (ECM) systems and/or as the project s success. Estimated parameters can be based on manufacturer s specifications, historical data, or engineering judgment; however, backup documentation and/or justification of the estimated parameters is required. This option does not meet the requirements for a Measured Savings project. Option B - Metered Savings of Equipment or Systems. Involves short-term or continuous metering of the baseline and reporting periods to determine energy consumption. Measurements are usually taken at the device or system level. This option is preferred for calculated measures that are not industry standard and/or are new technologies because savings are determined for each efficiency measure/project separately. Pre- and postmeasurements are required to determine final energy savings. Option C - Whole Facility Analysis Using Regression Models. Involves comparing monthly billing data recorded by a utility meter or submeters for the whole facility or subfacility level before and after project installation, and analyzing the data to account for any variables, such as weather or occupancy levels. Energy savings can be determined once the variables are recognized and adjusted to match pre-installation conditions. Option D - Computer Simulation. Involves using software to create a simulated model of a building/project based on blueprints and/or site surveys. The model is calibrated by Third-Party Implemented Programs Ver April 1,, 2011

11 comparing it with end-use monitoring data or billing data. Models of the project are constructed for: the existing base case, a base case complying with minimum standards, and a case with the energy measures installed. 1.8 Incentive Payments The incentive payment amount for Customized Measures (Calculated) is based on a flat incentive rate (per kwh) applied to one year of energy (kwh) savings, plus a flat incentive rate (per peak kw) applied to the resultant permanent peak demand reduction. The incentive payment for Itemized Measures (Express Solutions) will be based on the deemed per-unit amount set forth by SCE. For Demand Response (DR) incentives, customers can receive reimbursements of up to $125 per kw of verified load reduction for the purchase and installation of technologies that reduce electricity use during peak periods. Customers can be eligible for up to $300 per kw of verified load reduction for the purchase and installation of technologies that reduce electricity use during peak periods without manual intervention (Automated Demand Response Auto DR). The savings approved in the Final Installation Report will be used to calculate the final project energy savings, customer incentive, and consultant payment, which might differ from the Customer Agreement. For measures requiring extended M&V plans that exceed 60 calendar days, 60% of the incentive is paid when the Installation Report is approved by the CPM; the remainder is paid at the end of the M&V plan duration once the Installation Report (IR2) is approved by the CPM. Incentive for DR Measures on project with extended M&V will not be paid until SCE approves the IR2. When reviewing the PFS, the reviewer and CPM will verify the consultant has designated the proper incentive category for each efficiency measure. As illustrated in the following table, the incentive rate depends on the type of efficiency measure installed (lighting, AC&R I, AC&R II, other equipment, or natural gas). Measure Category 2010 Customized Energy Savings Incentive Rates Annual Energy Savings Incentive Rate (kwh) Lighting (Fluorescent, Other Lighting, or Lighting $0.05 per kwh saved $100 / kw Controls) Air Conditioning and Refrigeration (AC&R) I $0.15 per kwh saved $100 / kw Peak Permanent peak demand reduction Incentive Rate (kw) Air Conditioning and Refrigeration (AC&R) II $0.09 per kwh saved $100 / kw Motors and Other Equipment $0.09 per kwh saved $100 / kw Natural Gas * 1.00 per Therm saved * Applicable only if there is a Co-Funding Agreement. Third-Party Implemented Programs Ver April 1,, 2011

12 1.8.1 Incentive Payment May Vary from Contracted Value Based on Performance The incentive may differ from the contract amount if actual equipment installation or operation differs from that described in the approved PFS. The incentive is based on actual performance and can vary. In some cases, the amount of the Final Installation Report incentive could be less than the amount that was paid at installation (60% payment). If this happens, the customer is responsible for reimbursing SCE for the difference. The CPM may approve an incentive that exceeds the contracted amount if one of the following conditions occurs: Increased Measure Costs -The actual installed costs are higher than the PFS estimated costs approved at the PFS review and there are no other limiting caps on the customer project site. The incentive for Customized Measures is capped at 50% of the actual measure costs. The incentive for Itemized Measures (Express Solutions) is paid at 100% of measure costs. DR incentives are capped at the actual reasonable cost of the installation and equipment not to exceed a $125 ($300 for Auto-DR) per verified kw. Incentives are paid on demonstrated load reduction capability during scheduled load verification tests. Installation of More Efficient Equipment - The customer has installed higher efficiency equipment than equipment indicated in the PFS and approved at the PFS review. If the scope of work changes after the contract is issued, but before the work is completed, notify the CPM immediately. Change in Production and/or Operating Hours - The customer increases its Production and/or Operating Hours from the baseline established at the time of the PFS review and approval. The CPM may approve an incentive that is less than the contracted amount if one of the following conditions occurs: Reduced Measure Costs The actual installed costs are less than the PFS estimated costs approved at the PFS review and there are no other limiting customer project site caps. The incentive for Customized Measures is capped at 50% of the actual measure costs. The incentive for Itemized Measures (Express Solutions) is paid at 100% of measure costs. DR incentives are capped at the actual reasonable cost of the installation and equipment not to exceed a $125 ($300 for Auto-DR) per verified kw. Reduced Scope of Work The customer installs less equipment (measures) or is not able to shed estimated load indicated in the PFS and approved at the PFS review. If the scope of work changes after the contract is issued, but before the work is completed, notify the CPM immediately. Different Specified Equipment The customer installs equipment that is different than the equipment specified in the approved PFS. Change in Production and/or Operating Hours The customer reduces its Production and/or Operating Hours from the baseline established at the time of the PFS review and approval. Third-Party Implemented Programs Ver April 1,, 2011

13 1.8.2 Incentive Limits First Come, First Served Program funds are available on a first-come, first-served basis. Funds are available until they are depleted or the program is terminated. Incentive funds are committed when a Customer Agreement is fully executed by both the customer and SCE. Incentives from other Programs See 2010 Statewide Customized Offering Policies and Procedures Manual (Addendum A) & 2010 Statewide Deemed Offering Policies and Procedures Manual (Addendum B). Customer Project Incentive Caps The Customized Measure incentives are limited to the lesser of the following: The incentive based on the energy savings and permanent peak demand reduction resulting from the installation of the new equipment on the meters for which the utility collects the PPP surcharge Note: kwh and kw savings are limited to the net potential benefit provided to the SCE during the period of performance. Incentive Caps are limited to 50% of the total project costs (100% for Advanced Lighting measures) for all installed measures. The consultant will provide the project cost and a description of the cost items with the Installation Report (IR1). The Itemized Measure incentive amount cannot exceed 100% of the measure costs. DR incentives are capped at the actual reasonable cost of the installation and equipment not to exceed $125 ($300 for Auto-DR) per verified kw. Under no circumstances will incentives for any type of measure exceed 100% of the measure costs. For measures that are considered both EE and DR measures, DR incentives can complement EE incentives up to and not to exceed 100% of the measure costs. The maximum incentive per site is 15% of the annual program incentive funds managed by SCE. Contact SCE for details. Project Costs Project costs that are outside of the Contractor s Scope of Work, as detailed in their Purchase Order, must be included in the Installation Report package. Project costs may include audits, design, engineering, construction, equipment and materials, overhead, tax, shipping, and/or labor. The cost of filling out documentation and conducting M&V will not be accepted as part of the project cost. Any costs not directly related to the project and/or installation of measures (such as but not limited to, bidding, marketing, Request for Proposal (RFP), or labor expenses) are not eligible. Customer Project Site A Customer Project Site is defined as a single free-standing building/structure, an individual utility meter, or a service account number where the retrofit or installation is taking place. For DR customer site information, see Addendum A, Section Payment Schedule For most projects, 100% of the approved incentive amount is paid after the CPM approves the Installation Report. For measures requiring extended M&V, refer to section Payments are made only after the CPM has approved the necessary submissions. Incentives for DR Measures on projects with extended M&V will not be paid until SCE approval of IR2. Third-Party Implemented Programs Ver April 1,, 2011

14 1.8.4 Payment Disbursement SCE calculates the incentive payment based on its review of the submitted paperwork or site inspection. The CPM will notify the consultant and customer in writing of the final approved incentive payment amount upon approval of the Final Installation Report (IR2), as applicable, and will begin processing the incentive check. If the consultant disputes the findings of the review, the consultant should notify the CPM as soon as possible. This should be done before the payee designated by the customer receives the incentive payment. As soon as the check is processed, SCE will mail it to the payee shown on the Customer Agreement. SCE will not allow an incentive to be paid to a Consultant or Contractor that has a Purchase Order in force with SCE. 1.9 Project Submission Process The process requires careful attention to detail. Incomplete or incorrect documentation will be returned, so it is highly recommended to follow the program instructions carefully. Consultants can call their CPM for assistance in completing their documentation and to obtain answers to specific program questions as well. To receive incentives, the consultant must perform certain actions which require submitting certain forms, documents, and/or reports as stated in section and further defined below. The significant project steps are: 1. Project Submission 2. Project Review 3. Project Approval 4. Equipment Order 5. Project Installation Report 6. Installation Review 7. Incentive Payment Project Submission To initiate the process, the consultant first submits a Project Scoping Document to the CPM. Once the Project Scoping Document is approved, the consultant is responsible for submitting both a Program Agreement (PA) to the CPM and a Project Feasibility Study (PFS) through SCE s Invoice and Reporting Tool.. The Project Scoping Document will provide the CPM the following information: A description of the project and its specific measures, as well as the project s goals and objectives; An explanation of the customers business and what part of the customer s business process will be impacted by the installation/retrofit; A description of the Consultant s plan, including form of project measurement, measurement period timetable, engineering format for savings estimate, and how much time will be involved from approval to installation; And also, a description of all deliverables that come from the successful completion of the project. And also, at a minimum, the PFS is to include the following information: Description of the recommended equipment/measures to be installed; Third-Party Implemented Programs Ver April 1,, 2011

15 Analysis of current energy consumption; Estimated electricity energy savings (gross kwh), demand reduction (gross kw), and cost savings resulting from the Project; Estimated Project installation cost; Estimated Project completion date; and Cost-effectiveness (including estimated customer incentives): For Itemized measures, savings and Incentives/Rebates are calculated using a deemed per-unit amount times the number of units installed for each measure type. Measures for Deemed Incentives will follow the procedures and protocols consistent with those used by other SCE programs (Express Solutions, formerly known as the Express Efficiency model). For Custom Measures, savings are calculated using established engineering calculations and input values particular to the facility. The custom Measure Incentives/Rebates are calculated using a fixed dollar amount per gross EE kwh and EE kw saved and DR kw reduced. The specific Incentive/Rebate rates are shown in Appendix E (Deliverable Schedule). Calculated Incentives Measures will follow the procedures and protocols consistent with those used by other SCE programs (formerly known as Standard Performance Contracting program, DR s TA&TI program, etc.). Note: For DR Measures, kw load reductions are generally calculated as follows: DR kw = (CSSB RTE) CSSB is the Customer Summer Specific Baseline Recorded Test Energy (RTE) is the actual recorded kwh/hour of the Customer s demand during a test event (kwh/hr). In some cases, such as lighting, the RTE will be stipulated kw. Testing is typically two hours in duration. SCE will determine the appropriate baseline values and dispatchable load reduction used in calculating incentive payments if the CSSB is not representative of the customer s summer peak demand. Funding Results: Comparison of various funding sources. Equipment specifications, if applicable, that meet the Program requirements; Steps that the consultant will take to facilitate installation of the project and to assist the customer in obtaining the Incentives; Consultant information; Customer information (including service account number); Project and site eligibility information; and A proposed Measurement and Verification (M&V) Plan including pre- and post-monitoring procedures/requirements Project Review Review of the PFS is targeted to be completed within 25 business days. Complex and multiplesite projects may require more time. PFS review will begin after a complete package is received. Third-Party Implemented Programs Ver April 1,, 2011

16 The reviewer evaluates the project documentation. The reviewer will evaluate and may revise the submitted energy savings and/or incentive calculation. The SCE assigned reviewer will contact the consultant to schedule a pre-installation site inspection within five (5) days. At the sole discretion of SCE, alternative methods of determining pre-installation conditions such as photos, SCE personnel verification, and/or specific documentation. Deemed only projects that have a total Customer Incentive less than $7000 may not receive a pre-inspection at the sole discretion of SCE. The purpose of this inspection is to take measurements when necessary and verify that: The PFS accurately reflects the existing project baseline; All existing equipment listed in the PFS is still operational (if not, the associated measures may be deemed ineligible); and Installation has not yet occurred (if field preparations for installation have begun, the project may be deemed ineligible). The consultant must be flexible when scheduling inspections with customers and assist in providing complete access to customer project sites. A representative of the consultant who is familiar with the project will attend the inspection. When electrical measurements are necessary, the customer may be required to disrupt equipment operation, open any electrical connection boxes, and/or install current and power transducers, as needed. If the inspection cannot be completed in a timely manner, the project may fail the inspection. If the project fails the inspection, the CPM may decline the PFS. If multiple site inspections are conducted, the CPM may assess the consultant a re-inspection fee. The reviewer will verify that the M&V process is sufficient to verify the energy savings for the project scope. The reviewer may revise the submitted M&V plan in collaboration with the consultant. The reviewer will contact the consultant if additional information or clarification is needed to verify the project scope. The CPM will provide the results of the PFS to the consultant as follows: Approved. See section 1.9.3, Project Approval, below for next steps On Hold by CPM. The CPM may place the review on hold if circumstances (for example, no work paper) do not allow for the project to proceed. Upon resolution of the issues, the CPM will resume the review process. Suspended. The CPM may suspend review when repeated attempts to obtain information are ignored. The consultant has 30 calendar days to respond or the PFS may be withdrawn and will need to be resubmitted. Declined. The CPM may decline a PFS if any of the following conditions apply: The project fails inspection; The PFS is missing information that the consultant is unable to provide; The existing equipment has been removed before inspection; The project otherwise fails to meet program criteria; The PFS does not include an acceptable M&V plan; Customer not eligible for DR Measures. Note: A consultant is allowed to resubmit a PFS that was declined. Third-Party Implemented Programs Ver April 1,, 2011

17 1.9.3 Project Approval Installation can only commence after SCE has approved the PFS. Often, if contract execution is approved by the CPM, incentive funding for the project will be committed. SCE will send a Customer Agreement to the consultant who will obtain the customer's signature on the Agreement. The Agreement defines the estimated energy savings and load reduction capability, estimated incentive payment, and Terms & Conditions of the program. Upon SCE s review and approval, a copy signed by SCE will be uploaded to SCE s Invoice and Reporting Tool for consultant to give to the customer. Installation includes, but is not limited to, decommissioning and/or removal of existing equipment, demolition, facility alterations to prepare for new equipment, and installation of new equipment. If the scope of the project changes substantially from what was identified in the approved PFS, the project may need to be resubmitted. Substantial changes include significant modifications to the proposed equipment type, size, quantity, configuration, or if the project expands to include additional retrofits. The revised project scope and supporting calculations are subject to additional review and will require a revised PFS before removal of existing equipment/systems or the installation of the replacement equipment/systems. Exceptions may be granted at SCE's discretion. All projects must be installed and fully operational one year from PFS approval. If the project is not fully installed and operational by the specified installation deadline, the agreement is subject to cancellation. All projects must be installed and fully operational by October 31, 2012, or two months before the program cycle end date, whichever is earlier. Extensions may be granted at SCE s discretion Equipment Ordering The consultant is to provide Proof of Equipment Ordering by submitting approved documentation, including: Customer Purchase Order to vendor for equipment; Bill of Lading (listing equipment) and/or; Equipment Invoice (not including labor). See Appendix B for EEG Cost Documentation requirements Project Installation Report The consultant submits a signed Installation Report package after all project measures have been installed, fully commissioned, and fully operational. The Installation Report and all required documentation/data are required before review, as stated in the SCE approved PFS. At a minimum, the Installation Report package must include the following information: Project Description; Date of Installation; Project Completion Certificate (SCE standard form); A discussion of the pre- and post-m&v results; Project Documentation (includes, but is not limited to: a customer's Purchase Order to a vendor, a Bill of Lading (listing equipment), and/or an equipment invoice; Third-Party Implemented Programs Ver April 1,, 2011

18 Energy savings (gross kwh) and demand reductions (gross kw) (which may be different from the SCE-executed Customer Agreement); Customer Signatures; Consultant Signature; Attachments; Final energy savings (gross EE kwh) and demand reductions (gross EE kw and DR kw) calculations based on post-installation information; and Incentive/Rebate calculations based on post-installation information. Note: EE incentives are calculated first, the DR incentives are then revised, if necessary, when EE kw reduces the available load for DR. The components of each IR will vary depending on whether the installed Measures are Customized Measures (with calculated savings), Itemized Measures (with deemed savings) and/or DR Measures Installation Review The Installation Review approval is the basis for initiating the incentive payment. After receiving the Installation Report package, the reviewer evaluates the submittal package and conducts a post-installation inspection to verify project installation and ensure the scope of work was not altered from the agreed-upon project. At the sole discretion of SCE, alternative methods of determining post-installation conditions such as photos, SCE personnel verification, and/or specific documentation. Deemed only projects that have a total Customer Incentive less than $7000 may not receive a post-inspection at the sole discretion of SCE. The consultant submits an Installation Report to SCE through SCE s Invoice and Reporting Tool only after the project has been installed, fully commissioned, and fully operational. The Installation Report must be submitted for a post-installation inspection to be scheduled. This Installation Report should confirm the estimated energy savings and the load reduction capability. The consultant will provide data and analysis from the M&V plan that was implemented before and/or after installation. The consultant must submit the Installation Report within 60 calendar days of equipment installation. The target time for evaluating the completed and submitted Installation Report by the reviewer is within 25 business days. Complex and multiple site projects may take longer. After receiving the Installation Report, the reviewer will schedule a post-installation inspection with the consultant at the customer project site as soon as possible. The reviewer will verify that the new equipment (project) is completely installed and operational, and may conduct measurements, if applicable. For projects with DR measures, during the post-installation inspection, a load verification test is scheduled to demonstrate load reduction capability. For projects with DR measures, a verification/demonstration of the load shed capability and functionality of the DR equipment will be performed during the post-inspection. The consultant and the customer must be flexible in scheduling the inspections and providing complete access to customer project sites. A representative of the consultant who is familiar with the project must attend the inspection. When electrical measurements are necessary, the customer may be required to interrupt equipment operation, open any electrical connection boxes, and/or install current and power Third-Party Implemented Programs Ver April 1,, 2011

19 transducers, as needed. If the inspection cannot be completed in a timely manner, the CPM may fail the inspection. If the project fails the inspection, the CPM may decline the project. If multiple site inspections are conducted, the CPM may assess the consultant for a re-inspection fee. The CPM will provide the results of the Installation Report to the consultant as follows: Approved. A Project Completion letter will be uploaded to SCE s Invoice and Reporting Tool stating that the project has been approved for incentive payment processing under the terms of the Third-Party Implemented Program. On Hold. The review may be placed on hold if circumstances do not allow for the project to proceed through the Installation Report review process. After all issues are resolved, the CPM will resume the review process. Suspended. The review may be suspended when repeated attempts for information are ignored. At this point, the consultant has 30 calendar days to respond or the CPM may cancel the project and the project will have to be resubmitted. Declined. A project may be declined if any of the following conditions apply: The installation is not consistent with the PFS; The project fails inspection; The Installation Report is missing information that the consultant or customer is unwilling or unable to provide; The installed equipment is not fully commissioned and fully operational before inspection; or The project otherwise fails to meet program criteria. For projects requiring extended Measurement & Verification (M&V) exceeding 60 Calendar days, the final Installation Report (IR2) comes at the end of the M&V plan period. After the new equipment/project has been operating for the predetermined M&V plan period, the consultant submits the IR2. The IR2 confirms that the equipment is still in operation as installed and/or notes any changes (for example, equipment pulled out of service, changed operating hours, etc.). After receiving the Installation Report, or at any time during the extended M&V plan period, the CPM may request a site inspection, subject to the same provisions as the post-installation inspection. If the project fails the inspection, the CPM may decline the project. If multiple site inspections are conducted the CPM may assess a re-inspection fee to the consultant. If the inspection reveals that the M&V activities are different from those described in the M&V plan, SCE may deny any further incentive payments and may request repayment of the previous incentive payment. Based on evaluation of the IR2, review results, the CPM will notify the consultant in writing of the approved incentive amount to be processed. Incentives for DR Measures on projects with extended M&V will not be paid until SCE approval of IR2. A project may be denied further incentive funds if: The installation is not consistent with the PFS (fails inspection), or The project otherwise fails to meet program criteria. If an Installation Report is not approved, SCE may terminate the project and release the incentive funding committed for the project. Third-Party Implemented Programs Ver April 1,, 2011

20 SCE has the discretion to make the final decision on project energy savings. All disagreements between the Reviewer, Consultant, and/or Customer in regards to the final project energy savings shall be ultimately decided by SCE Incentive Payment After SCE approves the Installation Review, the customer or designated payee receives the applicable incentive payment. For projects requiring extended M&V, SCE will pay the final installment of the Energy Savings Incentive (the remaining 40% or whatever adjusted amount is properly due) after approval of the final IR2. Incentives for DR Measures on projects with extended M&V will not be paid until after SCE approves the IR2. If measurements show that the installation achieved greater energy savings than predicted, SCE will pay the additional energy savings incentive amount as verified in the final Installation Report. Similarly, if the installation achieved lower energy savings than anticipated, the customer or designated payee will not receive the full incentive, and is responsible for returning to SCE any overpayment that may have been made in the first installment Other Important Terms and Conditions By participating in the program, customers, project sponsors, and authorized agents agree to the following terms and conditions: All parties consent to participate in any evaluation of the program. The CPUC or its representatives may contact participants to answer questions regarding their experience with the statewide Customized Offering and/or request a site visit. All participants agree to comply with such program evaluations. SCE expressly reserves all its rights, which include, but are not limited to, the right to use others to perform or supply work of the type covered by the Statewide Customized Offering, as well as the unrestricted right to contract with others to perform the work or to perform any such work itself. SCE may employ third-party engineering firms to conduct site inspections, review calculations, and recommend project status. The information is considered confidential and is not shared with any entity outside the application, other than the CPUC upon its request. The CPUC has determined that the IOUs will administer the program through the end of The CPUC has not decided who will administer the program thereafter. Therefore, after December 31, 2012, existing projects could be assigned to a new administrator. In their applicable agreements, consultants and customers must agree to terms and conditions that allow such transfers. Notice of Public Record Because the program is funded by the PPP surcharge, participants should be aware that, Statewide Customized Offering projects are a matter of public record and may be reviewed and evaluated by the CPUC upon program commencement. The estimated total project costs will be part of the public record. As necessary, the IOUs may discuss projects and disclose project information among program administrators (SCE, SDG&E, and PG&E) to ensure statewide consistency and eligibility. However, projects are not shared or available for viewing by other customers or sponsors. Information about specific projects is not shared with parties not included on the application. SCE is not liable to any customer, consultant, authorized agent or other party resulting from any public disclosure to the CPUC for purposes of Measurement and Evaluation (M&E). Third-Party Implemented Programs Ver April 1,, 2011

21 Contract Termination SCE may terminate Third-Party Implemented contracts under certain conditions including, but not limited to, the following: SCE determines that significant information was purposely withheld or was falsely stated in any submitted documentation; The project fails to be installed, fully commissioned, or fully operational before the installation deadline; The consultant requests withdrawal from the program; The customer requests withdrawal from the program. Third-Party Implemented Programs Ver April 1,, 2011

22 Appendix A: Advanced Lighting Technical Requirements As part of the Advanced Lighting program offered under certain 3 rd Party programs, the following technical requirements describe the performance required for light-emitting diode (LED) measures to qualify under the various Tiered incentives as described in Appendix A of the Purchase Order. Interior Lighting Tier 0 Tier I Tier II Tier III Minimum Luminaire Efficacy (By Project Commitment Year) 50 lm/w 60 lm/w 70 lm/w Product Warranty 5 years 5 years 5 years Color Rendering Index (CQS Recommended) Power Factor Based on Energy Star or Minimum Based on Energy Star Center Beam Candle Minimum Output DLC Power Recommended Potential Effective Useful Life Requirements* 35,000 hr 2700K, 3000K, 3500K, 4000K, 4500K, 5000K Correlated Color Temperature Recommended 0 W (Exception luminaires with integral occupancy, motion, photo controls or individually addressable Maximum Off state Power fixtures with external control: 0.5 W) Total Harmonic Distortion < 20% * If a lamp does not fit into an Energy Star Category, DLC requirements will be used. Exterior Lighting Tier I Tier II Tier III Minimum Luminaire Efficacy 2010: 70 lm/w 80 lm/w 90 lm/w (By Project Commitment Year) 2011: 80 lm/w 90 lm/w 100 lm/w 2012: 90 lm/w 100 lm/w 115 lm/w Product Warranty 7 years Color Rendering Index Power Factor 0.9 Minimum Output Based on Energy Star Program Requirements for Solid State Lighting Luminaires Eligibility Criteria Proposed Category A Additions Outdoor Area & Parking Garage July 1, 2009 Potential Effective Useful Life Correlated Color Temperature 50,000 hr 2700K, 3000K, 3500K, 4000K, 4500K, 5000K, 6000K Recommended 0 W (Exception luminaires with integral occupancy, motion, photocontrols or individually addressable fixtures with external control: 0.5 Maximum Off State Power W) Total Harmonic Distortion < 20% Third-Party Implemented Programs Ver April 1,, 2011

23 APPENDIX B: PROJECT COST DOCUMENTATION Project costs must be reported for all Custom Calculation energy efficiency projects at a solution code level (SCE). Allowable project costs may include audits, design, engineering, construction, equipment and materials, overhead, tax, shipping, and labor on a per measure basis. Labor costs can be contractor or in-house if proof of direct project hours and costs are provided. Incremental or Whole Project Cost For replacement on burn out (ROB) of the participant s existing appliance/measure, the measure cost is the additional (incremental) cost of the equipment/measure relative to the standard (less efficient) appliance/measure that would have been installed, without the financial incentive. Measures involving baseline equipment that is beyond its effective useful life (considered burntout even if it still operates) or is non-existent (i.e. New Load) are evaluated on an incremental basis. Non-operational non-essential equipment (such as air-side economizers) may be an exception to the incremental cost rule if certain conditions are met. Please refer to the Customized Program Manual. Measures where the baseline equipment is operational and not beyond its useful life are evaluated on full measure cost basis. Full measure/equipment costs are only used in instances where the program causes the participant(s) to do what they would not have done anyway ( Early Retirement or Retrofit Add on) (or at least not in the near future, e.g., 5 years), such as replace a working air conditioner with a more efficient one. Preferred Measure Pre Install Documentation for Project Costs The preferred costs basis is actual project costs data for the EE portion of the project broken down at a measure level. In some cases, this data may not be readily available at this level. For incremental costs, to the extent possible, shall be taken from the Database for Energy Efficiency Resources (DEER). Measures not covered by DEER should use another method for incremental cost evaluation, including project bid options that contain this level of data. For full measure/equipment costs, acceptable methods for project cost documentation, given in order of descending preference, are: 1. Quote (PA) 2. Costing Estimation Documentation (RS Means, etc.) 3. Trade Study (like quotes, etc.)deer 4. Provide an invoice or multiple invoices containing the cost breakdown per end use (lighting, motors, pumping, etc.) Then allocate the cost breakdown for each solution code (analyze the percent of kwh savings that each solution code contributed to the total end use kwh savings and use this to approximate the cost). Post Install Project Cost After the completion of a project installation, an overall project invoice containing the entire project cost must be submitted. Preferably, this invoice should include only the energy efficiency Third-Party Implemented Programs Ver April 1,, 2011

24 portion of the project. For projects containing multiple solution codes, each invoice should be itemized by solution code. In cases where this is not possible or difficult to obtain, the following will be accepted, in addition to the overall project invoice: A purchase order for each solution code. The combination of these purchase orders shall total up to the energy efficiency cost value provided in the overall project invoice. Use RS Means or DEER to approximate the cost breakdown per solution code. The RS Means or DEER Analysis should also reconcile to the total energy efficiency portion of the completed project. Provide an invoice or multiple invoices containing the cost breakdown per end use (lighting, motors, pumping, etc.) Then allocate the cost breakdown for each solution code (analyze the percent of kwh savings that each solution code contributed to the total end use kwh savings and use this to approximate the cost). Third-Party Implemented Programs Ver April 1,, 2011

25 APPENDIX C: INDUSTRIAL / COMMERCIAL CUSTOMIZED PROCESS FLOW Third-Party Implemented Programs Ver April 1,, 2011

26 Third-Party Implemented Programs Ver April 1,, 2011

27 Section 2: Offering Overview and Policies for Turnkey Third- Party Implemented Program 2.1 Introduction How the Turnkey Program Works Eligibility for Participation Qualifying Energy Efficiency Measures Measure Cost Aggregating Customer Project Project Cost Limits How to Participate Authorization Form Review Project Completion Report Review Project Approval Invoicing Other Important Terms and Conditions Third-Party Implemented Programs Ver February, 16, 2010

28 2.1 Introduction The Third-Party Implemented Turnkey Program provides services to replace or upgrade to high-efficiency equipment at little or no cost to the customer. Southern California Edison (SCE) administers the Turnkey Program offering within its service territory. SCE determines the prescribed energy efficiency measures to be offered. Non-residential customers, who wish to receive services, must execute an Authorization Form for participation in the program and installation of eligible energy efficiency measures. The 2010 enrollment began on January 1, Completed projects must be submitted by November 15, Projects are accepted throughout the program cycle or until SCE's funds are fully committed. Please check with SCE for exact enrollment periods. Designed for Non-Residential Customers - The Turnkey Program serves non-residential Customers who receive energy services from SCE and pay into the Public Purpose Program (PPP) surcharge. Offering Documentation - Program services are based on careful adherence to offering requirements, please read the entire 2010 Turnkey Program Manual before starting a project. 2.2 How the Turnkey Program Works The Main Players The program involves five key parties: 1. Customer - A non-residential ratepayer, who meets program-specific eligibility requirements, is located within SCE s service territory, and is receiving electric services from SCE. 2. Contract Program Manager (CPM) - The CPM manages all aspects of the program and makes final decisions. 3. Consultant - The consultant is authorized by SCE and is responsible for identifying projects, making program presentations, perform audits, completing work orders, administering customer satisfaction surveys, and performing all steps required to ensure the viability (energy efficiency) of submitted projects. The consultant is also responsible for ensuring that all the required documentation is submitted correctly and that the project is completed. 4. Inspector - The Inspector is responsible for performing both pre and post-inspections to verify existing equipment and the installation of energy efficiency measures, respectively. 5. Utility Administrator - SCE administers the program in its service territory The Basic Process The Turnkey Program works as follows: Customer Enrollment The consult has the customer execute the Customer Authorization Form to trigger enrollment in the Program and submits the form through SCE s Invoice and Reporting Tool Project Submission The consultant submits an Authorization Summary Form through SCE s Invoice and Reporting Tool. Project Review SCE reviews the Authorization Summary Form and may conduct a preinspection. Third-Party Implemented Programs Ver February, 16, 2010

29 Authorization to Proceed Upon SCE approval, SCE will issue an authorization to proceed through SCE s Invoice and Reporting Tool. Project Installation The consultant performs the work authorized. Project Completion Report The consultant will complete the Project Completion Report (PCR) and submit through SCE s Invoice and Reporting Tool. Project Completion Review SCE will review the PCR and may conduct a post-installation site inspection. Project Invoiced After the PCR is approved, the consultant may invoice SCE through SCE s Invoice and Reporting Tool. 2.3 Eligibility for Participation Customer Eligibility The Turnkey Program is open to those Non-residential customers who (1) meet the program specific eligibility (that is, NAICS), (2) receive electric services from SCE, and (3) pay the PPP surcharge on the electric utility bill on which the energy efficient equipment is proposed Project Eligibility In order for the project to be eligible for the Turnkey Program, it must meet the following criteria: Any existing equipment required to establish the project baseline must be operating and available for inspection. New equipment/systems must not be installed. Installation cannot begin until SCE has the opportunity to inspect and approve the project. Any installed equipment must be fully commissioned and fully operational or the equipment may be deemed ineligible. When non-utility supply is involved, any energy savings for which rebates are paid cannot exceed the net potential benefit provided to the Utility (SCE). Non-utility supply, such as cogeneration or deliveries from another commodity supplier, does not qualify as usage from the utility (except for Direct Access customers or customers paying departing load fees for which SCE collects PPP surcharges). 2.4 Qualifying Energy Efficiency Measures The Turnkey Program accepts a wide variety of prescriptive energy-saving measures. All measures must meet the following criteria as SCE deems reasonable: 1. Are Utility Approved Measures. In order for a measure to qualify for the Program it must be approved by SCE. Refer to the Program s Program Management Plan for allowable measure details. 2. Meet Measure Terms and Conditions. Any measure within the Program must comply with measure terms and conditions. Terms and conditions are subject to change. 3. Utilize New Equipment. Only new equipment installations qualify unless explicitly stated otherwise by SCE. Third-Party Implemented Programs Ver February, 16, 2010

30 4. Replace Existing Equipment Proposed equipment must be replacing existing equipment, unless otherwise explicitly communicated by SCE. 5. Cannot Replace Previously Retrofitted Equipment Retrofit projects where proposed equipment installed is the same, as the equipment being replaced does not qualify, unless explicitly communicated by SCE. For example, a customer who has an existing Lighting Occupancy Sensor cannot receive a Lighting Occupancy Sensor from the program. 6. Operational Period The Customer must provide Utility with 100% of the related energy benefits for the effective useful life of the product or for a period of five years from receipt of installation, whichever is less. SCE may request a refund of the prorated amount of the measure cost based on the actual period of time for which the energy benefits did not materialize. 7. Measures Cannot Be Submitted Through Other Rebate Programs Any measures installed through the program cannot be applied through multiple California energy efficiency incentive or rebate programs. Other California end user energy efficiency programs include, but are not limited to, any program offered by or through the PG&E, SCE, SDG&E, SoCalGas, California Energy Commission (CEC), and California Public Utilities Commission (CPUC), including PPP funded local programs, third-party programs, American Recovery Reinvestment Act (ARRA), or local government partnerships. Customers cannot receive rebates from more than one energy efficiency program for the same measures. 2.5 Measure Cost Material, labor, and other costs are included in the measure costs of the equipment installed. For certain measures, a co-payment required by the customer may apply. Refer to Appendix G of the Program s Purchase Order for measure cost details. 2.6 Aggregating Customer Project A Turnkey Program project may be comprised of a single energy efficiency measure or a variety of measures. The consultant may choose to include multiple buildings at a project site (such as a school campus with multiple buildings) within a single project. The following requirements apply: The same customer must own and/or occupy the buildings. There is no limit on the number of buildings that can be aggregated. Each building can have entirely different measures. If the same measures are installed across multiple buildings, the consultant must indicate the measure quantities and location by building. This information must be included in the Project Completion Report (PCR). When combining buildings and measures into a single project, the consultant should be aware that such projects will not be reviewed or approved until paperwork on all the individual buildings and measures is complete. If a large project is being implemented in phases, submit phases as individual projects. Third-Party Implemented Programs Ver February, 16, 2010

31 2.7 Project Cost Limits The project amount invoiced is based on the number of measures approved at the prescribed per unit rates, as determined by SCE First Come, First Served Program funds are available on a first-come, first-served basis. Projects may not be accepted after Turnkey Program funds are fully committed Rebates from other Programs Any measures included in the project cannot be applied through multiple California energy efficiency incentive or rebate programs. Other California end user energy efficiency programs include, but are not limited to, any program offered by or through the PG&E, SCE, SDG&E, SoCal Gas, the CEC, and the CPUC, including PPP funded local programs, third-party programs, or local government partnerships. Customers cannot receive services from more than one energy efficiency program for the same measures Project Caps The maximum project cost per site per program cycle is $100,000. Contact SCE for more information. 2.8 How to Participate Customers can contact either SCE or the contractor for participation assistance and information about the program Overview of Documentation To receive Turnkey Program services, the consultant must perform certain actions, and submit documentation and supporting materials at specific project milestones: 1. Execution of the Customer Authorization Form (CAF) The execution of the Customer Authorization Form enrolls the Customer in the Program to receive program services. The CAF includes customer information (including service account number) and the terms and conditions of the Customer to enroll in the Program. Included in the terms and conditions of the CAF, it provides the consultant access to the Customer site to receive preliminary program services including an energy survey of prescribed measure opportunities eligible within the Program. 2. Execution of Authorization Form (AF) The Authorization Summary Form (ASF) describes the project and commits the customer to install certain program measures and sets forth each party s responsibilities. The ASF includes customer information (including service account number), project site information, site eligibility, description of proposed measures, energy and demand savings estimates, and participant costs or co-payments (if applicable), as deemed necessary by SCE. 3. Project Completion Report (PCR) The consultant will assemble all the necessary information (the Authorization Summary Form, co-payment confirmation, etc.) in a PCR to SCE after the new equipment is installed and fully commissioned and fully operational. The PCR includes date of installation, measures installed, energy and demand savings, customer verification of installation and co-payments, and customer satisfaction survey, as deemed necessary by SCE. SCE cannot schedule a post-inspection without a submitted PCR. Third-Party Implemented Programs Ver February, 16, 2010

32 2.8.2 Submission of Program Documentation All Turnkey Program documentation must be submitted through SCE s Invoice and Reporting Tool in the following ways: On paper - hardcopy forms must be uploaded as attachments; and Electronically through an interactive website the consultant must input key data fields such as service account number, customer information, and measure quantity. 2.9 Authorization Form Review The Authorization Form and Authorization Summary Form review is the basis for the validation of customer eligibility, commitment of funds, and authorization to proceed Pre-Installation Site Inspection (if required) Upon receipt of the ASF, SCE may schedule a pre-installation inspection at the customer project site. If a pre-installation inspection is required, SCE will verify that the base case equipment is installed and operational or the project may fail inspection. As necessary, the consultant must assist in scheduling such inspections and provide complete access to customer project sites. A representative of the customer and/or consultant who is familiar with the project, e.g. the facility manager or other responsible representative of the customer, should attend the inspection. If the inspection cannot be completed in a timely manner, the project may fail inspection. If the project fails the inspection, SCE may cancel the project. Also, SCE may assess a fee for any re-inspection Project Completion Report Review The PCR review is the basis for verifying implemented measures and project approval Post-Installation Site Inspection (if required) Upon receipt of the PCR, SCE may schedule a post-installation inspection at the customer project site. If a post-installation inspection is required, SCE will verify that the new measures are installed, fully commissioned and fully operational or the project may fail inspection. As necessary, the consultant must assist in scheduling such inspections and provide complete access to customer project sites. A representative of the customer and/or consultant who is familiar with the project, e.g. the facility manager or other responsible representative of the customer, should attend the inspection. If the inspection cannot be completed in a timely manner, the project may fail inspection. If the project fails the inspection, SCE may cancel the project. Also, SCE may assess a fee if reinspections are conducted Project Approval The project approval is the basis for initiating the invoice submission. Third-Party Implemented Programs Ver February, 16, 2010

33 Notice of Project Completion Report Review Results SCE will provide the consultant notice through SCE s Invoice and Reporting Tool of the PCR review results, as follows: Approved The approval notice through SCE s Invoice and Reporting Tool informs the consultant that the project has been approved for invoice processing under the terms of the Turnkey Program. The approval notice will also inform the consultant of the approved project amount. Declined A project may be declined if any of the following conditions apply: Installation is not consistent with the PCR; Project fails inspection; Project is missing information that the consultant is unable to provide; Project otherwise fails to meet program criteria. If the consultant disputes the review's findings, the consultant should notify SCE as soon as possible Invoicing Billing Schedule For most projects, 100% of the approved project amount is paid after SCE reviews and approves the invoice for processing. The invoice payment is generally processed within 30 calendar days after the completed invoice is received, including all required documentation Payment Disbursement As soon as the invoice is processed, SCE will mail payment to the payee designated on the invoice Other Important Terms and Conditions By virtue of participation in the program, customers, consultants, and authorized agents agree to the following terms and conditions: All parties consent to participate in any evaluation of the program. The CPUC or its representatives may contact participants to answer questions regarding their experience with the Turnkey Program and/or to request a site visit. All participants agree to comply with such program evaluations. SCE as the Utility Administrator, expressly reserve all rights, which include, but are not limited to, the right to use others to perform or supply work of the type covered by the Turnkey Program, as well as the unrestricted right to contract with others to perform the work or to perform any such work itself. SCE may employ third-party engineering firms to conduct site inspections, review calculations, and make recommendations for project status. The information reviewed is considered confidential and is not shared with any party outside the application, other than the CPUC as requested. The CPUC has determined that the IOUs will administer the program through the end of 2012, but has not decided who will administer the program thereafter. Therefore, after December 31, 2012, existing program commitments might be assigned to a new Third-Party Implemented Programs Ver February, 16, 2010

34 Administrator. In their Program Agreements, applicants must agree to terms and conditions allowing for such a transfer. Third-Party Implemented Programs Ver February, 16, 2010

35 Notice of Public Record Because the program is funded by the PGC OR PPP surcharge, Turnkey Program projects are a matter of public record and may be reviewed and evaluated by the CPUC upon program commencement. The estimated total project costs will be part of the public record. As necessary, the IOUs may discuss projects and disclose project information among program administrators (PG&E, SCE, SDG&E, and SoCal Gas) to ensure statewide consistency and eligibility. However, project information is not shared and is not available to other customers or sponsors. Information about specific projects is not disclosed to parties who are not included on the Application. SCE is not liable to any consultant, customer, authorized agent or other party as a result of any public disclosure to the CPUC for the purpose of Measurement and Evaluation. Project Termination Turnkey Program projects may be terminated by SCE under the following conditions: SCE determines that significant information was purposely withheld or falsely stated in the project documentation. The project fails to be installed, fully commissioned, or fully operational. The customer requests withdrawal from the program. Third-Party Implemented Programs Ver February, 16, 2010

36 Addendum A 2010 Statewide Customized Offering Procedures Manual for Business

37 Addendum B 2010 Statewide Deemed Offering Procedures Manual for Business

38 Addendum A 2010 Statewide Customized Offering Procedures Manual for Business

39 2010 Statewide Customized Offering Procedures Manual for Business Summary of Offering Rules Summary of Offering Rules The Statewide Customized Offering provides cash incentive payments for business energy efficiency projects involving the installation of new, high-efficiency equipment or systems (measures). A project may consist of the retrofit of existing equipment/systems or the installation of equipment associated with new or added load. The Offering is open to all commercial, industrial and agricultural Customers, regardless of size or project scope. A customized approach is used to estimate the energy savings and incentive. Incentives are paid based on the quantities of kwh and peak kw or therms saved resulting from the installation of the new equipment or system. (Incentives for gas savings are available only for projects in Pacific Gas & Electric Company and San Diego Gas & Electric natural gas service territories.) Incentives for peak demand reduction (peak KW) are paid on the peak demand permanently reduced as a result of the project. While a project may realize a substantial amount of total demand reduction, the incentive is based only on the peak demand reduced (per the CPUC Mandated DEER Peak definition). Under the Statewide Customized Offering, pre and post-inspections may be required and the Applicant follows a multi-step application process using forms supplied specifically for the Customized program. The forms are submitted to the Utility Administrator for review and approval prior to installing the equipment. The Utility Administrator will work closely with the Project Sponsor/Authorized Agent or Customer to facilitate the review and payment process. Participation in the Statewide Customized Offering is entirely voluntary. Applicants incur all costs associated with preparing an application, installing equipment, conducting measurement and verification activities, and otherwise reviewing or executing the Offering agreement. In return, Customers (or otherwise indicated payee) receive cash payments and acquire highefficiency equipment that will help lower energy costs and reduce energy consumption. Receipt of incentive funds depends on careful adherence to Offering policies. The following sections briefly summarize the Statewide Customized program. For additional information contact your Utility Administrator. A. OFFERING DEFINITIONS Utility Administrator Pacific Gas & Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), or Southern California Edison Company (SCE), whichever Utility provides natural gas and/or electric services to the Customer Project Site. Project Sponsor An entity that is authorized to enter into a Project Agreement with a Utility Administrator. The Project Sponsor is responsible for ensuring all the required paperwork is submitted correctly and for ensuring the project is completed. For PG&E and SDG&E, customers can serve as their own Project Sponsor, i.e. self-sponsor, or may elect to have a third party enter into the agreement on their behalf. For SCE, a third party who enters into the agreement on the customer s behalf is known as the Authorized Agent. February 25, Version 1.1

40 2010 Statewide Customized Offering Procedures Manual for Business Summary of Offering Rules Customer An eligible non-residential ratepayer who is applying for incentives through the Statewide Customized Offering.Project. Energy Savings Measures An energy saving measure ( measure ) is a new, high-efficiency equipment or systems. This can involve installations associated with retrofits and replacements of existing equipment, increased load, or new load. Measures that are replacing or installing cogeneration equipment are not eligible. Measures cannot be removed or installed until the Utility can conduct an on-site inspection. Measures must exceed applicable government and/or industry minimum efficiency standards to qualify and must operate and produce verifiable energy savings for at least five years. Incentives are paid for direct energy savings only; energy savings due to interactive effects such as the reduced cooling load due to installing more efficient lamps are not eligible for incentives. B. ESTIMATING ENERGY SAVINGS, PEAK DEMAND SAVINGS, AND INCENTIVES The Customized Approach determines the amount of the incentive based on the annual kwh, CPUC Mandated DEER Peak kw reduction, and/or therms saved. Energy savings may be estimated using the estimating tools provided in the Customized software or the Applicant may elect to use their own engineering calculations. The Customized Offering pays incentives based on kwh and kw or therm savings achieved above and beyond minimum industry or government standards. To calculate savings, the Applicant uses Title 24 or government minimum standards as the baseline. If there are no government standards for a particular measure, current industry practices are used to establish baseline performance. All energy savings estimates are reviewed and approved by the Utility Administrator as part of the application process. Additional information may be required to verify the inputs and variables used to determine the incentive. Occasionally, energy savings cannot be substantiated to the satisfaction of the Utility. In these cases the Utility Administrator may require the Measured Savings approach or measurement and verification (M&V) of energy use before and up to 2 years after implementation of the energy saving measure. If the Utility determines that M&V is necessary to accurately determine the energy savings, the Applicant must prepare and submit an M&V plan to the Utility Administrator for review and approval. Should M&V be required, then the Offering incentive payment will be increased by 10 percent to help defray the M&V costs, not to exceed $50,000. C. INCENTIVES For Customized measures, the incentive payment amount is based on a flat rate (per kwh or therm) applied to one year of energy (kwh or therms) savings and the rate per CPUC Mandated DEER peak KW reduced. The final incentive amount for measures that require M&V is based on the measured performance and can vary between 0 and 110 percent of the amount originally indicated on the agreement. February 25, Version 1.1

41 2010 Statewide Customized Offering Procedures Manual for Business Summary of Offering Rules The incentive rates are based on the applicable measure category as shown in Table C-1 below. Table C-1. Incentive Rates Measure Category Lighting Includes interior and exterior fluorescent, HID or other energy efficient lighting, and lighting controls or EMS systems Air Conditioning and Refrigeration (AC&R) I Includes major system replacements for air conditioning and refrigeration systems Annual Energy Savings Incentive Rate (kwh) DEER Peak Demand Reduction Incentive Rate (kw) $0.05 per kwh saved $100 / kw $0.15 per kwh saved $100 / kw Air Conditioning and Refrigeration (AC&R) II $0.09 per kwh saved $100 / kw Includes reduced operation or reduced load such as controls, building shell retrofits, or components retrofits Other Equipment $0.09 per kwh saved $100 / kw Includes motors, variable speed drives, compressed air systems, EMS controls, and process load Natural Gas* Includes natural gas fueled boilers, furnaces, and oxidizers $1.00 per therm saved * Natural Gas Measures are Applicable only in PG&E and SDG&E service territories Project Costs Limitations Customized Measure incentives are limited to 50 percent of the total project costs. Please refer to Section for project cost information. Incentive Amount Limitations The maximum incentive that can be paid to an individual project site in a calendar year is limited to 15 percent of the annual customized incentive funds managed by the specific Utility Administrator. Please refer to section Incentive Payment Schedule After project measure(s) are installed, incentive payments are made. 100 percent of the approved incentive amount is paid after installation of the project measure(s) is confirmed (Installation Review is approved). For projects requiring M&V in SDG&E and SCE service territories, 60 percent of the approved estimated incentive is paid after the installation of the project measure(s) is confirmed. The balance of the incentive amount for the measure(s) installed is determined based on the M&V results and is paid upon receipt and approval of the final report (Operating Report). For projects requiring M&V in PG&E service territory, 100 percent of the approved incentive amount (up to 110%) is paid after the approval of the final report (Operating Report). February 25, Version 1.1

42 2010 Statewide Customized Offering Procedures Manual for Business Summary of Offering Rules D. HOW TO APPLY Decommissioning of existing equipment, construction, or implementation of an energy saving measure may NOT begin prior to Application approval To apply for incentives under the Statewide Customized program, the Applicant follows a multistep process using forms specific to the Utility program. These forms can be completed manually using the hand-written (PDF) forms, or can be completed electronically using Excel forms downloaded from the Utility Administrator s website. The application process consists of the following two or three steps depending on whether or not M&V is required. First Milestone - Project Application The Applicant prepares and submits a Project Application, which includes Customer information, site information, data regarding specific measures to be installed and the estimated energy savings. The Utility Administrator reviews the Application and may schedule an inspection of the existing equipment. The Utility Administrator may distribute the Project Application to a thirdparty engineering firm for inspection and review of the energy savings calculations. Second Milestone Installation For SDG&E and SCE service territories, the Project Sponsor or Authorized Agent/Customer submits a signed Installation Report after all project measure(s) have been installed and are fully commissioned and fully operational. The Installation report should have all invoices or cost documentation attached, and include post-monitoring data (if required in the original application approval). For PG&E service territory, the Project Sponsor notifies the Utility Administrator and submits invoices after all project measure(s) have been installed and are fully commissioned and fully operational. If any changes have occurred the Project Sponsor submits revised calculations as well. The Utility Administrator may schedule an inspection of the installed equipment prior to approval. The Utility Administrator issues a payment upon approval of the Installation Review for the project measure(s) installed. Refer to Section Third Milestone - Operating Report Projects requiring M&V ONLY For projects requiring M&V, the Applicant must prepare and submit an Operating Report at the end of the predetermined performance period. The Operating Report is prepared using the results of the M&V activities during the first year or two of operation and confirms the project is still operating as installed. The Utility Administrator reviews the Operating Report and may choose to inspect the installed equipment prior to approval. The Utility Administrator calculates the final incentive amount based on the M&V results for the project measure(s) installed and issues the final incentive payment. Applicants are eligible to receive up to an additional 10 percent based on the final Utility-approved savings. Refer to Section IMPORTANT DATES AND DEADLINES: Offering opens: January 1, 2010 Application deadline: December 31, 2010 or before all of the Utility s customized incentive funds are committed. Installation deadline: For SCE and SDG&E service territories, all projects must be installed and fully operational one year from PA approval. For PG&E service territory, all projects must be installed and fully operational by June 1, February 25, Version 1.1

43 2010 Statewide Customized Offering Procedures Manual for Business Utility Administrator: Pacific Gas and Electric San Diego Gas & Electric Southern California Edison The 2010 Customized Offering is a statewide program administered by Southern California Edison (SCE), San Diego Gas & Electric (SDG&E), and Pacific Gas and Electric (PG&E) in their respective territories. The program rules, incentive rates, incentive limits, and program requirements are identical for all three Utilities. The program packaging and individual offering may vary slightly between the Utilities. Subject to all applicable federal, state, and local laws, and CPUC rulings, the Utility Administrators reserve the right to approve otherwise eligible EE projects by waiving project steps and/or sequencing guidelines. If the Utility Administrators determines program influence and can establish appropriate baseline and post operating conditions, with or without a pre- or post-inspection and including energy savings calculations, the Utility Administrators reserve the right to make appropriate and reasonable business decisions regarding project eligibility and approvals

44 Contents of This Manual Introduction Summary of Program Rules Section 1 Offering Overview and Policies Section 2 Estimating Energy Savings and Incentives Section 3 Software Instructions Section 4 (PG&E Only) Demand Response Program Overview and Policies Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Appendix H Sample Statewide Customized Offering Agreement Table of Standard Fixture Wattages and Sample Lighting Table Minimum Equipment Efficiency Standards Building Descriptions and Climate Zones Engineering Calculation Worksheet First Time User s Guide (Customized Software) Measurement and Verification Table of Approved LED Lighting and Utility Approval Process

45 Section 1: Offering Overview and Policies 1.1 Introduction How the Statewide Customized Offering Works Eligibility for Participation Qualifying Energy Efficiency Measures Direct Savings and Multiple Measures Aggregating Customer Project Sites Verification Requirements Incentive Payments How to Apply Application Review Project Installation Installation Review Operating Report (Measured Savings only) Other Important Terms and Conditions... 24

46 1.1 Introduction The 2010 Statewide Customized Offering provides financial incentives for the installation of highefficiency equipment or systems. Non-Residential Customers that install energy-saving technology are eligible for energy efficiency incentives based on calculated energy savings and permanent peak demand reduction. (Incentives for gas-related energy savings are eligible only in Pacific Gas & Electric Company and San Diego Gas & Electric Company natural gas service territories.) Incentives are paid on the energy savings and permanent peak demand reduction above and beyond baseline energy performance, which include state-mandated codes, federal-mandated codes, industry-accepted performance standards, or other baseline energy performance standards as determined by the Utility Administrator. Non-Residential Customers who wish to receive Utility incentives must submit a project application for the installation of eligible energy efficiency measure(s) through the Statewide Customized Offering process. The 2010 enrollment begins January 1 st Applications for the 2010 enrollment period are accepted until December 31, 2010 or until the Utility s customized incentive funds are fully committed. Administered by Utilities. The Statewide Customized Offering is administered by three of California s Investor-Owned Utilities (CIOU) Pacific Gas & Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE). Designed for Non-Residential Customers. The Statewide Customized Offering serves Non- Residential Customers who receive energy services from CIOUs and pay into the Public Purpose Program (PPP) surcharge. Offering Materials. Incentive payments are based on careful adherence to offering requirements, please read the entire Section 1: Offering Overview and Policies of the 2010 Customized Statewide Procedures Manual for Business before starting a customized project. Changes for Refer to Table 1-1 below for a list of specific Offering changes for Table 1-1. What s New in 2010 The Statewide Customized Offering has been re-designed to offer a more comprehensive and consistent method for Utility customers to participate in statewide energy efficiency retrofit incentives. Please visit the following websites for detailed information: SCE SDG&E PG&E - February 25, Version 1.1

47 1.2 How the Statewide Customized Offering Works The Main Players The Statewide Customized Offering involves three key parties: 1. Customer (Applicant) An eligible non-residential ratepayer who is applying for incentives through the Statewide Customized Offering. 2. Project Sponsor An entity that is authorized to enter into a Project Agreement with a Utility Administrator. The Project Sponsor is responsible for ensuring all the required paperwork is submitted correctly and for ensuring the project is completed. For PG&E and SDG&E, customers can serve as their own Project Sponsor, i.e. selfsponsor, or may elect to have a third party enter into the agreement on their behalf. For SCE, a third party who enters into the agreement on the customer s behalf is known as the Authorized Agent. 3. Utility Administrator PG&E, SDG&E, or SCE, whichever provides natural gas and/or electric services to the Customer Project Site The Basic Process The Statewide Customized Offering works as follows: 1. Application Submission. The Project Sponsor submits an application to the Utility Administrator. The application submission contains project details and any other supporting documentation as deemed necessary by the Utility Administrator. 2. Application Review. The Utility Administrator-assigned Reviewer evaluates the application and conducts a pre-installation site inspection. At the Utility Administrator s sole discretion the pre-installation site inspection may be waived. The Reviewer will evaluate and may revise the submitted energy savings and/or incentive calculation. The Utility Administrator may require the Project Sponsor to submit an M&V plan, if the Utility Administrator determines at its sole discretion that an M&V process is appropriate for the proposed project. 3. Application Approval. If the application is approved by the Utility Administrator, incentive funding for the project is reserved and the Project Sponsor and Utility Administrator enter into a Project Agreement that defines the energy savings and incentive payment. For SCE and SDG&E, funding for the project is not reserved until a Project Agreement is fully executed by both parties. 4. Project Installation. For SDG&E and SCE service territories, the Project Sponsor submits a signed Installation Report and invoices after all project measure(s) have been installed and are fully commissioned and fully operational. For PG&E service territory, the Project Sponsor notifies the Utility Administrator in writing and submits invoices after all project measure(s) have been installed and are fully commissioned and fully operational. 5. Installation Review. Upon receipt of Installation Report (SCE and SDG&E), or Installation notification (PG&E), the Reviewer will evaluate the submittal package and conduct a postinstallation inspection to verify project installation and ensure the scope of work has not altered from the agreed-upon project. Based on special circumstances the Utility Administrator, at their sole discretion, may waive the post-installation site inspection. February 25, Version 1.1

48 6. Incentive Payment. Upon Utility Administrator s approval of the Installation Review, the indicated Payee receives the incentive payment. In most circumstances, Applicants are paid 100 percent of the approved incentive upon project completion and Installation Review approval. 1.3 Eligibility for Participation Customer Eligibility The Statewide Customized Offering is open to all Non-Residential Customers who (1) receive natural gas and/or electric services from PG&E, SCE, or SDG&E and (2) pay the PPP surcharge on the gas or electric meter on which the energy efficient equipment is proposed Project Sponsor and Authorized Agent Eligibility Customers may self-sponsor their own projects or projects can be sponsored by outside parties such as energy efficiency service providers (EESPs), which include energy service companies (ESCOs), lighting installers, HVAC contractors, consulting engineers, energy management companies or other entities. The Utility Administrators do not qualify Project Sponsors or Authorized Agents; the Customer bears full responsibility for selecting a Project Sponsor or Authorized Agent if one is desired Project Eligibility In order for the project to be eligible for the Statewide Customized Offering it must meet the following criteria: 1. Any existing equipment required to establish the project baseline must be operating and available for inspection. 2. New equipment/systems must not be installed. Installation cannot begin until the Utility Administrator has the opportunity to inspect and approve the project. 3. When Non-Utility supply is involved, any energy savings for which incentives are paid cannot exceed the net potential benefit provided to the Utility. Non-utility supply, such as cogeneration or deliveries from another commodity supplier, does not qualify as usage from the utility (with the exception of Direct Access customers or customers paying departing load fees for which the utility collects PPP surcharges). Under special circumstances, the Utility Administrator, at their sole discretion, may waive certain project eligibility conditions. 1.4 Qualifying Energy Efficiency Measures The Statewide Customized Offering accepts a wide variety of energy-saving projects, including a pre-defined list of common measures as well as custom-designed measures. All projects must meet the following criteria: 1. Must Exceed Baseline Energy Performance. Incentives are paid on the energy savings and demand reduction above and beyond baseline energy performance, which include state-mandated codes, federal-mandated codes, industry-accepted performance standards, or other baseline energy performance standards as determined by the Utility Administrator. 2. Must Meet CPUC Mandated DEER Peak Demand Definition. Incentives for demand reduction (kw) are paid only on permanent electrical demand which is reduced during peak periods, as defined by Database for Energy Efficiency Resources (DEER) (Refer to Manual Section 1.4.8). February 25, Version 1.1

49 3. Must Operate at Least Five Years. The Project Agreement requires that the new equipment or system retrofit must guarantee energy savings for the effective useful life of the product or for a period of five years, whichever is less. 4. Measures Cannot Overlap Other Incentive Programs. Any measures included in the application cannot be applied through multiple California energy efficiency incentive or rebate programs. Gas and Electric components should be considered separately. Other California end user energy efficiency programs include, but are not limited to, any program offered by or through Southern California Gas Company, PG&E, SDG&E, SCE, California Energy Commission (CEC), and California Public Utilities Commission (CPUC), including PPP funded local programs, third-party programs, or local government partnerships. Applicants cannot receive incentives from more than one energy efficiency program for the same measures. Contact the Utility Administrator for further details. 5. Baseline Equipment Must Be Decommissioned and Removed. The baseline equipment must be decommissioned and removed from site prior to Installation Review approval. Under certain circumstances and subject to Utility Administrator discretion, baseline equipment may be kept for backup purposes. Additional documentation may be required in these cases. 6. LED Fixtures. LED fixtures must be specifically listed in or comply with the testing standards and requirements described in Appendix H. Table H1 includes approved EnergyStar rated, DesignLights Consortium (DLC) qualified, and Utility qualified LED fixtures. EnergyStar - DesignLights Consortium Integral LED Lamps (SCE only). Integral LED lamps must be specifically listed in or comply with the testing standards and requirements described in Appendix H. Table I1 includes DLC and SCE qualified integral LED lamps 8. T8 and T5 Fluorescent Lamps and Ballasts. T8 and T5 Fluorescent Lamps must meet the Color Rendering Index (CRI) and Rated Lamp Life Standards described in Table 1-2. Additionally, T8 and T5 fluorescent ballasts must exhibit total harmonic distortion (THD) less than or equal to 20% and a power factor greater than 0.9. Table 1-2 Eligible Fluorescent Lamp Characteristics Lamp Type & Size Ballast Type CRI Minimum Rated Lamp Life (3 hrs/start) T8 2-ft, 3-ft, 4-ft Programmed Start/ Programmed Rapid-start >= 80 24,000 hours T8 All Sizes Instant Start >= 80 18,000 hours T5 All Sizes Programmed Start/ Programmed Rapid-start >= 82 20,000 hours Examples of Eligible Measures If a measure is not specifically excluded by the eligibility conditions and the Applicant can provide documentation supporting energy savings beyond baseline energy performance standards, then it may be eligible for Statewide Customized Offering incentives (subject to the approval of the Utility Administrator). Table 1-3 provides an illustrative (not a comprehensive) list of qualifying efficiency measures. Please note that the category of a given measure is important because the category determines the incentive rate that will be paid (see Section 1.8 of this manual). February 25, Version 1.1

50 Air conditioning and refrigeration related measures that qualify for the AC&R I incentive rate category generally include those retrofits that improve the efficiency of the A/C system (i.e. kw/ton improvements). Evaporative cooler and evaporative condenser retrofits are also classified under the AC&R I incentive rate category. Air conditioning and refrigeration measures that involve reduced operation or reduced load such as controls, building shell retrofits, or components retrofits (e.g. motors, pumps, component VSDs or fans) are classified under the AC&R II incentive rate category. System retrofits involving both AC&R I and AC&R II measures will be incented at $0.15/kWh for the complete system measure. Table 1-3. Examples of Eligible Measures Air Conditioning and Refrigeration I Energy $0.15 / kwh Peak Demand $100 / kw Air Conditioning and Refrigeration II Energy - $0.09 / kwh Peak Demand - $100 / kw High-efficiency chillers replacements Packaged air conditioners and heat pumps in PG&E and SDG&E service territories (>760,000 Btu/hr or 63.3 tons) Variable Speed Drive installations on existing air conditioning or refrigeration compressor motors. Air conditioning complete subsystem replacements (evaporative condensers, air-cooled condensers, cooling towers, or compressors) Refrigeration complete subsystem replacements (condensers, evaporators, cooling towers, or compressors) Constant air volume to variable air volume conversions Chiller heat reclaim Evaporative cooling unit installations Evaporative pre-cooling unit installations Indirect evaporative cooling (single stage and dual stage) Heat transfer (including heat pumps) to heat sinks, such as ground source cooling in air-conditioned buildings A/C compressor replacements Data center free cooling Refrigeration floating head controller installations Controls and energy management systems for HVAC or refrigeration equipment Variable speed drives on fans (including supply fans, exhaust fans, and cooling tower fans) Variable speed drives on pump motors (including chilled water and cooling tower pumps) Fan, pump, and/or motor replacements Refrigeration evaporator fan controls Insulating chilled water, condenser water, or refrigerant pipes Insulating cool air ducts Insulating storage tanks Demand control ventilation installation (CO 2 sensors) Installation of high-speed cold storage doors Air Conditioner air-side or water-side economizer installations on units not already equipped with a 100% economizer Building shell improvements Cooling tower upgrades Refrigerated case doors February 25, Version 1.1

51 Lighting Energy - $0.05 / kwh Peak Demand - $100 / kw Motors and Other Equipment Energy - $0.09 / kwh Peak Demand - $100 / kw Natural Gas Measures* $1.00 / Therm Interior and exterior lighting retrofits including linear fluorescent, HID, induction, cold cathode and compact fluorescent lamps (not including screw-in lamps) LED luminaire retrofits utilizing qualified fixtures (see Appendix H for qualification process and table of current qualified fixtures) (SCE-only) Screw-in cold cathode and Integral LED Lamp retrofits utilizing qualified lamps - see Appendix H for LED qualification process and table of current qualified LED lamps. High efficiency signage or architectural lighting Lighting control systems LED traffic lights LED exit signs (SCE and PG&E only) Day lighting controls and dimmable ballast De-lamping measures performed as part of an integral lighting efficiency upgrade Motor upgrades (all sizes) Variable-speed drives (e.g., on industrial fans, industrial pumps, and on air compressor motors) Industrial process applications Industrial fan replacements Industrial pump replacements Trimming impellers on industrial fans and pumps Projects improving building hot water efficiency Water flow controls resulting in electric savings Exhaust hood and fan projects Window films and glazing Dairy Vacuum Pumps/ Variable-speed drives (VSDs) Pulse cooling devices for injection molding machines Injection molding machines Professional wet cleaning equipment CO sensors for parking garages Rapid Close Doors Thermal Oxidizers Boiler or furnace replacements Boiler heat recovery Boiler economizers * Natural Gas measures applicable only in PG&E and SDG&E service territories February 25, Version 1.1

52 1.4.2 Summary of Ineligible Measures Table 1-4 summarizes the types of measures that do not qualify for program incentive funds. This table provides an illustrative (not a comprehensive) list of ineligible efficiency measures. Table 1-4. Ineligible Measures T8 and T5 fluorescent lighting retrofits where the proposed equipment does not meet the CRI and Lamp Life requirements (Table 1-2) Compact fluorescent lamps not equipped with electronic ballasts. LED luminaires that are not listed or do not comply with the testing standards and requirements described in Appendix H. (The table of approved fixtures includes EnergyStar rated, DLC approved, and Utility Approved fixtures) Screw-In CFLs (PG&E and SDG&E Only) LED replacement lamps and screw-in lamps of any type Incandescent to incandescent retrofits (including halogen incandescent) Packaged or split system air conditioning units, Air-cooled chillers, and Water Source Heat Pumps (WSHP) of any size (SCE) or units less than 63.3 Tons (SDG&E and PG&E) Technologies where there is no significant replacement/installation of equipment or modification to existing equipment, as determined by the Utility Administrator Measures that are not permanently installed and can be easily removed, as determined by the Utility Administrator Measures that save energy because of operational changes Cool roof systems Fuel-switching measures that do not meet the Utility s three-prong test Self-generation or cogeneration projects (i.e. measures that are replacing or installing self-generation or cogeneration equipment) Repair or maintenance projects. Exceptions are granted for specific measures listed in section Re-commissioning activities Power correction or power conditioning equipment Pre-owned equipment that doesn t meet specific conditions (please contact the Utility Administrator for eligibility) Plug Load Sensors Power Controllers for Non-Perishable Refrigerated Coolers Non-Operational Existing Equipment Eligibility Non-operational, existing equipment replaced with higher efficiency equipment will be eligible for incentives, if: 1. All proposed equipment meets all other requirements of the program and exceed Title 24 or industry standards; 2. The baseline is Title 24 or industry standards of the proposed equipment type; and 3. Measure costs are the incremental costs above similarly configured standard efficiency equipment. The following measures are also eligible for incentives if the equipment has not been fully operational for at least one year. Measure costs are the total costs associated with the installation of the measure. February 25, Version 1.1

53 Table 1-5. Eligible Non-Operational Measures Failed Steam traps (not available in SCE territory) Failed HVAC air-side economizers Failed Boiler economizers (not available in SCE territory) New Load Project Eligibility The 2010 Statewide Customized Offering pays incentives for the installation of new, highefficiency equipment to meet the expanded process needs of an existing facility or to accommodate new production loads. New Construction projects will continue to be eligible for the Statewide New Construction Offering. Projects that involve modifying an existing operation, structure or process due to growth or expansion that do not qualify for Statewide New Construction Offering may be reviewed by the Statewide Customized Offering. This includes projects that are not direct, one-for-one replacements and enables the calculated process to capture and account for efficient increases in electric load. Customers are required to have an existing Utility service account with at least 12 months of billing and usage history. The following guidelines designate projects that fall under the Statewide Customized Offering. In special circumstance, exceptions may be granted as deemed reasonable by the Utility Administrator: no walls are removed or constructed, or no significant impact to existing structures are affected to accommodate the new equipment no change in facility function/occupancy type footprint of the facility remains the same process enhancements where equipment or operations are moved, and minimal accommodations are made (e.g. building a new workstation to accommodate for a process change) Projects that involve a gut rehab, expansion, complete remodel, demolition or renovation where architectural design assistance is involved would fall under the Statewide New Construction Offering Examples of new load projects: A refrigerated warehouse owner adds compressors and condensers to increase cooling capacity. A plastics manufacturer installs a new injection-molding machine to accommodate a new production run. An industrial facility adds additional air compressors to facilitate a new production line in the existing site. A drilling company installs a new, state-of-the art oil well to pump oil into an existing pipeline. All eligible equipment must meet all other eligibility conditions set forth by the Utility Administrator. Measure costs are evaluated as the incremental costs above and beyond similarly configured standard-efficiency equipment. February 25, Version 1.1

54 1.4.5 Increased Load / Production Measures Project Eligibility The 2010 Statewide Customized Offering may pay incentives for retrofit of existing equipment/systems with larger high-efficiency equipment/systems to accommodate increased load/production. In general, the incentives for these measures will be based on the postinstallation load/production rate. The energy savings will be calculated as: Eligible Energy Savings = (Baseline Efficiency Proposed Efficiency) * Proposed Production Rate or Load * Proposed Operating Hours Examples of increased load measures: A building owner replaces a dedicated package rooftop HVAC unit with a larger more efficient unit to accommodate increased load of an existing computer room. A hospital energy manager replaces a 300 ton chiller with a high efficiency 450 ton chiller to accommodate and meet increased cooling needs. A water district replaces a 150 HP pump/motor with a premium efficiency 200 HP pump/motor to respond to increased system demand. All equipment must meet all other requirements of the program, set forth by the Utility Administrator, and exceed Title 24 or minimum industry standards to be eligible. The baseline is calculated at Title 24 or current minimum standards Fuel Substitution Measures Fuel substitution (fuel switching) measures involve retrofit projects where all or a portion of the existing energy use is converted from either electricity to natural gas or natural gas to electricity. Fuel substitutions measures are calculated using a baseline energy performance of the replacement fuel. Incentives are paid on the energy savings above and beyond the baseline energy performance standards as determined by the Utility Administrator. For SCE service territory, only fuel substitution measures involving retrofit projects where all or a portion of the existing energy use is converted from natural gas to electricity are eligible; incentives are not paid for switching from gas to electric but for installing premium efficiency electric equipment. Fuel-substitution measures must reduce the need for source energy use without degrading environmental quality. Fuel-substitution measures must pass a three-prong test to be eligible for customized incentives. These tests include a source-btu comparison, a benefit-cost ratio calculation, and an environmental impact analysis. The Utility Administrator will perform these analyses Early Retirement Feature The early retirement feature is designed to accelerate the retirement of older, less efficient equipment with new, high efficiency replacements. Eligible measures are subject to an expanded definition of energy savings which may result in a larger incentive than would be possible using the traditional approach. For PG&E and SDG&E service territories, this approach can be applied to air conditioning units (packaged AC, heat pumps and chillers), and electrical motors with five or more years of remaining useful life. For SCE service territory, the Early Retirement calculation procedure can be applied only to water-cooled chillers and electrical motors with five or more years of remaining useful life. The new units must exceed baseline energy performance standards as determined by the Utility Administrator. The early retirement feature credits savings from the original efficiency to the proposed efficiency (depending on size and type). February 25, Version 1.1

55 Applicants MUST use the Statewide Customized Offering software to determine the energy savings and incentive calculations for early retirement projects. Manual forms are not available for this type of measure. If you need assistance with the software, please contact your Utility Administrator. For the HVAC equipment, DOE-2 hourly simulation will be used to account for the weather variations. For the motor replacement, the Motor Master algorithms will be used. The remaining useful life for motors and HVAC is determined from ASHRAE s published data on equipment life (see below). Table 1-6 lists the earliest year equipment must have been built or overhauled to qualify for the Early Retirement feature. A table of efficiencies for the various types and sizes (based on averages for a typical unit) is included in Appendix C. The baseline efficiencies for air conditioning equipment are developed from earlier versions of Title 24, while the baseline efficiencies for motors are developed from earlier NEMA standards. Table 1-6. Early Retirement Equipment Eligibility Equipment Useful Life Year Built or Later** Overhauled Useful Life Overhauled Since Motor Packaged Units* Chillers - Reciprocating Chillers - Centrifugal *Useful life from ASHRAE, **For equipment not overhauled or rewound To evaluate a project for Early Retirement, the Applicant uses the Customized program software. Upon selecting one of the measure types eligible for the Early Retirement feature, the participant enters the age of equipment, its size and other parameters, which the software uses to determine if the measure qualifies for Early Retirement. If the measure qualifies for Early Retirement, the participant enters the necessary inputs for the measure, such as the operating hours, location (HVAC measures), electrical spot measurements (motors) and other required parameters. The Customized software will then estimate the energy savings and the incentive amounts. The incentive rates are the same as the standard approach. Below is a simplified energy savings calculation for 10-year old, 350-ton water-cooled centrifugal chiller. Assumptions Existing Chiller 350 Ton, Efficiency = COP, 8,760 hrs per year Proposed Chiller 350 Ton, Efficiency = 6.39 COP, 8,760 hrs per year Title 24 Standard Efficiency = 6.1; COP Useful Life = 23 years Calculations Baseline Energy Usage = 2,167,292 kwh Energy Usage at Standard Efficiency = 2,108,115 kwh Proposed Energy Usage = 2,077,122 kwh kwh savings = 2,167,292 kwh 2,108,115 kwh = 90,170 kwh Energy Savings Incentive = 90,170 kwh x $0.15 /kwh = $13,526 Permanent demand reduction Incentive = determined by the Customized estimation tool, based on chiller operation Using the standard approach, this measure would have earned a kwh incentive of $4,648, compared to a kwh incentive of $13,526 using Early Retirement. February 25, Version 1.1

56 1.4.8 DEER Peak Permanent peak demand reduction Calculations The CPUC has determined that peak demand reduction will be evaluated using the DEER Peak approach. The CPUC mandated approach more closely ties demand reduction to grid level impact. The complexity of estimating CPUC Mandated Peak varies based on the measure type, measure operation, and level of data available. The Statewide Customized Offering software offers the most accurate DEER calculations for weather dependant measures, so customers are encouraged to use the tool. All other calculations are subject to a rigorous review by IOUs engineers and consultants CPUC Mandated DEER Peak Definition The CPUC Mandated DEER Peak method is summarized from Version 4 of California s Energy Efficiency Policy Manual as the average grid level impact for a measure between 2:00 p.m. and 5:00 p.m. during the three consecutive weekday periods containing the weekday temperature with the hottest temperature of the year. The CPUC Mandated DEER Peak periods are further defined by individual climate zones. Because the definition is based on average grid-level impacts it has been determined that all measures must use the predefined heat wave periods (table 1-7). Table 1-7. CPUC Mandated DEER Peak Periods by CZ Climate Zone Start Date End Date 1 30-Sep 2-Oct 2 22-Jul 24-Jul 3 17-Jul 19-Jul 4 17-Jul 19-Jul 5 3-Sep 5-Sep 6 9-Jul 11-July 7 9-Sep 11-Sep 8 23-Sep 25-Sep 9 6-Aug 8-Aug 10 8-Jul 10-Jul Jul 2-Aug 12 5-Aug 7-Aug Aug 16-Aug 14 9-Jul 11-Jul Jul 1-Aug 16 6-Aug 8-Aug The periods are based on a typical year using a 1991 calendar. If the CPUC Mandated peak period falls on a weekend, the proceeding three day period will be utilized. February 25, Version 1.1

57 1.5 Direct Savings and Multiple Measures A project must achieve significant energy savings, subject to the following provisions: 1. Direct Savings Only. Only direct energy savings not indirect energy savings due to interactive effects count in determining a project s incentive. Direct savings occur as the primary purpose of the retrofit. Indirect energy savings from interactive effects are those savings that occur from other than the primary purpose of the retrofit. For example, highefficiency lighting typically lowers the air conditioning load. However, only the avoided lighting energy, not the avoided air conditioning energy, would count as energy savings in determining the energy savings and incentives for a lighting project. 2. Either Single or Multiple Measures. A Statewide Customized Offering project may comprise of a single energy efficiency measure (e.g., a boiler replacement or chiller plant upgrade) or a variety of measures (e.g., an air handler motor upgrade and a variable-speed drive, plus a day lighting measure). 1.6 Aggregating Customer Project Sites A Statewide Customized Offering application may comprise of a single energy efficiency measure or a variety of measures. A Project Sponsor may choose to include multiple project sites in a single project application. The following requirements apply: The same Customer must own and/or occupy the Customer Project Sites. Please refer to Section (Customer Project Site Caps) to review the total incentive amount available per Customer Project Site. There is no limit on the number of sites that can be aggregated. The sites can have entirely different measures, operating hours, energy use profiles, and M&V plans (if required). If it is determined by the Utility Administrator that a measure needs to use the M&V Process, it will be separated from the non-m&v measures on a second application for processing. If the same measure is applied for at different sites, they must be considered separate measures, one for each site. The measure cost must be determined for each individual site. Project Sites for which the Customer is applying for incentives must be in the same service territory as the Utility Administrator. When combining sites and measures into a single application, the Applicant should be aware that such projects will not be reviewed, or approved, or receive payment until paperwork on all the individual sites and measures is complete. If the project is being implemented in phases, consider submitting individual applications. 1.7 Verification Requirements As a performance-contracting offer, the Statewide Customized Offering may require additional means of determining the energy savings from a given project and verifying that those energy savings have been achieved. The verification requirements have been greatly simplified over the years so that for many straightforward retrofits, the Applicant may simply use the Customized Approach to validate the energy savings instead of measuring them directly for a specified period of time. However, short-term monitoring, spot measurements, production data or other forms of verification may be requested to confirm savings estimates. February 25, Version 1.1

58 The measured approach utilizing the Measurement & Verification (M&V) process is only required if the Utility Administrator determines that the energy savings cannot be reasonably substantiated without pre-and post-installation measurements. If the Utility requires the M&V process, the Project Sponsor is required to comply. To help defray the M&V cost, the Payee will then be eligible to receive an additional 10 percent of the approved incentive, not to exceed $50, The Measurement & Verification Process The M&V process begins after the Utility Administrator reviews the submitted application and has determined at its sole discretion that an M&V process is appropriate for the proposed project. The M&V process proceeds as follows: 1. M&V Requirement Notification. The Utility Administrator contacts the Project Sponsor and notifies them of the M&V requirement. The Utility Administrator sends the Project Sponsor the Measurement & Verification Guidelines. 2. M&V Plan Development. The Project Sponsor develops an M&V plan based on the M&V Guidelines. The Project Sponsor submits the M&V plan, and any required baseline data to the Utility Administrator. 3. Application and M&V Plan Approval. If the application and the M&V plan are approved, incentive funding for the project is reserved and the Project Sponsor and Utility Administrator initiate the application approval review. 4. Project Installation. For SDG&E and SCE service territories, the Project Sponsor submits a signed Installation Report and invoices after all project measure(s) have been installed and are fully commissioned and fully operational. For PG&E service territory, the Project Sponsor notifies the Utility Administrator in writing and submits invoices after all project measure(s) have been installed and are fully commissioned and fully operational. 5. Installation Review. Upon receipt of Installation Report (SCE and SDG&E), or Installation notification (PG&E), the Reviewer will evaluate the submittal package and conduct a postinstallation inspection to verify project installation and ensure the scope of work has not altered from the agreed-upon project. 6. First Payment. For SCE and SDG&E service territories, the designated Payee receives 60 percent of the Installation Report approved incentive along with a 10% M&V adder, upon approval of the Installation Report. For PG&E service territory, the designated payee receives the 10% M&V adder, to defray the M&V cost, upon approval of the Installation Review. The M&V adder is10% of the IR approved incentive amount, not to exceed $50, Project Performance Period. The Applicant performs the agreed-upon M&V activities on the new operating equipment for a period up to two years (at discretion of Utility Administrator). At the end of the project performance period, the Project Sponsor submits the Operating Report. 8. Operating Report. The Applicant submits the Operating Report and operating data to the Utility Administrator. Upon receipt, the Utility Administrator reviews the report and data. 9. Final Payment. For SCE and SDG&E service territories, the designated Payee receives the remaining balance of the incentive based on the measured savings upon approval of the Operating Report. For PG&E service territory, 100% of the incentive based on the measured savings is paid at the end of the project performance period when the Operating Report is approved. February 25, Version 1.1

59 1.8 Incentive Payments The incentive payment amount is based on a flat incentive rate (per kwh) applied to one year of energy (kwh) savings, plus a flat incentive rate (per peak kw) applied to the resultant permanent peak permanent peak demand reduction. For measures that require M&V (Measurement and Verification), the final incentive amount is based on the measured performance and can therefore vary between 0 and 110 percent of the amount originally indicated on the Project Agreement. For measures not requiring M&V in SCE, SDG&E, and PG&E territories, 100 percent of the incentive is paid after the Installation Review is approved. For measures requiring M&V in SCE and SDG&E territories, 60 percent, along with the 10 percent M&V adder (not to exceed $50,000), is paid when the Installation Report is approved; the remainder is paid at the end of the project performance period when the Operating Report is submitted by the Project Sponsor and approved by the Utility Administrator. For measures requiring M&V in PG&E service territory, the 10% M&V adder to defray the M&V cost is paid when the Installation Review is approved and 100% of the incentive based on the measured savings is paid at the end of the project performance period when the Operating Report is approved. When reviewing the project application, the Utility Administrator will verify that the Applicant has designated the proper incentive category for each efficiency measure. As illustrated in Table 1-8, the incentive rate is dependent on the type of efficiency measure installed (Lighting, AC&R I, AC&R II, Other equipment, or Natural Gas). Table Energy Savings Incentive Rates Measure Category Lighting (Fluorescent, Other Lighting, or Lighting Controls) Annual Energy Savings Incentive Rate (kwh) Peak Permanent peak demand reduction Incentive Rate (kw) $0.05 per kwh saved $100 / kw Air Conditioning and Refrigeration (AC&R) I $0.15 per kwh saved $100 / kw Air Conditioning and Refrigeration (AC&R) II $0.09 per kwh saved $100 / kw Motors and Other Equipment $0.09 per kwh saved $100 / kw Natural Gas* 1.00 per therm saved * Applicable only in PG&E and SDG&E service territories Incentive Payment May Vary from Contracted Value Based on Performance Measures not requiring M&V: The incentive may be less than contract amount, if actual equipment installation or operation differs from that described in the approved application. For example, if the installed equipment or operating schedule is different from the approved application, the incentive amount must be adjusted. Generally the incentive amount cannot exceed the contracted amount however some exceptions may apply. For SDG&E service territory, the incentive amount cannot exceed the contracted amount unless the Utility Administrator approves a revision of the contract. For PG&E and SCE service territories, the Utility Administrator may approve an incentive that exceeds the contracted amount if one of the following conditions occurs: February 25, Version 1.1

60 1. Increased Measure Costs The actual installed costs are higher than the application estimated costs approved at the application review and there are no other limiting customer project site caps. The incentive is capped at 50% of the actual measure costs. 2. Installation of More Efficient Equipment The Customer has installed higher efficiency equipment than equipment indicated on the application and approved at the application review. If the scope of work changes after the contract is issued, but before the work is completed, notify the Utility Administrator immediately. Measures requiring M&V: The Energy Savings Incentive is based on actual performance and can vary between 0 and 110 percent of the approved incentive amount. In the event that actual energy savings are higher than projected, the final incentive amount may include an additional incentive amount (up to 10 percent) above the contracted amount. In some cases, the amount of the adjusted Operating Report incentive could drop below the amount that was paid out at installation. In such a situation, the Payee is responsible for reimbursement of the difference to the Utility Administrator Incentive Limits First Come, First Served Program funds are available on a first-come, first-served basis. For SDG&E and SCE Project incentive funds are reserved when a Project Agreement is fully executed by both the Project Sponsor and the Utility Administrator. For PG&E incentive funds are reserved when the application is fully approved Incentives from other Programs Any measures included in the application cannot be applied through multiple California energy efficiency incentive or rebate programs. Gas and Electric components should be considered separately. Other California end user energy efficiency programs include, but are not limited to, any program offered by or through SoCal Gas, PG&E, SDG&E, SCE, California Energy Commission (CEC), and California Public Utilities Commission (CPUC), including PPP funded local programs, third-party programs, or local government partnerships. Applicants cannot receive incentives from more than one energy efficiency program for the same measures Customer Project Incentive Caps The Customized Measure incentives are limited to the lesser of the following: 1) The incentive based on the energy savings and permanent peak demand reduction resulting from the installation of the new equipment on the meter(s) for which the utility collects the PPP surcharge; Note: kwh, kw and therm savings are limited to the net potential benefit provided to the Utility during the period of performance. 2) 50 percent of the total project costs for all installed measures. The 10% measure savings adder to defray the M&V costs (not to exceed $50,000), if applicable, is not used in the calculation of the 50 percent cost cap. The Project Sponsor shall provide the project cost and a description of the cost items with the application. 3) The maximum incentive per site is 15 percent of the annual program incentive funds managed by the specific Utility Administrator. Please contact your Utility Administrator for details. February 25, Version 1.1

61 Project Cost Project costs must be included on the application. Project costs may include audits, design, engineering, construction, equipment and materials, overhead, tax, shipping, and labor on a per measure basis. The cost of filling out Customized forms and conducting M&V may be included in the project cost. Costs that do not directly pertain to measure installation such as bidding, marketing, and RFP labor expenses, are not eligible Customer Project Site A Customer Project Site is defined as a single free-standing building/structure; an individual utility meter; or a service account number where the retrofit or installation is taking place Payment Schedule For most projects, 100 percent of the approved incentive amount is paid after the Utility Administrator approves the Installation Report. For measures requiring M&V, refer to section Payments are made only after the Utility Administrator has approved the necessary submissions (as discussed in Sections 1.13 and 1.14 of this manual) Payment Disbursement The Utility Administrator will calculate the incentive payment based on its review of the submitted paperwork or site inspection. The Utility Administrator will notify the Project Sponsor in writing of the final approved incentive payment amount upon approval of the Installation Review or Operating Report, as applicable, and will begin processing the incentive check. As soon as the check is processed, the Utility Administrator will mail it to the Payee designated on the application. If the Project Sponsor disputes the findings of the review, the Project Sponsor should notify the Utility Administrator as soon as possible. This should be done before the Payee receives the incentive payment. February 25, Version 1.1

62 1.9 How to Apply The application process requires careful attention to detail. Incomplete or incorrect applications will be returned, so it is highly recommended to follow the program instructions carefully. Applicants can call their Utility Administrator for assistance in completing their applications and to obtain answers to specific program questions as well. Table 1-9 lists the Statewide Customized Offering contact information for each Utility Administrator. Table 1-9. Utility Administrator Utility Administrator Program Contact Information San Diego Gas & Electric Southern California Edison Pacific Gas and Electric San Diego Gas & Electric 8335 Century Park Ct., CP12C San Diego, CA Fax: (619) Southern California Edison Business Incentives & Services P.O. Box 800 Rosemead, CA Phone: General Assistance - (800) Technical Assistance - (626) Fax: (626) BusinessIncentives@sce.com Pacific Gas and Electric Company PG&E Integrated Processing Center P.O. Box 7265 San Francisco, CA For overnight delivery: PG&E Integrated Processing Center Mail Code B3B, 77 Beale Street - 3rd Floor San Francisco, CA Phone: (800) businesscustomerhelp@pge.com Overview of Paperwork To receive Statewide Customized Offering incentives, the Applicant must perform certain actions and submit certain forms or applications/reports at specific project milestones: 1. First milestone: Application The application describes the project and estimates the energy savings and permanent peak demand reduction. Supporting documentation and calculations must accompany the application forms. Additionally, all measure costs must be outlined. 2. Second milestone: Installation For SCE and SDG&E service territories, the Project Sponsor submits an Installation Report to the Utility Administrator after the new equipment is installed and fully commissioned and fully operational. The Utility Administrator cannot schedule an inspection without a submitted and signed IR. For PG&E service territory, the Project Sponsor notifies the Utility Administrator after installation and commissioning are complete. For all Utilities, the Project Sponsor also submits invoices and any other materials deemed relevant by the Utility Administrator. February 25, Version 1.1

63 3. Third milestone: Operating Report (Projects requiring the M&V process only) This form is filed with the Utility at the end of the project performance period to confirm that the project is still in operation as installed and is submitted with M&V results. The Operating Report is the basis for the final incentive payment for measured savings Paper or Electronic Forms There are two ways to fill out the Customized Program paperwork: 1. On paper, using hardcopy forms (a) obtained from your Utility Administrator or (b) downloaded from the Utility s energy efficiency website (please refer to table 1-9 for website address). 2. Electronically, through interactive Statewide Customized Offering software or online application system accessed through the Utility s website 1 (please refer to table 1-9 for website address). The software and online versions of the forms allows for easier editing and can save time in preparing multiple project applications. The software also checks to make sure that necessary information is not missing, a feature that can speed processing time Application Review The project application (first submittal) consists of the application document and supporting attachments. The application process is different between the Utilities so please consult with their websites for forms and instructions. Table 1-9 shows the website addresses. The information required for the application consists of: 1. Incentive Application (information regarding Applicant, Project Type, and Payment, Customer Project Site, Property Type, and Project Sponsor) 2. Savings Summary (Information regarding Energy Savings) 3. Energy savings calculations showing how the energy and peak savings were determined; a printout of the estimation software results if you use the software method; and custom calculations if you use the engineering calculation method. If possible, please provide an electronic copy of the energy savings calculations. These calculations are required for all Customized projects Project Application Review Schedule Review of a Customized application not requiring the M&V process (including the site inspection) may be completed within 30 days. Complex and multiple-site projects may require more time. Projects can only be reviewed when documentation is complete. If deemed necessary, the Utility Administrator will contact the Project Sponsor for additional information or clarification. The quicker the response, the faster the application process can be reviewed and completed. If the Utility Administrator determines that the M&V process is required (see Section 1.8), the Utility Administrator will advise the Project Sponsor. The Project Sponsor will then be required to develop and submit a Measurement & Verification (M&V) plan within 30 days. The application will not be approved until the M&V plan has been received and approved. 1 Downloadable software is available for SDG&E and PG&E service territories, an online application system is currently under development for SDG&E and PG&E. February 25, Version 1.1

64 Pre-Installation Inspection Upon receiving a complete Statewide Customized Offering application, the Utility Administratorassigned Reviewer may contact the Project Sponsor to schedule a pre-installation site inspection as soon as possible. The purpose of this inspection is to verify: 1. The application accurately reflects the existing project baseline. 2. All existing equipment listed in the application is still operational (if not, the associated measures may be deemed ineligible). 3. Installation has not yet occurred (if field preparations for installation have begun, the project may be deemed ineligible). 4. Take spot measurements, if applicable. The Project Sponsor should be flexible in scheduling such inspections and provide complete access to customer project sites. A representative of the Project Sponsor who is familiar with the project, e.g. the facility manager or other responsible representative of the Customer, should attend the inspection. When electrical measurements are necessary, the Customer may be required to disrupt equipment operation, open any electrical connection boxes, and/or install current and power transducers, as needed. If the inspection cannot be completed in a timely manner, the Customer Project Site may fail the inspection. If the project fails the inspection, the Utility Administrator may decline the application. Also, the Utility Administrator may assess a re-inspection fee if multiple site inspections are conducted Notice of Application Review Results The Utility Administrator will provide the Project Sponsor written notice of the pre-installation inspection results and overall review of the project application as follows: Approved. The approval letter/ informs the Project Sponsor that the project is accepted under the terms of the Statewide Customized Offering outlining the approved energy savings and incentive. Included with the letter/ is an official Program Agreement, which is to be signed and returned within 10 business days. If the Project Sponsor does not sign and return the Project Agreement within the designated time, the Utility Administrator reserves the right to rescind the Project Agreement. Sample Project Agreements are included in Appendix A. On Hold. The review may be placed on hold if circumstances do not allow for the project to proceed. Upon resolution of the issue(s), the Utility Administrator will resume the review process. Suspended. The review may be suspended when repeated attempts for information are ignored. At this point the Project Sponsor has 30 days to respond or the application may be withdrawn and will need to reapply. Declined. An application may be declined if any of the following conditions apply: the project fails inspection; the application is missing information that the Project Sponsor is unwilling or unable to provide; the existing equipment has been removed prior to inspection; the project otherwise fails to meet program criteria; the application does not include an acceptable M&V plan (M&V process projects only). If declined, the Project Sponsor may re-apply to the program, or the application may be reactivated once the information is provided. February 25, Version 1.1

65 1.11 Project Installation Wait for Approval As a general rule, actual project implementation should not begin until after the project application has been approved. However, sometimes based on special circumstances the Utility Administrator, at their discretion, may allow installation to begin immediately after the preinstallation inspection. The Utility Administrator pre-approval does not mean the application has been approved and will receive funding, but rather that proceeding with installation will not impair the Project Sponsor s chances for the application s approval. The Project Sponsor is to request this notification in writing from the Utility Administrator. Verbal notification is not binding. Installation includes, but is not limited to, decommissioning and/or removal of existing equipment, demolition, facility alterations to prepare for new equipment, and installation of new equipment Change in Project Scope If the scope of the project changes substantially from what was identified in the project application review, the project may require resubmittal. Substantial changes include significant modifications to the proposed equipment type, size, quantity, configuration, or the expansion of project to include additional retrofits. The revised project scope and supporting calculations are subject to an additional review and may require a new agreement prior to the removal of existing equipment/systems or the installation of the replacement equipment/systems. Exceptions may be granted as deemed reasonable by the Utility Administrator Installation Deadline For SCE and SDG&E service territories, all projects must be installed and fully operational one year from PA approval. For PG&E service territory, all projects must be installed and fully operational by June 1, If project is not fully installed and operational by the specified installation deadline, the agreement is subject to cancellation. Extensions may be requested and granted at the Utility Administrator s discretion Installation Review For SCE and SDG&E service territories, the Project Sponsor submits an Installation Report (second milestone) to the Utility Administrator once the project has been installed and is fully commissioned and fully operational. The Installation Report must be submitted for a postinstallation inspection to be scheduled. For PG&E service territory, the Project Sponsor notifies the Utility Administrator and submits project invoices once the project has been installed and is fully commissioned and fully operational. This Installation Report/notification should confirm the estimated energy savings, or identify any changes to the project that were made during installation. In this later case, the anticipated energy savings and demand reduction should be recalculated as necessary. The Project Sponsor also attaches any required data and analysis from spot metering that may have been performed before or after installation. The Installation Review approval is the basis for initiating the incentive payment Installation Review Timeline The Project Sponsor should submit the Installation Report (SCE and SDG&E) or notify the Utility Administrator (PG&E) within 30 days of equipment installation. The Utility Administrator will typically review the form within 30 days for non-m&v projects and 45 business days for M&V projects. Complex and multiple-site projects may take longer. February 25, Version 1.1

66 Post-Installation Inspection Upon receipt of the Installation Report (SCE and SDG&E) or installation notification (PG&E), the Utility Administrator will schedule a post-installation inspection at the customer project site as soon as possible. The Reviewer will verify that the new equipment (project) is completely installed and operational, and may conduct spot measurements, if applicable. The Project Sponsor should be flexible in scheduling such inspections and provide complete access to customer project sites. A representative of the Project Sponsor who is familiar with the project, e.g. the facility manager or other responsible representative of the Customer, should attend the inspection. When electrical measurements are necessary, the Customer may be required to disrupt equipment operation, open any electrical connection boxes, and/or install current and power transducers, as needed. If the inspection cannot be completed in a timely manner, the Customer Project Site may fail the inspection. If the project fails the inspection, the Utility Administrator may decline the application. Also, the Utility Administrator may assess a re-inspection fee if multiple site inspections are conducted Notice of Installation Review Results The Utility Administrator will provide the Project Sponsor written notice of the post-installation inspection results and overall review of the project application, typically within 30 days of receipt of the completed Installation Report/Notification, as follows: Approved. The approval letter/ informs the Project Sponsor that the project has been approved for incentive payment processing under the terms of the Statewide Customized Offering. On Hold. The review may be placed on hold if circumstances do not allow for the project to proceed. Upon resolution of the issue(s), the Utility Administrator will resume the review process. Suspended. The review may be suspended when repeated attempts for information are ignored. At this point the Project Sponsor has 30 days to respond or the application may be withdrawn and will need to reapply. Declined. An application may be declined if any of the following conditions apply: the installation is not consistent with the Project Agreement; the project fails inspection; the project is missing information that the Project Sponsor is unwilling or unable to provide; the installed equipment is not fully commissioned and fully operational prior to inspection; the project otherwise fails to meet program criteria. If an Installation Review is not approved, the Utility Administrator may terminate the Project Agreement and release the incentive funding reserved for the project. February 25, Version 1.1

67 Incentive Payment Upon approval of the Installation Review, the Utility Administrator will pay the Project Sponsor the approved incentive amount. For projects requiring M&V, refer to section Operating Report (Measured Savings only) For the Customized projects requiring Measurement & Verification (M&V), the third and final paperwork submittal stage comes at the end of the project performance period. After the new equipment (project) has been operating for the predetermined project performance period, the Project Sponsor submits the Operating Report. This form confirms that the equipment is still in operation as installed or notes any changes (e.g., equipment pulled out of service, changed operating hours, etc.). The Project Sponsor is to attach the M&V data and analyses to the Operating Report Operating Report Timeline The Operating Report is due within 30 days following the end of the project performance period. The Utility Administrator will typically finish reviewing the Operating Report within 45 business days. The process may take longer for complex and multiple-site projects Operating Report Inspection Upon receipt of the Operating Report or at any time during the performance period the Utility Administrator may request a site inspection, subject to the same provisions as the postinstallation inspection. If the project fails the inspection, the Utility Administrator may decline the application. Also, the Utility Administrator may assess a re-inspection fee if multiple site inspections are conducted. If the inspection reveals that the M&V activities are different from those described in the M&V plan, the Utility Administrator may deny any further incentive payments and may request repayment of the previous incentive payment Notice of Operating Report Review Results The Utility Administrator will provide the Project Sponsor written notice of the Operating Report review results. If approved, the notice will include the approved incentive amount based on the Utility Administrator s evaluation of the Operating Report and indicate that the final incentive check is being processed. A project may be denied further incentive funds if: The installation is not consistent with the Project Agreement (fails inspection); or The project otherwise fails to meet program criteria. If an Operating Report is declined, the Utility Administrator may terminate the Project Agreement and request that the previous payment be returned. February 25, Version 1.1

68 Final Incentive Payment (Projects requiring the M&V process) For SCE and SDG&E service territories, the Utility Administrator will pay the final installment of the Energy Savings Incentive (the remaining 40 percent or whatever adjusted amount is properly due) upon approval of the Operating Report. For PG&E service territory, the Utility Administrator will pay 100 percent of the incentive upon approval of the Operating Report. If measurements show that the installation achieved greater energy savings than predicted, the Utility Administrator will pay up to 10 percent higher than the Energy Savings Incentive amount estimated on the approved project application, or the applicable percent of the measure cost, which ever is the lesser amount. Similarly, if the installation achieved lower energy savings than anticipated, the Applicant will not receive the full incentive, and is responsible for returning to the Utility Administrator any overpayment that may have been made in the first installment Other Important Terms and Conditions By virtue of participation in the program, Customers, Project Sponsors, and Authorized Agents agree to the following terms and conditions: 1. All parties consent to participate in any evaluation of the program. The CPUC or its representatives may contact participants to answer questions regarding their Statewide Customized Offering experience and/or request a site visit. All participants agree to comply with such program evaluations. 2. Utility Administrators expressly reserve all their rights, which include, but are not limited to, the right to use others to perform or supply work of the type covered by the Statewide Customized Offering, as well as the unrestricted right to contract with others to perform the work or to perform any such work themselves. Utility Administrators may employee thirdparty engineering firms to conduct site inspections, review calculations, and make recommendations for project status. The information reviewed is considered confidential and is not shared with any party outside the application, other than the California Public Utility Commission as requested. The CPUC has decided that the Utilities should continue to administer the program through the end of The CPUC has not decided who will administer the program thereafter. Thus, after December 31, 2012, existing program Agreements might be assigned to a new Administrator. In their program Agreements, Applicants must agree to terms and conditions allowing for such a transfer. Notice of Public Record Participants should be aware that, because the program is funded by the PPP surcharge, Statewide Customized Offering projects are a matter of public record and may be reviewed and evaluated by the CPUC upon program commencement. The estimated total project costs will be part of the public record. The Utilities may discuss projects and disclose project information among program administrators (SDG&E, PG&E and SCE) to ensure statewide consistency and eligibility, as necessary. However, projects are not shared or available for viewing by other customers or sponsors, and information about specific projects is not divulged to parties not included on the application. The Utility Administrators are not liable to any Project Sponsor, Customer, Authorized Agent or other party as a result of any public disclosure to the CPUC for the purpose of Measurement and Evaluation. 2 Applicable in SCE and SDG&E service territories only. February 25, Version 1.1

69 Change in Sponsorship If a change in sponsorship occurs after the application is submitted, a new Statewide Customized Offering application is required. Please indicate the change request in writing to the Utility Administrator, and resubmit the required forms. Written notification is also required from the original Project Sponsor or Authorized Agent/Customer. If written notification is not possible, (i.e. the sponsor is no longer in business or non-responsive) the Applicant must submit a letter in writing requesting termination of the Project Sponsor or Authorized Agent/Customer to act on their behalf. Contract Termination Statewide Customized Offering contracts may be terminated at the Utility Administrator s discretion, under the following conditions but not limited to: The Utility Administrator determines that significant information was purposely withheld or falsely stated in the Project Application. The project fails to be installed, fully commissioned, or fully operational prior to the installation deadline. The Project Sponsor formally requests withdrawal from the program, or requests the contract to be turned over to the Customer. For SDG&E or SCE, The Customer requests withdrawal from the program. For more information see sample Customized offering agreements in Appendix A. February 25, Version 1.1

70 Section 2: Estimating Energy Savings and Incentives 2.1 Estimating Energy Savings and Incentives Customized Measures - Estimation Software AC&R Chiller Replacement or Early Retirement AC&R - Split/Packaged AC Retrofit or Early Retirement (PG&E and SDG&E Only) AC&R Split/Packaged Heat Pump or Early Retirement (PG&E and SDG&E Only) AC&R VAV or VSD on Supply Fan Motors Gas - Natural Gas Boiler Measures (PG&E and SDG&E Only) Gas - Thermal Oxidizer Upgrades (PG&E and SDG&E Only) Gas Steam Trap Replacement (PG&E and SDG&E Only) Lighting - Lighting Retrofit Lighting - Lighting Controls Other - A/C Economizers Other - Carbon Monoxide Sensors for Parking Garages Other - Cold Storage Rapid Close Doors Other - Compressed Air System Upgrades Other - Demand Control Ventilation (DCV) Other - Injection Molding Machines Other Low Solar Heat Gain Coefficient Windows Other - Motors Replacement or Early Retirement for Motors Other - Professional Wet Cleaning Replacement Other - Pulse Cooling for Injection Molding Machines Other - Pump-Off Controllers for Oil Wells Other Pumping System Upgrades Other - Refrigerated Wine Tank Insulation Other - Tape Drip Irrigation Other - Variable-Speed Drives for Cooling Tower Fan Motors Other - Variable-Speed Drives for Dairy Vacuum Pump Other - Variable-Speed Drives for HVAC Fans > 100 HP Other - Variable-Speed Drives for Process Applications Other - Wastewater Retrocommissioning Customized Measures - Engineering Calculations Measurement & Verification (M&V) Process February 25, 2010 Version 1.1

71 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 2.1 Estimating Energy Savings and Incentives This section of the 2010 Statewide Customized Offering Procedures Manual describes the customized approach utilized to estimate the expected energy savings and incentives for your proposed Customized energy efficiency project(s). Under this approach you will need to estimate the kwh savings and the permanent peak demand reduction achieved as a result of your high efficiency upgrade. This can be done using either the estimation software or using engineering calculations. Estimating software. Downloaded from the Utility website or on-line (SCE Only), the estimating software provides methodologies for specific measures that calculate energy savings based on site-specific information for the project (a list of the measures included on the software is included in Section 2.3). This method is also used to determine the energy savings for air conditioning equipment and motors that qualify for the Early Retirement option. Engineering calculations. If your proposed energy efficiency measures are not addressed by the estimation software, you can calculate the energy savings by using accepted engineering procedures. This option should ONLY be used if the estimating software does not address the specific measure you are installing or if the software does not accurately calculate your achievable savings. This is the more difficult approach for estimating the savings but is acceptable with supporting documentation and substantiation of your savings claims. 2.2 Customized Measures - Estimation Software The Statewide Customized Offering Estimation Software provides savings calculations for a variety of the most common energy-saving measures. These savings calculations incorporate assumptions and stipulations that provide reasonable savings estimates under most conditions. The estimation software asks for detailed input from your facility, providing a good approximation of the energy savings. In some cases spot measurements may be necessary. Each of these tools collects project information through a combination of direct data entry and pull-down menus. The input fields are generally self-explanatory, and if you position your cursor at the very beginning (left edge) of the white input field, a balloon prompt will pop up to explain the type of data that should be entered into that field. The estimating tools can be accessed either by using Create or Edit Application feature or by using the Energy Savings Calculator feature of the software (The calculator only provides a savings estimation and does not go through the steps of filling out an electronic application). This allows you to fill out the Application forms by hand, and attach the savings calculation. Specific considerations for each of these tools are discussed below. February 25, Version 1.1

72 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings AC&R Chiller Replacement or Early Retirement This tool is for the direct replacement of water-cooled chillers (SCE) and for direct replacement of air-cooled and water-cooled Chillers (PG&E and SDG&E).The tool also can be utilized for the installation of a VSD on an existing Chiller. Baseline efficiency is current Title 24 standards or minimum efficiency standards. Calculating Early Retirement This tool is used for chillers that qualify for Early Retirement. If the unit qualifies for early retirement, (either recently overhauled or replaced before the end of its useful life) the energy savings are calculated using the baseline standards that were in effect when the equipment was manufactured rather than the current minimum standards. This results in a larger incentive than would be possible using the traditional Customized Approach. To qualify as overhauled, a significant amount of work must have been performed (major overhaul). All of the components must be brought back to their original condition. The life of the existing equipment must have been significantly extended from this effort. For example, a major overhaul would include the replacement or rebuilding of all of the compressors and motors of the chiller unit as well as restoring the evaporator and condenser heat exchangers to their original condition. As part of the inspection, the equipment will be examined to determine if the calculated remaining life is reasonable. Should the equipment not meet the expected useful life, the measure will be rejected. The Utility administer has the final decision on whether a piece of equipment qualifies as refurbished. To establish the overhaul and its date, supporting invoices are required. The 2010 Customized Offering estimating software calculates savings using the Engage tool for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. Please note the following inputs into the Engage Model: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Area Enter the total building area. There may be auxiliary or secondary area inputs required, depending on the building type selected. Building Seasons - Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o o Sheet 2 The user has the ability to define up to three seasons Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. The following inputs relate to the measure specifications located on Screen 4 February 25, Version 1.1

73 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Area Served This is the total building area within the project that is served by the selected type of HVAC equipment. Year Manufactured Indicate the year during which the existing chiller(s) were manufactured. Overhaul Flag for Existing Chillers - Use this checkbox to indicate whether the existing equipment has been overhauled. The useful life for overhauled chillers is assumed to be 15 years (reciprocating chillers) or 17 years (other chiller types) Year of Overhaul for Existing Chillers - Indicate the year during which the existing chiller(s) were overhauled. Chiller Type Select the appropriate chiller type from the drop down list. Condenser Types Chiller Condenser Type is used to indicate whether the chillers use air-cooled or water-cooled condensers. There are five choices: o o o o "Water-Cooled" A water-cooled chiller will be used. "Packaged Air-Cooled" A self-contained air-cooled condenser will be used. All energy consumption associated with the condenser fans is included in the chiller s rated efficiency Remote Air-Cooled A remotely located, air-cooled condenser will be used. The chiller s rated efficiency does not include the energy used by the condensing unit. Remote Evap-Cooled A remotely located, evaporative-cooled condenser will be used. The chiller s rated efficiency does not include the energy used by the condensing unit Compressors Select between constant, variable speed, and frictionless compressors. Please note that this option is only enabled for centrifugal chillers. Chiller Counts and Sizes Input the quantity and the typical chiller size (in tons) for the baseline and proposed equipment. Chiller Size is available for input only if the user has selected "Specify" for the Specify Chiller Size. Chiller Efficiency - Indicate the preferred chiller efficiency units (kw/ton or COP) and input the chiller efficiency for the baseline and proposed equipment. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. February 25, Version 1.1

74 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings AC&R - Split/Packaged AC Retrofit or Early Retirement (PG&E and SDG&E Only) This tool is for split or packaged air-cooled air conditioners greater than or equal to 760,000 BTU/hr (63.3 tons). Baseline efficiency is current Title 24 standards or minimum efficiency standards. A package unit is defined as an electric cooling unit with its compressor, condenser, and supply fan in a single enclosure. For SCE, Packaged, Split-System, Heat Pumps, and Air-Cooled Chillers are not eligible under the Customized Offering but may be available through other Offerings; please check for more information. Calculating Early Retirement This tool can also be used for packaged AC Units that qualify for Early Retirement. If the unit qualifies for early retirement, (either recently overhauled or replaced before the end of its useful life) the energy savings are calculated using the baseline standards that were in effect when the equipment was manufactured rather than the current minimum standards. This results in a larger incentive than would be possible using the traditional Customized Approach. To qualify as overhauled, a significant amount of work must have been performed (major overhaul). All of the components must be brought back to their original condition. The life of the existing equipment must have been significantly extended from this effort. For example, a major overhaul would include the replacement or rebuilding of all of the compressors and motors of the AC unit as well as restoring the evaporator and condenser heat exchangers to their original condition. As part of the inspection, the equipment will be examined to determine if the calculated remaining life is reasonable. Should the equipment not meet the expected useful life, the measure will be rejected. The Utility administer has the final decision on whether a piece of equipment qualifies as refurbished. To establish the overhaul and its date, supporting invoices are required. The 2010 Customized Offering estimating software calculates savings using the Engage tool for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. Please note the following inputs into the Engage Model: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Area Enter the total building area. There may be auxiliary or secondary area inputs required, depending on the building type selected. Building Seasons - Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o Sheet 2 The user has the ability to define up to three seasons February 25, Version 1.1

75 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings o Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. The following inputs relate to the measure specifications located on Screen 4 Area Served This is the total building area within the project that is served by the selected type of HVAC equipment. Economizer This is used to indicate whether the AC units described on this screen are required to have economizers by the latest vintage of Title24. Equipment Data Button Select the appropriate button to view or edit the details for existing or replacement AC systems. Existing AC Systems: Year Manufactured Indicate the year during which the existing AC unit(s) was manufactured. Overhaul Flag for Existing Equipment - Use this checkbox to indicate whether the existing equipment has been overhauled. Year of Overhaul for Existing Equipment - Indicate the year during which the existing unit(s) was overhauled. Cooling Capacity Per Unit - Indicate the rated or nominal capacity of each individual unit defined as the total (sensible + latent) cooling capacity in tons, per individual unit. Number of Units - Input the quantity of units of the same size and efficiency. Select a new row (up to 15) for each unitary unit type, size or efficiency. Unit Type Select type and size range of replacement packaged AC unit (choices vary based on cooling capacity). Indicate the type of replacement unit, package or split, single-phase or three-phase. This input is used to identify the Title 24 size range for the AC units described on this screen. Cool Efficiency - Indicate the preferred AC unit efficiency in units of EER (Energy Efficiency Ratio). Static Pressure Indicate the total (internal + external) static pressure for the supply and return fans for the existing AC unit(s) described on this screen. Static pressure is a commonly used indicator of fan power. It is the amount of air pressure generated (or overcome) by the system fan, commonly measured in inches of water gauge. Supply Flow Indicate the supply fan flow rate, per ton of cooling capacity, per individual AC unit(s) described on this screen Replacement AC Systems Cooling Capacity Per Unit - Indicate the rated or nominal capacity of each individual unit. This is defined as the total (sensible + latent) cooling capacity in tons, per individual unit. Number of Units - Input the quantity of units of the same size and efficiency. Please note that up to fifteen (15) systems may be specified for the replacement scenarios. The number of replacement systems does NOT need to match the number of existing systems. Unit Type Select the appropriate equipment type from the drop down list. Cool Efficiency - Indicate the preferred AC unit efficiency in units of EER (Energy Efficiency Ratio). February 25, Version 1.1

76 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Static Pressure Indicate the Total (internal + external) static pressure for the supply and return fans for the replacement AC unit(s) described on this screen. Static pressure is a commonly used indicator of fan power. It is the amount of air pressure generated (or overcome) by the system fan, commonly measured in inches of water gauge. Supply Flow Indicate the supply fan flow rate, per ton of cooling capacity, per individual AC unit(s) described on this screen. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. February 25, Version 1.1

77 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings AC&R Split/Packaged Heat Pump or Early Retirement (PG&E and SDG&E Only) This tool is for split or packaged air-cooled heat pumps greater than or equal to 760,000 BTU/hr (63.3 tons). Baseline efficiency is current Title 24 standards or minimum efficiency standards. A package heat pump is defined as an electric cooling unit with its compressor, condenser, and supply fan in a single container. This tool can only be used for measures replacing an existing heat pump (no fuel switching). Heat pump savings are calculated for the cooling savings only. For SCE, Packaged, Split-System, Heat Pumps, and Air-Cooled Chillers are not eligible under the Customized Offering but may be available through other Offerings; please check for more information. Calculating Early Retirement This tool can also be used for heat pumps that qualify for Early Retirement. If the unit qualifies for early retirement, (either recently overhauled or replaced before the end of its useful life) the energy savings are calculated using the baseline standards that were in effect when the equipment was manufactured rather than the current minimum standards. This results in a larger incentive than would be possible using the traditional Customized Approach. To qualify as overhauled, a significant amount of work must have been performed (major overhaul). All of the components must be brought back to their original condition. The life of the existing equipment must have been significantly extended from this effort. For example, a major overhaul would include the replacement or rebuilding of all of the compressors and motors of the heat pump unit as well as restoring the evaporator and condenser heat exchangers to their original condition. As part of the inspection, the equipment will be examined to determine if the calculated remaining life is reasonable. Should the equipment not meet the expected useful life, the measure will be rejected. The Utility administer has the final decision on whether a piece of equipment qualifies as refurbished. To establish the overhaul and its date, supporting invoices are required. The 2010 Customized Offering estimating software calculates savings using the Engage tool for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. Please note the following inputs into the Engage Model: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Area Enter the total building area. There may be auxiliary or secondary area inputs required, depending on the building type selected. Building Seasons - Sheet 2 and Sheet 3 are used to input the operating schedule of the building. February 25, Version 1.1

78 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings o o Sheet 2 The user has the ability to define up to three seasons Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. The following inputs relate to the measure specifications located on Screen 4 Area Served This is the total building area within the project that is served by the selected type of heat pump equipment. Economizer This is used to indicate whether the heat pump units described on this screen are required to have economizers by the latest vintage of Title24. Equipment Data Button Select the appropriate button to view or edit the details for existing or replacement heat pump units. Existing HP Units: Year Manufactured Indicate the year during which the existing heat pump unit(s) was manufactured. Overhaul Flag for Existing Equipment - Use this checkbox to indicate whether the existing equipment has been overhauled. Year of Overhaul for Existing Equipment - Indicate the year during which the existing unit(s) was overhauled. Cooling Capacity Per Unit - Indicate the rated or nominal capacity of each individual unit defined as the total (sensible + latent) cooling capacity in tons, per individual unit. Number of Units - Input the quantity of units of the same size and efficiency. Please note that up to fifteen (15) systems may be specified for the existing scenarios. The number of existing systems does NOT need to match the number of replacement systems. Unit Type Select the appropriate equipment type from the drop down list (choices vary based on cooling capacity). Indicate the type of replacement unit, package or split, single-phase or three-phase. This input is used to identify the Title 24 size range for the heat pump units described on this screen. Cool Efficiency - Indicate the preferred heat pump efficiency in units of EER (Energy Efficiency Ratio). Heat Efficiency Input the heating efficiency, per individual unit, for the existing airsource heat pump unit(s) described on this screen. This is assumed to be the rated heating efficiency of each individual air-source heat pump in units of COP (Coefficient of Performance, heating work accomplished in Btu/hr divided by electric energy required in Watts). Static Pressure Indicate the total (internal + external) static pressure for the supply and return fans for the existing heat pump(s) described on this screen. Static pressure is a commonly used indicator of fan power. It is the amount of air pressure generated (or overcome) by the system fan, commonly measured in inches of water gauge. Supply Flow Indicate the supply fan flow rate, per ton of cooling capacity, per individual heat pump described on this screen Replacement HP Units February 25, Version 1.1

79 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Cooling Capacity Per Unit - Indicate the rated or nominal capacity of each individual heat pump unit. This is defined as the total (sensible + latent) cooling capacity in tons, per individual unit. Number of Units - Input the quantity of units of the same size and efficiency. Select a new row (up to 15) for each unitary unit type, size or efficiency. Unit Type Select the appropriate type and size range of replacement packaged heat pump unit (choices vary based on cooling capacity). Indicate the type of replacement unit. This input is used to identify the Title 24 size range for the heat pump units described on this screen. Cool Efficiency - Indicate the preferred heat pump unit efficiency in units of EER (Energy Efficiency Ratio). Heat Efficiency Input the heating efficiency, per individual unit, for the replacement airsource heat pump unit(s) described on this screen. This is assumed to be the rated heating efficiency of each individual air-source heat pump in units of COP (Coefficient of Performance, heating work accomplished in Btu/hr divided by electric energy required in Watts). Static Pressure Indicate the total (internal + external) static pressure for the supply and return fans for the replacement heat pump unit(s) described on this screen. Static pressure is a commonly used indicator of fan power. It is the amount of air pressure generated (or overcome) by the system fan, commonly measured in inches of water gauge. Supply Flow Indicate the supply fan flow rate, per ton of cooling capacity, per individual heat pump unit(s) described on this screen. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. February 25, Version 1.1

80 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings AC&R VAV or VSD on Supply Fan Motors This tool predicts the savings achievable by installing a Variable Speed Drive or other control device on the main air handler supply fan(s) in a building. The Variable Speed Drive on the Supply Air fan(s), along with VAV boxes at the zone level, allows for varying air flow depending on the overall building cooling load. The 2010 Customized Offering estimating software calculates savings using the Engage tool for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. This tool has four (4) input screens. Please note the following inputs into the Engage Model: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Area Enter the total building area. There may be auxiliary or secondary area inputs required, depending on the building type selected. Building Seasons - Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o o Sheet 2 The user has the ability to define up to three seasons Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. The following inputs relate to the measure specifications located on Screen 4 Supply Fan Type and Control (Baseline and Measure) - Select the appropriate fan and control combination for both the baseline and measure cases: o o o o Forward Curved Centrifugal Fan, Inlet Guide Vane Control a squirrel cage type fan with forward curved impeller blades and using inlet guide vanes to throttle the amount of air entering the fan. Forward Curved Centrifugal with Discharge Dampers a squirrel cage type fan with forward curved impeller blades and using outlet dampers to throttle the amount of air leaving the fan. Air Foil Centrifugal with Inlet Vanes a squirrel cage type fan with airfoil impeller blades (i.e., curved backward blades having an airfoil shape, similar in cross section to an airplane wing) and using inlet guide vanes to throttle the amount of air entering the fan Air Foil Centrifugal with Discharge Dampers a squirrel cage type fan with airfoil impeller blades (i.e., curved backward blades having an airfoil shape, similar in cross section to an airplane wing) and using outlet dampers to throttle the amount of air leaving the fan February 25, Version 1.1

81 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings o o Vane-Axial a propeller-type fan (similar to residential fans that get plugged into the wall for space cooling) and using guide vanes to throttle the amount of fan s air flow Variable Speed Drive the default for the Measure case; Variable Speed Drives (VSD s or equivalent, Variable Frequency Drive, VFD s) are the most efficient means of varying the air flow of an HVAC fan VAV Minimum Flow - Use these inputs to describe the Minimum Flow entering Perimeter Zones and Core Zones throughout the building for both the baseline and measure cases. The defaults come from Title 24. If a Baseline case is constant volume, VAV Minimum Flow should be 100%, indicating no reduction ion flow. Fan Motors - Enter motor count and motor horsepower for up to twenty (20) different motor sizes. Savings Estimate - The estimated savings are reported on the fifth screen of this tool. February 25, Version 1.1

82 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Gas - Natural Gas Boiler Measures This tool covers the replacement of space heating, process, and industrial boilers and the addition of an economizer to a process boiler. Replacing a Space Heating Boiler(s) This tool is to be used for calculating the energy savings and incentive for replacing space heating steam or hot water boiler(s) with new boiler(s) of higher efficiency. The energy output of the proposed boiler(s) can be larger than the output from the existing boiler(s). The 2009 program does provide incentives for increased capacity. This 2009 estimating software tool for replacing an existing space heating boiler is based on parametric runs using the hourly simulation program equest and empirical data from the Commercial Buildings Energy Consumption Survey conducted by the Energy Information Administration. A small number of building types, operating hours and sizes were used in developing the results. If you believe this method does not fairly represent the project s savings, use the Engineering Calculations approach to estimate the energy savings. Boiler Data The Project Sponsor shall provide, with the program Application, copies of the manufacturer s specification sheets that detail the replacement equipment output, input and efficiency and other data pertaining to the boiler s operation. In some instances the output from a boiler may be rated in Boiler Horsepower (BHP). BHP should be converted to Btu/hr by the factor of 33,476 Btu/hr per BHP and inserted in the output box. Boiler Efficiency As in all equipment covered by the program, energy savings for boilers are calculated using, as a baseline, the California Energy Commission s (CEC) minimum efficiencies. When the efficiency for the existing boiler is less than the CEC minimum efficiency, the savings are calculated as the differential between the CEC minimum efficiency and the proposed boiler efficiency. In cases where the efficiency of the existing boiler is greater than the CEC minimum, the savings will be calculated as the differential between the existing and proposed efficiencies. Building Type Select the building type that is closest to the project building. Building Construction Year Select the appropriate period of building construction. Occupancy Schedule Select the Occupancy Schedule of Low, Medium, or High that best represents your project s schedule. The days per week and start and stop times per day of the heating equipment will be shown in the Occupied Hours field that represents the Occupancy Schedule selected. City Select the city where the building is located. The city selected will determine the CEC weather zone. Building Size Enter the floor area of the building in ft 2. Setback Specify if the boiler has temperature setback controls. These controls lower the heating set point to 60 degrees during periods when the building is unoccupied. If this is not selected, it is assumed the building temperature will not be regulated (i.e. no heating) during unoccupied periods. The type of CEC minimum efficiency (AFUE, thermal or combustion) is dependent on the size of the boiler. See Table 2-5 CEC Minimum Efficiencies for Natural Gas Fired Boilers. February 25, Version 1.1

83 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings The procedures for retrofits with multiple boilers are as follows: Multiple Boilers Replacing a Single Boiler - Indicate the number of proposed boilers in the quantity field. Enter the value for one of the multiple boilers in the proposed Input (Btu/hr) and Output (Btu/hr) fields (the energy input value is used to determine the type of efficiency and CEC minimum efficiency). If the proposed boilers are not identical in energy output and efficiency you must use the Engineering Calculations method of energy estimation. Single Boiler Replacing Multiple Boilers - Indicate the number of proposed boilers in the quantity field. If the existing boilers are not of the same output and efficiency, use the average efficiency, input energy rating, and output energy rating. This information should be entered as a single unit not the sum of all the units. Multiple Boilers Replacing Multiple Boilers - Indicate the number of proposed and existing boilers in the quantity fields. Enter the value for one of the multiple boilers in the proposed Input (Btu/hr) and Output (Btu/hr) fields (the energy input value is used to determine the type of efficiency and CEC minimum efficiency). If the existing boilers are not of the same output and efficiency, use the average efficiency, input energy rating, and output energy rating. This information should be entered as a single unit, not the sum of all the units. Table 2-5. CEC Minimum Efficiencies for Natural Gas Fired Boilers 1 Steam & Hot Water Boilers Size (Btuh Input) Steam (min eff.) Hot Water (min eff.) <300,000 75%a 80%a > 300,000 80%c 80%c a = AFUE t = Thermal Efficiency c = Combustion Efficiency Definitions: AFUE (Annual Fuel Utilization Efficiency) AFUE is a measure of the percentage of heat from the combustion of natural gas or oil that is transferred to the space being heated during a year, as determined using the applicable test method in the Appliance Efficiency Regulations of paragraph 112. The AFUE is usually lower than thermal efficiency because it takes into account the effects of equipment cycling or modulation at loads than design. It is calculated using the prescribed annual load profile. (P ) Thermal Efficiency is defined in the Appliance Efficiency Regulations as a measure of the percentage of heat from the combustion of natural gas which is transferred to the water as measured under test conditions specified % Thermal Eff = Energy to Medium/total Fuel Input (P ) Combustion Efficiency is not defined in the Standards, but is used as the efficiency measurement for large boilers and service water heaters. It is a measure of the percent of 1 For Boilers with <300,000Btuh input see CEC document Appliance Efficiency Regulations Table E-3 & E-5, P For Boilers with input >300,000Btuh <2,500,000 see CEC document 2005 Energy Efficiency Standards for Residential and Non-Residential Buildings Table 112-F. For Boilers with input >2,500,000 see CEC document 2001 Energy Efficiency Standards for Residential and Non-Residential Buildings Table 1-C6. February 25, Version 1.1

84 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings energy transfer from the fuel to the heat exchanger (HX). Input and output energy are expressed in the same units so that the result is non-dimensional: % Combustion Eff = Energy to HX/Total Fuel Input Note: Combustion Efficiency does not include losses from the boiler jacket. It is strictly a measure of the energy transferred from the products of combustion. (P ) Replace Process/Industrial Boiler(s) This tool calculates the energy savings and incentive for replacing existing steam or hot water boiler(s) with new boiler(s) of higher efficiency. This method is specific to process/industrial heating loads as opposed to space heating loads. The energy output from the proposed boiler can be larger than the output from the existing boiler. The 2009 program does provide incentives for increased capacity. For space heating loads served by a boiler see Section Boiler Data The project sponsor shall provide with the application, a copy of the manufacturer s specification sheets that detail the replacement boiler s output, input and efficiency and other data pertaining to the boiler s operation. In some instances the boiler s output maybe rated in Boiler Horsepower (BHP). BHP should be converted to Btu/hr by the factor of 33,476 Btu/hr per BHP and inserted in the output field. Average Annual Load Typically boilers do not operate at full load over their entire operating schedule. The project sponsor shall estimate the Average Annual Load on the boiler(s) as a percent of boiler(s) full load. The project sponsor will provide along with the application, data (e.g. steam flow data, gas meter data, etc.) backing up the estimate made for the Average Annual Load. This supplied data will facilitate the review of the application. Boiler(s) Operating Hours This value may or may not be equal to the operating hours of the facility. The project sponsor shall provide for Utility Administrator review, data that supports the estimate of the operating hours used in the calculations. Boiler Efficiency Industrial/process boilers are not covered under Title 20 or Title 24. The minimum baseline efficiency for industrial/process boilers is the industry standard for packaged industrial/process boilers. This is estimated to be 78% thermal efficiency. Additionally, very large industrial/process boilers (10 MMBtu and larger) are often custom built and therefore the industry standard efficiency of packaged boilers is not applicable to these very large custom boilers. To accommodate this, a Custom Boiler box has been added to the Customized process boiler calculator. When this box is checked, the calculator allows the user to input a baseline thermal efficiency lower than 78%. Please note that the Project Sponsor must provide documentation to verify baseline thermal efficiencies lower than 78%. The procedures for retrofits with multiple boilers are as follows: Multiple Boilers Replacing a Single Boiler - Indicate the number of proposed boilers in the quantity field. Enter the value for one of the multiple boilers in the proposed boiler Input (Btu/hr) and Output (Btu/hr) sections. Average Annual Load and Operating Hours for multiple boilers should be calculated as the average of all boilers. If the proposed boilers are not identical in output energy and efficiency, separate software runs will have to be performed. Single Boiler Replacing Multiple Boilers - Indicate the number of existing boilers in the quantity field. Enter the value for a single boiler in the existing boiler Input (Btu/hr) and Output (Btu/hr) sections. If the existing boilers are not identical in output energy and efficiency, separate software runs will have to be performed. February 25, Version 1.1

85 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Multiple Boilers Replacing Multiple Boilers - Indicate the number of proposed and existing boilers in the quantity fields. Enter the value for one of the multiple boilers in the proposed Input (Btu/hr) and Output (Btu/hr) fields (the energy input value is used to determine the type of efficiency and CEC minimum efficiency). If the existing boilers are not of the same output and efficiency, use the average efficiency, input energy rating, and output energy rating. This information should be entered as a single unit not the sum of all the units. Add an Economizer to a Process Boiler This tool is to be used for calculating the energy savings by adding an economizer to an existing boiler that provides heating to a non-space heating load. An economizer recovers heat from the flue gas and transfers it to the boiler feedwater. Boiler Data In some instances the output from a boiler may be rated in Boiler Horsepower (BHP). BHP should be converted to Btu/hr by the factor of 33,476 Btu/hr per BHP and inserted in the output box. Economizer Data The Project Sponsor will provide the flue gas temperature entering and leaving the economizer. Data supporting the entering flue gas temperature shall be supplied (measured or other means) with the Project Application. The Project Sponsor shall supply manufacturer s data documenting the operating conditions of the economizer for this specific boiler. Manufacturer s data for the economizer shall include: 1) Entering and leaving flue gas temperatures, 2) Entering and leaving water temperature, 3) Water (gal/min) and gas (#/hr) flows, 4) Energy transferred from flue gas to water (Btu/hr). This data will be entered in the Estimation Software. Average Annual Load It is recognized that boilers do not operate at full load for all of their operating hours. The Project Sponsor will estimate the Average Annual Load on the boiler as a percent of boiler full load. The Project Sponsor will provide with the calculation software sheets submitted with the Application, data (e.g. steam flow data, gas meter data, etc.) backing up the estimate made for the Average Annual Load. This supplied data will facilitate the review of the application. Boiler(s) Operating Hours This value may or may not be equal to the operating hours of the facility. The Project Sponsor shall provide data that supports the estimate of the operating hours used in the calculations for Utility Administrator review. February 25, Version 1.1

86 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Gas - Thermal Oxidizer Upgrades (PG&E and SDG&E Only) One method used to destroy the volatile organic compounds (VOC) in a contaminated airstreams is to oxidize, (burn) the solvents with high temperature, combustion-based systems. Thermal oxidizers work by converting hydrocarbons into carbon dioxide and water. There are five main types of combustion based VOC emission control devices: Thermal Oxidizers (with no heat recovery), Catalytic Oxidizers, Recuperative Thermal Oxidizers, Regenerative Thermal Oxidizers (RTO), and Regenerative Catalytic Oxidizers (RCO). This tool covers retrofits involving the replacement of an existing thermal oxidizer with a more efficient oxidizer. It also covers measures involving the addition of a heat exchanger for heat recovery purposes (recuperative) on an existing thermal oxidation system. The tool is intended for oxidization systems that are used to destroy low concentration VOC waste streams (less than 25% Lower Flammable Limit). Examples of processes that create these contaminated airstreams are as follows: Coating Operations Printing Lines Paint Booths Textile Converters Textile Finishing Solvent Cleaning Packaging Food Processing and Baking Pulp and Paper Ventilation Odors Drying Rendering Plants Certain Chemical Processes Sewage Treatment Plants Computer Chip Manufacturing (Semiconductors) Significant Energy savings can be achieved by replacing an existing thermal oxidizer, catalytic oxidizer, or recuperative oxidizer with a regenerative thermal oxidizer. For processes with the appropriate waste gas stream a regenerative thermal oxidizer retrofit can save significant electric (reduced combustion fan usage) and natural gas (reduced supplemental fuel requirements) usage. The amount of savings is highly dependent on the characteristics of process, existing equipment type, and proposed equipment type. This tool does not cover oxidizers that are used to destroy contaminated inert gas streams, rich gas streams, or contaminated air streams with an LFL (previously LEL- lower explosive limit) greater than 25% Data Inputs Waste Gas Stream and Site Information The following lists describe the input information necessary to estimate the energy savings and incentives. Because of the nature of the air quality requirements associated with Thermal Oxidizers much of this information is readily available from the permitting processes. Waste Gas Stream Information Average VOC Concentration (LFL) Enter the Average VOC Concentration as expressed in terms of lower flammable limit (LFL) of the VOCs in the waste gas. The LFL (previously referred to as LEL - lower explosive limit) of an organic compound is its minimum concentration in air that will sustain combustion. The Average VOC Concentration is the actual volumetric concentration value divided by the theoretical volume concentration of the combined gases. This input is required if Average VOC Loading and Average VOC Heat of Combustion are not available. February 25, Version 1.1

87 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Average VOC Loading (lb/hr) Enter the Average VOC Loading as the mass (weight) of the waste gas produced per hour. Typically this information can be obtained from the Air Quality permit emission information. This input is required if Average VOC Concentration is not available. Average VOC Heat of Combustion (Btu/hr) Enter the average VOC heat of combustion as the heat content of the VOCs in the waste gas. Typically, this information can be obtained from the Air Quality permit emission information. This input is required if Average VOC Concentration is not available. Average Volumetric Flow Rate (SCFM) Enter the average volumetric flow rate of the waste gas at standard conditions. Average Entering Temperature ( F) Enter the average temperature of the waste gas during VOC destruction. This value should not average the ambient temperature when the oxidizer in operating at idle (unit at operating temperature but no oxidation occurring). Destruction Efficiency (%) Enter the required VOC Destruction Efficiency (some times referred to as Destruction Removal Efficiency - DRE) in terms of a percentage. This value is mandated by the governing air quality district. Site Information City - From the pull-down menu, select a city that best represents the site location. Site elevation is determined from ASHRAE weather data. Average ambient temperature is calculated based on the 16 weather zones from California Energy Commission s CTZ weather data. Annual Operating Hours (VOC Destruction) Enter the total number of hours in the year that the oxidizer operates during VOC Destruction. Annual Operating Hours (Idle) Enter the total number of hours in the year that the oxidizer operates at full temperature but with no waste gas flowing through the system. Measure Type Select either Oxidizer Replacement or Auxiliary Heat Exchanger Installation Data Inputs for Oxidizer Retrofit Existing/Proposed Oxidizer Characteristics Manufacturer Enter the manufacturer of the Oxidizer. Model Number Enter the model number of the Oxidizer. Serial Number Enter the Serial number of the Oxidizer. Oxidizer Type From the pull-down menu, select the appropriate Oxidizer Type: Thermal Oxidizer (no heat recovery); Recuperative Catalytic Oxidizer (no heat recovery); Recuperative Thermal Oxidizer; Regenerative Thermal Oxidizer (RTO); Regenerative Catalytic Oxidizer (RCO). Thermal Efficiency (%) For Oxidizers with heat recovery, enter a thermal efficiency of the integral heat exchanger in terms of a percentage. For Thermal Oxidizer (no heat recovery) this field will not be available. Combustion Chamber Air Temp ( F) Enter the set point temperature that the oxidizer maintains in the combustion chamber during operation. This value is mandated by the governing air quality district. February 25, Version 1.1

88 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Existing/Proposed Oxidation (System) Fan Oxidation Airflow Resistance (Flange to Flange Pressure Drop Inches W.C.) Enter the total pressure drop across the oxidation side of the oxidizer in inches of H 2 O. Oxidation (System) Fan Motor HP Enter the rated horsepower of the fan motor on the oxidation side of the oxidizer. Typically this information can be found on the motor nameplate. Oxidation (System) Fan Motor Efficiency (%) This entry is automatically entered based on the selected Letter Code (see below) unless N/A is chosen. If N/A is chosen then enter the rated efficiency of the fan motor on the oxidation side of the oxidizer. Letter Code The fan motor efficiency as expressed by letter code. Typically, this information can be found on the motor nameplate. Existing/Proposed Combustion Blower Combustion Blower Average Air Flow Rate (SCFM) Enter the average volumetric flow rate of the combustion air at standard conditions. Combustion Blower Motor HP Enter the rated horsepower of the fan motor on the combustion side of the oxidizer. Typically, this information can be found on the motor nameplate. Combustion Blower Motor Efficiency (%) This entry is automatically entered based on the selected Letter Code (see below) unless N/A is chosen. If N/A is chosen then enter the rated efficiency of the fan motor on the oxidation side of the oxidizer. Letter Code The fan motor efficiency as expressed by letter code. Typically, this information can be found on the motor nameplate. Combustion blower fan operates during idle Check this box if the combustion fan runs during Oxidizer idle operation. Combustion blower fan operates during VOC destruction Check this box if the combustion fan runs during Oxidizer VOC destruction operation. Combustion blower fan draws outside air Check this box if the combustion fan draws fresh outside air. Leave this box unchecked if the combustion fan draws air/fuel mixture directly from the VOC laden waste stream Data Inputs for Heat Exchanger Installation Existing Oxidizer Characteristics Manufacturer Enter the manufacturer of the Oxidizer. Model Number Enter the model number of the Oxidizer. Serial Number Enter the Serial number of the Oxidizer. Average Combustion Chamber Temperature ( F) Enter the set point temperature that the oxidizer maintains in the combustion chamber during operation. This value is mandated by the governing air quality district. Exhaust Gas Temperature During VOC Destruction ( F) Enter the Average exhaust gas temperature during operation. Oxidation (System) Fan Motor Efficiency (%) This entry is automatically entered based on the selected Letter Code (see below) unless N/A is chosen. If N/A is chosen then enter the rated efficiency of the fan motor on the oxidation side of the oxidizer. February 25, Version 1.1

89 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Letter Code The fan motor efficiency as expressed by letter code. Typically, this information can be found on the motor nameplate. Oxidation Airflow Resistance (Flange to Flange Pressure Drop Inches W.C.) Enter the total pressure drop across the oxidation side of the oxidizer in inches of H 2 O. Proposed Heat Exchanger Manufacturer Enter the manufacturer of the heat exchanger. Model Number Enter the model number of the heat exchanger. Effectiveness (%) Enter the rated effectiveness of the proposed heat exchanger. Typically, this information is found in manufacturer s specifications. Heat Exchanger Pressure Drop (Inches W.C.) Enter the rated pressure drop in inches w.c. Typically, this information is found in manufacturer s specifications Basis for Energy Savings The energy saving estimating tool for thermal oxidizer retrofits uses simplified calculation procedures that are based on industry standards. These procedures capitalize on the fact that the waste gas stream consists primarily of air. An average density and mean heat capacity of the waste gas stream are determined based on this information. Thermodynamic equations are utilized to calculate the heat required to raise the waste gas to combustion temperature, the heat released from the VOCs, the radiated heat losses, and ultimately the additional heat required from natural gas. The general heat equations are as follows: Q FUEL = Q WASTEGAS + Q RADLOSS - Q VOC Where: Q WASTEGAS = Flow scfm * 60 min/hr * Density lb/scf * Heat Capacity BTU/lb F * F Q RADLOSS = Q WASTEGAS * % Heat Loss (based on oxidizer type) Q VOC = VOC Loading lb/hr * VOC Heat of Combustion BTU/lb -or- Q VOC = Flow scfm * 60 min/hr * Density lb/scf * Heat Capacity BTU/lb F * (VOC Concentration LFL * 25 F) Increased electrical usage is calculated using basic fan affinity laws. Pressure differentials, efficiencies and air flow are used as inputs. The general fan energy equation is as follows: kw FAN = BHP FAN * ; BHP FAN = (Flow acfm * Pressure inches w.c.) / (6,356 * FAN * MOTOR) The energy savings estimating tool for the heat exchanger installation utilize calculations based on standard heat balance and thermal efficiency equations. Mass flow and average temperature readings are used as inputs. The basic heat equations are as follows: Heat Exchanger Effectiveness (where mass flow in = mass flow out) - = (T CO T CI ) / (T HI T CI ) & = (T HI T HO ) / (T HI T CI ) Oxidizer Thermal Efficiency (where mass flow in = mass flow out) = (T COMBUSTION T EXHAUST ) / (T COMBUSTION T WASTEGAS ) Intermediate Calculations Intermediate Calculations are provided for oxidizer retrofits in order to display the heat balance equations. These values are displayed for the existing and proposed systems during idle and VOC destruction operations. The field elements are described below: February 25, Version 1.1

90 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Heat Required This value represents the estimated heat required to raise the waste gas stream to combustion chamber temperature. Heat Loss This value represents the estimated heat radiant loss through the oxidizer walls. Heat Released This value represents the estimated heat released through the oxidization of the VOCs in the waste gas stream. Auxiliary Heat Required - This value represents the estimated auxiliary heat required, beyond that released through VOC oxidation, in order to achieve the total Heat Required. Natural gas usage (therms) required during operation can be derived from this value Estimating Tool Outputs The thermal and electrical usages and the savings for the existing system and the proposed system are displayed on this screen. The incentive is calculated from these values. Oxidizer Replacement Therms/yr (Existing/Proposed/Savings) This value represents the estimated annual fuel usage. kw (Existing/Proposed/Savings) This value represents the estimated average annual electrical demand. kwh/yr (Existing/Proposed/Savings) This value represents the annual electrical usage. Incentive (Therms/yr) This value represents the natural gas incentive based on the annual fuel savings. Incentive (kwh/yr) - This value represents the electrical incentive based on the annual electric usage savings. Heat Exchanger Installation Therms/yr (Existing/Proposed/Savings) This value represents the estimated annual fuel usage. Increased Fan Electrical Consumption (equivalent therms) This value represents the increased fan usage for the added pressure drop associated with a heat exchanger installation. The value is converted into equivalent therms. The program uses a 10:1 electric to fuel conversion ratio. Therms/yr (Net Savings) This value represents the fuel savings minus the increased fan usage (equivalent therms) for heat exchanger installations. Incentive (Therms/yr) This value represents the natural gas incentive based on the annual fuel savings. February 25, Version 1.1

91 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Gas Steam Trap Replacement (PG&E and SDG&E Only) This tool is used to estimate the energy savings and associated incentive for replacement of a defective steam trap. To qualify, the steam trap must have previously been identified in a recent vendor steam trap survey as having failed in the open position and a copy of the survey must be provided to the Utility Administrator with the Project Application. Note that repair or rebuilding of defective traps does not qualify for an incentive; only complete replacement with a new steam trap qualifies under the existing program rules. Steam traps are automatic valves used to remove air, non-condensable gases and condensate from steam systems. The four most common types of steam traps include: thermodynamic, thermostatic, inverted bucket and float/thermostatic. Proper steam trap operation is crucial to efficient plant operation since failure in either an open or closed position can reduce plant efficiency or capacity. Steam traps can fail in either a closed or open position. Failure in a closed position can result in a buildup of condensate, which can reduce the flow capacity of steam lines and the thermal capacity of heat transfer equipment. Likewise a buildup of non-condensable gases can reduce steam pressure and temperature and may also reduce the thermal capacity of heat transfer equipment. Steam trap failure in an open position results in steam passing directly through the steam trap. When this occurs the steam provides none of the intended heating service and some or all of the steam energy may be lost. Energy loss in this instance is dependent on the design of the steam trap drain or condensate recovery system. Recovery systems that direct the condensate drains back to the boiler via a feedwater heater, such as a deaerator can help reduce this energy loss. Steam trap performance assessment is primarily concerned with determining if the trap is working properly and if not, whether it has failed in the open or closed position. Steam trap vendors can survey the steam traps in a facility, cataloging the important data for each trap. These data include the type and size of the trap along with the inlet steam conditions, condensate conditions and the operating status Data Inputs A copy of the steam trap survey results that support the user input data must be supplied to the Utility Administrator with the Project Application. Estimation tool data inputs include: Input Steam Trap Type Location Number of Traps Total Retrofit Cost ($) Steam Press. (psig) Description The type of steam trap involved (thermodynamic, thermostatic, inverted bucket, float/thermostatic) The physical location of the steam trap for purposes of locating the trap at the time of inspection. The number of leaking steam traps of this type with the same steam conditions. Total replacement cost of all of the steam traps of this type and size. The pressure (gauge) of the steam flowing in the line served by the steam trap. Steam Temp. (DegF), optional The temperature of the steam flowing in the line served by the steam trap. This field is optional when using the calculated steam properties option. If left blank, the steam properties will be calculated automatically based on the saturation temperature. Makeup Water Temp (DegF) The temperature of the boiler makeup water February 25, Version 1.1

92 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Steam System Annual Op Hours Boiler Effcy (%) Steam Property Entry Method Steam Enthalpy (btu/lb), optional Makeup Water Enthalpy (btu/lb), optional Manufacturer Model ID Number Line Size (inches) Orifice Size (inches) Condensate Recovered? Steam Trap Survey Provider Steam Trap Survey Date Leakage Rate (lbs/hr) (typically 55 to 65 DegF). The total number of hours that the steam system operates annually. The thermal efficiency of the boiler. Steam and makeup water properties can be entered manually using steam table values or the estimation tool will calculate the needed values automatically based on the steam and makeup water parameters entered above. The enthalpy of the steam flowing in the steam line served by the steam trap. The enthalpy of the makeup water. Manufacturer of the existing steam trap Model of the existing steam trap Steam trap tag/id number(s) should correspond to ID information in the steam trap survey. Steam trap inlet and outlet fitting size Steam trap orifice size from manufacturer s data Select YES if the output of the steam trap is collected and returned to the steam system for recovery of thermal energy. Select NO if the trap drain is vented to atmosphere or if the condensate is recovered without recovery of thermal energy. Name of vendor or individual/affiliation that performed the steam trap leakage survey Date of the steam trap survey that identified the steam trap as having failed in the open position Estimated steam loss rate in lbs/hr for a specific trap as noted in the vendor survey Basis for Energy Savings Unlike other savings measures, the proposed energy use of the new steam trap is assumed to be zero while the baseline energy use of the existing trap is equal to the energy loss associated with steam passing directly through the defective trap. In other words, the energy savings are equal to the abnormal energy loss associated with the defective trap. No attempt is made to quantify steam trap energy loss for a normally functioning trap under the assumption that this baseline energy loss would remain the same for the replacement trap compared to the defective steam trap. The energy savings calculation is the product of the mass flow of the escaping steam and the equivalent energy of the fuel needed by the central boiler to bring the boiler makeup water to the energy level of the escaping steam. The energy savings estimating tool estimates the mass flow of the escaping steam using the following assumptions: The flow is similar to that of an ideal gas through an isentropic nozzle The backpressure at the leaking steam trap (atmospheric pressure) is below the critical flow pressure; the flow is therefore assumed to be choked. February 25, Version 1.1

93 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Steam Mass Flow Calculation Based on these assumptions the mass flow rate, M, through the steam trap orifice is calculated using the following equation: M C d 2 D 4 T 1 P C 1 C 2 Where: C d = sonic discharge coefficient for square edged orifice, 0.8, no units π = Pythagorean constant, D = diameter of steam trap orifice divided by 2, inches C 1 = isentropic sonic mass flow constant for steam, sec R 0.5 /ft C 2 = conversion constant, 3,600 sec/h P 1 = pressure of steam in the line, psig T l = temperature of steam in the line, F The mass flow of the escaping steam is highest for a steam trap that has failed in the fully open position. While this is a common failure mode it is also true that the actual orifice size is unlikely to correspond to the full orifice size of the steam trap. The U.S. Department of Energy recommends that lacking better data it is prudent to assume the orifice of the defective trap is equal to one-half of the size of the fully open valve. It for this reason that the steam trap orifice diameter, D, in the above expression is divided by two. It is important to note that the estimation tool compares the estimated mass flow as calculated above with the estimated leakage rate noted in the vendor steam trap survey (user input) and uses the lesser of the two values to calculate the energy loss value. Energy Loss Flow Calculation Having estimated the mass flow of the escaping steam flow, the annual energy loss (ES) can then be calculated using the following expression: ES max where N M H h 2 h 1 N Eff C M H Eff ( h2 h1) C = number of traps of a given size, no units = mass flow rate per trap, lb/h = annual hours during which trap is passing steam, h/yr = enthalpy of steam at line pressure, Btu/lb = enthalpy of makeup water, Btu/lb = boiler efficiency (no units) = conversion constant, 100,000 Btu/Therm The estimation tool software will use this energy loss value unless the user has indicated that the condensate energy is recovered. If the user has indicated that the thermal energy of the escaping steam is recovered (user selected YES in response to Condensate Recovered? input) then the estimation tool software reduces the above estimated value using the following expression: ES ( 1 Eff ) ES max February 25, Version 1.1

94 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings This reduction is based on the assumption that the boiler will need to replace the escaping steam and the system will therefore experience the loss associated with boiler inefficiency while this steam is produced. February 25, Version 1.1

95 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Lighting - Lighting Retrofit The Lighting Estimating Software tool addresses the replacement of existing lamps and fixtures with units of higher efficiency. Proposed equipment for T8 and T5 linear fluorescent lighting upgrades must meet the Color Rendering Index and Lamp Life specifications listed in Table 1-2, Section 1.4 for definition. LED fixtures must be specifically listed in or comply with the testing standards and requirements described in Appendix I. Table I1 includes EnergyStar and Utility approved LED fixtures. LED lamp-only replacements are not eligible. De-lamping measures are eligible only as an integral part of a lighting efficiency upgrade. The removal of bulbs and/or the disabling of fixtures alone are not eligible for the program. Lighting retrofits that include the retention of existing ballasts are eligible only if the ballasts have at least five year of useful life remaining. The Utilities may require the Project Sponsor to certify the remaining useful life of the existing ballast. Multiple line items (i.e. groupings of similar fixtures and similar usage patterns) can be entered as a single measure. Lighting fixtures and the associated savings are grouped by usage. Usage groups may include offices, restrooms, hallways/stairs, display lights, sales floor, process areas, and parking areas or structures. Inputs for each usage group should include a brief description of the area affected by the lighting, as well as specifications for both existing and new equipment. Pull-down menus are used to simplify this process, but input of custom fixtures is also supported. If a particular lamp/fixture/ballast combination is not contained within the pull-down menus, N/A# will appear in the Watts/Fixture column and you must provide the necessary specifications by including a copy of the manufacturer s specification sheet along with the submittal documents. For measures involving partial delamping (e.g., removing two lamps from a three-lamp fixture), spot measurements used to verify fixture loads must be input into the Proposed Equipment Manufacturer s Data/Spot Measurements table. For lighting measures you may estimate the operating hours, but you should be able to support the estimate. Typically proposed operating hours should not differ from existing operating hours User Inputs User inputs can be divided into two basic categories - measure information and equipment specifications (existing/proposed). Measure Information Line Item Select a unique line item number for each lighting retrofit, consisting of identical equipment, within the same usage group. Usage Group Enter an identifying name for a grouping of fixtures that have similar operating characteristics (i.e. they are turned off and on at the same time). A usage group may have multiple line items containing sub-groupings of identical fixture retrofits. Area Description Enter a short description of the area of the proposed fixture retrofit (e.g. Warehouse, Building 123, Conference Room, etc.) Equipment Specifications (Existing/Proposed) Line Item Select the appropriate line item number for each lighting retrofit. Num Fixtures Enter the number of proposed/existing fixtures. Hours of Operation Enter the number of annual hours the existing fixtures operate. The proposed fixture operating hours are the same as the existing hours and can not be modified. February 25, Version 1.1

96 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Fixture Type Choose Standard if the fixture is identified in the Standard Table of Fixture Wattages in Appendix B. Choose Custom if the fixture is not identified on this table or the Itemized (Express Efficiency) Measures Table 2.1 above. Measures identified on the Itemized (Express Efficiency) Measure table are not eligible for the Customized Approach. Lamp Type Select the lamp type (i.e. T12 Fluorescent, HPS, Incandescent, etc.) Tube Length For tube fixtures select the tube length in inches. For non-tube fixtures select N/A. Ballast Type Select the ballast type for fixtures equipped with ballasts (i.e. Magnetic, Electronic, etc.). Select N/A for non-ballast fixtures. Lamps/Fixture Select the number of lamps per fixture. Watts/Lamps Select the nominal watts per lamp. February 25, Version 1.1

97 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Lighting - Lighting Controls The Lighting Controls savings estimation tool covers the installation of occupancy sensors, time clocks, and lighting energy management systems (EMS) for lighting replacements and existing lighting systems. Measures involving day-lighting or daylight harvesting cannot use this tool and must use the Engineering Calculations approach. Lighting Controls line items are grouped by lighting equipment type and space type. Individual controls that regulate different light types or have different usage patterns should be grouped separately. The Lighting Controls estimating software calculates the energy savings as the difference between the energy usage of the lighting equipment in an uncontrolled (pre-installation) and a controlled (post-installation) state. The energy demand of the lighting equipment is calculated from information entered by the user. Information such as, lamp and ballast specifications, are selected from pull-down lists. For EMS and timeclock type measures, the user enters previous operating hours (preinstallation) and new operating hours (post-installation). These hours must correspond to actual hours the lights are energized prior to the installation of the controls and the proposed hours from the scheduled operation. The programmed schedule in the EMS will be independently verified by the Utility Administrator Inspector. For occupancy sensors, enter previous operating hours (pre-installation) and a space type (i.e, warehouse, office, bathroom, etc.). The software estimates the amount of savings (time the lights will be de-energized by the occupancy sensor) based on the space type and applies it to the baseline (pre-installation) hours. The energy savings (kwh) are calculated as the product of the lighting energy demand (kw) and the reduction in on-time (hours). Table 2-1 lists the allowable reduction in operating time based on space type. Table 2-1. Occupancy Sensors Reduction in Operating Time Space Type % Savings Space Type % Savings Space Type % Savings Assembly 45 Industrial 45 Restroom 45 Break room 25 Kitchen 30 Retail 15 Classroom 30 Library 15 Stair 25 Computer Room 35 Lobby 25 Storage 45 Conference 35 Lodging (Guest Rooms) 45 Technical Area 35 Dinning 35 Open Office 15 Warehouses 45 Gymnasium 35 Private Office 30 Other 15 Hallway 25 Process 45 Parking Garage 15 Hospital Room 45 Public Assembly User Inputs User inputs can be divided into two basic categories - measure information and equipment specifications. Measure Information Line Item Select a unique line item number for each lighting control retrofit, consisting of identical equipment within the same usage group. February 25, Version 1.1

98 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Control Type The control technologies eligible for the offering using the Estimating Software are EMS, occupancy Sensors, and time clocks. Day-Light Harvesting or Day- Lighting systems must use the Engineering Calculations approach to estimate energy savings. Usage Group Enter an identifying name for a grouping of lighting controls that have similar operating characteristics (i.e. they are turned off and on at the same time). Area Description Enter a short description of the area covered by the lighting controls (e.g. Warehouse, Building 123, Conference Room, etc). Equipment Specifications Line Item Select the appropriate line item number for each lighting retrofit. Num Fixtures Enter the number of proposed/existing fixtures. Previous Op Hours Enter the number of annual hours the fixtures operate prior to the installation of lighting controls. New Op Hours - Enter the number of annual hours the fixtures operate after the installation of lighting controls. Automatically calculated for occupancy sensor measures. Space Type Select the space type from the pull-down list that most closely describes the primary function/purpose of the illuminated area. Fixture Type Choose Standard if the fixture is identified in the Standard Table of Fixture Wattages in Appendix B. Choose Custom if the fixture is not identified on this table. Lamp Type Select the lamp type (i.e. T12 Fluorescent, HPS, Incandescent, etc). Tube Length For tube fixtures select the tube length in inches. For non-tube fixtures select N/A. Ballast Type Select the ballast type for fixtures equipped with ballasts (i.e. Magnetic, Electronic, etc.). Select N/A for non-ballast fixtures. Lamps/Fixture Select the number of bulbs per fixture. Watts/Lamps Select the nominal watts per bulb. February 25, Version 1.1

99 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - A/C Economizers This tool calculates savings for the addition of an economy cycle on existing HVAC equipment. The 2010 Statewide Customized Offering software calculates savings using the Engage Software for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. This tool has four input screens. The following inputs should be noted: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. Building Area Enter the total building area. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Seasons- Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o o Sheet 2 The user has the ability to define up to three seasons. Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. Air-Side Economizers inputs (Sheet 4): Cooling Equipment Served (tons): Total capacity of cooling equipment served by economizers. Indicate the cooling capacity of all Cooling Equipment Served by Economizers. Input should be in tons of total (sensible + latent) cooling capacity, where the tons input here represents the sum of the rated (i.e., nominal) capacity of all systems for which economizers are being added or repaired. Baseline Economizer Type - Use these inputs to describe the existing economizer type: o o Drybulb Temperature the economizer is enabled whenever the outside air drybulb temperature is below the maximum allowed drybulb temperature (i.e., high limit drybulb temperature). Enthalpy the economizer is enabled whenever the outside air outside air enthalpy is below the maximum allowed enthalpy (i.e., high limit enthalpy) Proposed Economizer Type - Use these inputs to describe the economizer type being installed or repaired: o o Drybulb Temperature the economizer is enabled whenever the outside air drybulb temperature is below the maximum allowed drybulb temperature (i.e., high limit drybulb temperature). Enthalpy the economizer is enabled whenever the outside air outside air enthalpy is below the maximum allowed enthalpy (i.e., high limit enthalpy). February 25, Version 1.1

100 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Minimum Outside Air Control Method - These inputs are used only with Variable Air Volume (VAV) systems. Use this input to describe the Minimum OA Control Method employed by the VAV air handlers on which economizers are being installed or repaired. o Fraction of Design Flow this selection indicates that code-required levels of outside air are maintained even when VAV systems back off from their design (maximum) flow. This will have the effect of providing a constant amount of outside air (in terms of flow), which during times of reduced VAV flow will require that the outside air be increased as a fraction of hourly system air flow. Constant outside air flow on VAV systems can only be achieved with special controls not commonly available in most VAV systems. Newer packaged VAV systems now usually include controls necessary to accomplish this. In built-up CHW VAV systems, this type of constant outside air flow can only be achieved using flow sensors or other means to detect outside air flow and then adjusting outside air dampers accordingly. o Fraction of Hourly Flow this selection indicates that code-required levels of outside air may not necessarily be maintained when VAV systems back off from their design (maximum) flow. This will have the effect of providing a reduced amount of outside air (in terms of flow) when the VAV system reduces flow from maximum levels. Under this scenario, outside air flow remains a constant fraction of hourly system air flow. This Minimum OA Control Method is most common, especially in built-up CHW VAV systems, where the controls necessary to achieve constant outside air flow are not provided. February 25, Version 1.1

101 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Carbon Monoxide Sensors for Parking Garages This tool provides the energy savings estimate for exhaust fans in enclosed parking structures when these fans are controlled by Carbon Monoxide sensors. Exhaust fans are typically on 24 hours/day or controlled by time clocks. Controlling fan on-time using CO sensors to maintain an acceptable limit on CO in the parking structures can result in significant energy savings. A number of parking structures with their exhaust fans under CO control were metered to determine the run-time of the exhaust fans. This tool is appropriate for all building types with enclosed parking structures. Data inputs for CO mitigation for parking structures include: Manufacturer of CO Controls/Sensors - Enter the name of the manufacturer of the CO Controls/Sensors. Model Number of CO Controls/Sensors - Enter model number of CO Sensors. Number of CO Sensors in Parking Structure - Enter the number of CO Sensors in Parking Structure. Total Exhaust Fan Motor(s) HP - Enter the summation of HP for all exhaust fans. Average Exhaust Fan Motor Efficiency - Enter the motor efficiency if there is only one exhaust fan. If there is more than one exhaust fan, calculate an average motor efficiency. Annual Operating Hours before CO Controls - Provide the annual operating hours of the exhaust fans before the installation of the CO Sensors. Savings Estimate - The savings estimate and incentive is provided on screen two of this tool. February 25, Version 1.1

102 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Cold Storage Rapid Close Doors Rapid close doors save energy by lowering infiltration. This can be achieved by improving the seal of the doorway, increasing the door speed and/or reducing the amount of time the door simply stands open. The methodology for estimating energy savings for this measure is well documented (2002 ASHRAE Refrigeration Handbook, Refrigeration Load, Page 12.3). The software allows the user to specify multiple retrofit types. Retrofit types must share similar operating schedules, doorway specifications, traffic flow, etc. The required inputs are detailed below. Site Information: Number of Doorway Types -- Enter the number of doorway retrofit types. Recall each type must have similar characteristics and usage patterns. City Select the site location. Doorway Characteristics (Existing and Proposed): For each doorway type, edit the existing and proposed doorway and operating characteristics. To edit a doorway type, the user must highlight it in the table and click Edit Existing, Edit Proposed or Edit Operation, or edit it through the Equipment Description and Operating Characteristics Forms by selecting the doorway type number. Building Identification Enter the building identification. Number of Doorways Enter the number of like doorway retrofits. Doorway Width (ft) Enter doorway width. Doorway Height (ft) Enter doorway height. Opens to Select the door opening type. The options are freezer-to-cooler, freezer/cooler-to-loading dock, conditioned and unconditioned, and various exterior door openings. If the door does not open to the outside or an unconditioned loading dock, the user needs to input the cooler or loading dock temperature and a default value of 80% relative humidity is assumed but can be adjusted. See below. Refrigeration System Efficiency Enter the rated efficiency of the refrigeration system and select the appropriate units. The rated efficiency should be based on design conditions at entering ambient air temperatures of 95 F dry-bulb for air-cooled condensers and 75 F wet-bulb for evaporative-cooled condensers, and 85 F entering water temperature for water-cooled condensers. If the door opens to a conditioned space, the exterior cooling efficiency needs to be input. Condenser Type Selection the refrigeration system condenser type: air-cooled, watercooled, or evaporative-cooled. Controls Select the refrigeration controls: fixed or floating head. Doorway Protective Device Select from the following doorway protective devices: none, strip curtains, strip curtains with air-lock vestibule, dual impact (or push-through) doors with air-lock vestibule, vertical non-recirculating air curtain, dual horizontal recirculating air curtain, dual horizontal recirculating air curtain with outer strip curtain, standard-folding doors, standing-sliding curtains, standard-sliding doors, rapid-folding doors, rapid-sliding curtains and rapid-sliding doors. Door Insulation Enter the door insulation type. This information is for review purposes only; it does not impact the savings calculation. February 25, Version 1.1

103 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Insulation Thickness (in.) Enter the door insulation thickness. This information is for review purposes only; it does not impact the savings calculation. U-Factor (Btu/hr ft F) Enter the overall coefficient of heat transfer (U-Factor). The U- Factor accounts for inside surface conductance, total door thermal conductance and outside surface conductance. Please provide manufacturer s specification for the existing, if available, and proposed doors. For a summary of the principles of heat transfer, refer to the 2001 ASHRAE Fundamentals Handbook, Pages Other variables that may impact the thermal conductivity are wind and solar exposure. For a detailed discussion of their effects, refer to the 2001 ASHRAE Fundamentals Handbook, Pages and 30.11, and 2002 ASHRAE Refrigeration Handbook, Page Door Open-Close Time (sec) Enter door open-close time. This is the time it takes for the door to open and close. For conventional pull-cord operated doors, this value typically ranges from 15 to 25 seconds per passage; for high speed doors, it can range from 5 to 10 seconds depending on the means of control and the control setpoint. Open Doorway Protective Device The open-doorway device is a secondary device that restricts infiltration when the main door is open. In some cases, the doorway and open-doorway protective devices may be the same. For example, strip curtains may be the only doorway protective device. Select from the following open doorway protective devices: none, strip curtains, strip curtains with air-lock vestibule, dual impact (or pushthrough) doors with air-lock vestibule, vertical non-recirculating air curtain, dual horizontal recirculating air curtain, dual horizontal recirculating air curtain with outer strip curtain, rapid-folding doors, rapid-sliding curtains and rapid-sliding doors. Operating Characteristics - The user may input annual or monthly values for the following. To input monthly value select the check box. Loading Dock / Cooler Temperature ( F) If the doorway does not open to the outside or to an unconditioned space, the user needs to specify the annual or monthly temperatures of the loading dock or cooler. If this cases, the default relative humidity is 80%, which can be edited by the user. Inside Temperature ( F) Enter storage temperature setpoint. Weekday Hours Enter the average work hours per weekday. Saturday Hours Enter the average work hours on Saturday. Sunday Hours Enter the average work hours on Sunday. Averages Openings per Hour Enter the average openings (passages) per hour for this door type. This is how many times the door opens and closes as a result of foot or forklift traffic. Average Open Time, Pre and Post (minutes) Enter average door open time, before and after installation. This is the time the door simply stands open. This could be the result of multiple forklift traffic or manually keeping the door open. February 25, Version 1.1

104 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Compressed Air System Upgrades This tool includes a variety of compressed air system measures. These include: Direct replacement of one or more compressors with compressor(s) of higher efficiency, including compressors equipped with variable speed drives, Installation of new compressor motors to service increased production capacity, Installation or upgrade of system storage, and Installation of intermediate pressure/flow control valves Compressor and Control Types The software accommodates up to 3 compressors of varying types and sizes. The compressor types and associated controls that will be accepted will continue to correspond to the types accepted by the AirMaster+ software (see Table 2-2). The only exception is that variable speed drive controls have been added to the rotary screw compressor types. Table 2-2. Equipment Included in Air Compressor Estimation Software Compressor Types Control Types Size (hp) Pressure (psig) Single-stage lubricantinjected rotary screw Two-stage lubricantinjected rotary screw Inlet modulation w/o unloading Inlet modulation w/unloading Load/unload Variable displ. w/unloading Variable speed drive Inlet modulation w/o unloading Inlet modulation w/unloading Load/unload Variable displ. w/unloading Variable speed drive Load/unload Variable speed drive Two-stage lubricant-free rotary screw Single-stage reciprocating Load/unload Two-stage reciprocating Load/unload Baseline Compressor Loading The project sponsor must enter an individual hourly load profile for each compressor, for up to 4 types of system operation ( day-types ). A load profile in either kw or acfm will be accommodated. Values entered in acfm are summed to arrive at the system usage profile and will also be converted into an equivalent kw demand for each compressor, using a generic performance map for each type of compressor. The project sponsor must identify day-types as having weekday operation (or not) so that the software can estimate the peak demand savings. Inputs for the estimated days per week and weeks per year are required for each day-type so that the software can estimate the annual energy usage. The software will continue to use the AirMaster+ specific power consumption as the minimum compressor efficiency. Thus the software will correct the baseline power if the baseline compressor(s) does not meet the minimum specific power consumption requirement. February 25, Version 1.1

105 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Efficiency Measure Multiple Compressor Replacement or Upgrade The tool will accommodate replacement or upgrade of multiple compressors. To accomplish this, the software must be able to reasonably estimate how the system flow will be distributed amongst the various compressors for each hour of the day and for each day-type. To simplify the analysis the project sponsor must: Specify each compressor as a Lead/Baseload, Additional Baseload or a Variable/Trim machine. Since a site is permitted up to three compressors, two may be designated as baseload and one as variable/trim. The software will automatically designate the compressor as variable/trim if 1 compressor is selected on the initial site set up screen. Keep the compressor designations fixed for all day-types and all hours of operation (i.e., the compressors must always be sequenced in the same fashion). Note that baseline designations may differ from proposed that in both cases they must be fixed across all day types. The software checks that new compressors meet the AirMaster+ specific power consumption requirement and will flag compressors that do not comply. The software also checks for the presence of automatic shut-off timers and/or sequencing controls (user inputs) that permit compressors to be turned off if fully unloaded. If these devices/controls are not present, then the software assumes that the compressor will operate at the fully unloaded operating point during any hour when a system flow is required (even if this flow is supplied by another compressor). Note that the software assumes that each compressor operates at the same pressure (nominal supply pressure) even though each compressor will operate at a slightly different pressure during actual operation. The user inputs for cut-in and cut-out pressure are used solely to estimate compressor cycle time (in conjunction with system storage) for compressors equipped with unloading type controls. Compressors equipped with variable speed drives are modeled using a straight-line approximation similar to a reciprocating compressor with on/off control except an additional 5% is added to the input kw to account for VSD drive inefficiency. The software will not allow VSD operation below 20% of rated capacity but will instead unload other compressor(s) to achieve the minimum flow Efficiency Measure Intermediate Flow/Pressure Controllers The software calculates savings associated with reduced compressor(s) power demand when supplying less overall airflow (due to a system pressure reduction) downstream of the flow/pressure controller. The user must input both the upstream (nominal supply pressure) and downstream pressure (nominal system operating pressure or end use pressure) that will be used with the new controller. The software uses these values to estimate the change in system airflow associated with leakage or other unregulated end uses (without individual pressure regulators). This reduced system airflow is used along with the upstream pressure to estimate the change in compressor energy use. Only unregulated end uses will be reduced and it is for this reason that the project sponsor must enter the estimated leakage rate (default of 5%) and the percentage of total system airflow represented by other unregulated end uses (default is 0%). Since storage located downstream of the controller will not have the same impact on compressor operation as storage located upstream of the controller the user must input the amount (%) of the existing system volume that is located upstream and downstream of the controller. These percentages are exclusive of any new storage, which is handled by inputs for the Storage System Upgrade measure. February 25, Version 1.1

106 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Efficiency Measure Storage System Upgrade The program software estimates savings associated with increased storage capacity. However, appreciable savings are only possible if the increased capacity permits one or more of the compressors to be turned off (cycle time exceeds auto shut down timer setting) that would otherwise operate at no load. Thus savings may not be indicated with certain types of compressors and controls. It is also important to note that storage location must be considered when an intermediate flow/pressure controller is involved. The project sponsor is therefore required to identify the amount of the new storage that will be located upstream and downstream of the intermediate flow/pressure controller (if the intermediate flow controller measure is also selected) User Inputs User inputs can be divided into four basic categories compressed air system, compressor description, usage/load profile and EEM selections. Compressed air system - Inputs include site location, number of compressors, nominal system (end use pressure) and compressor operating pressures (nominal supply pressure), and system volumes (total system and receivers). Compressor inputs (for each compressor) - Include nameplate data, operating mode (lead, variable/trim, etc.), control method and settings, and drive motor nameplate data (compressor and air-cooler). Usage profile/load data inputs - Include number and type of day-types, profile data type, days per week and weeks per year of operation for each day-type, and hourly air flow or kw demand data for each compressor. EEM Inputs for compressor replacement / upgrade - Inputs allow the project sponsor to identify which compressors will be upgraded, replaced or eliminated as well as changes to the operating mode. Changes specific to new compressors are subsequently entered via the compressor input screen(s). EEM Inputs for intermediate flow/pressure controller - Include pressure settings (upstream and downstream), storage volumes (% of existing volume) upstream and downstream of the controller, leakage air flow and other unregulated air flow (% of total flow). EEM Inputs for storage upgrade - Include total additional storage volume and location relative to compressor(s) and end uses (if an intermediate flow controller is also specified). February 25, Version 1.1

107 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Demand Control Ventilation (DCV) Background Outside air is typically introduced at a fixed rate, into buildings for the peak design occupancy level. Occupancy levels vary significantly during a buildings operating hours. Demand Control Ventilation (DCV) varies the amount of outside air introduced into the building based on occupancy level. The energy conserving attribute of DCV is heavily dependent on the variability of the occupancy level and climate zone. Reducing the amount of outside air can reduce the amount of energy to heat or cool the outside air in certain climate zones. Reducing outside air in certain climate zones (cool and dry) can increase energy consumption because the cooling effect of the outside air is reduced (no economy cycle scenario). Carbon Dioxide is used as an indicator of occupancy level. With the use of CO 2 sensors and a prescribed CO 2 concentration set point for the space, the amount of outside air can be varied. This is the basis of DCV; the amount of outside air introduced is based on the demand for it. In all cases DCV is overridden by economy cycle controls. When outside air (economy cycle) can be beneficial for cooling, DCV is not allowed to reduce the amount of outside air introduced Energy Savings Calculations The tool developed for the 2009 program is based on Honeywell s Savings Estimator. This program is also the basis for the California Energy Commissions VSAT (Ventilation Strategy Assessment Tool), which was used for the CEC s ventilation assessment program. The Savings Estimator is an hourly program that evaluates the energy impact of DCV. This tool evaluates the energy impact for cooling (not from heating) from the application of DCV control for rooftop package units. The default occupancy levels are based on work done by Lawrence Berkeley Labs (LBL). For each building type there is a default occupancy schedule used that cannot be changed. The fixed ventilation rate is determined by the peak design occupancy and ASHRAE Standard The thermostat set-point is 75 F for the occupied period. Data inputs for the Demand Control Ventilation action include: Manufacturer of DCV Controls - Enter the name of the manufacturer of the DCV controls. Model Number of DCV Controls - Enter Model Number of DCV Controls. City - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone. (The program uses the California Energy Commission s CTZ weather data, which breaks up the state into 17 weather zones.) Economy Cycle - Specify if an economy cycle is present in the rooftop equipment. Equipment Efficiency - Select Low (EER=8), Medium (EER=10) or High (EER=12) equipment efficiency for the rooftop package units. Building Type - From the pull down menu, select one of the 4 building types offered. February 25, Version 1.1

108 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Building Area - Enter the area in square footage of the building space that will have DCV. This could be several class rooms in a school, a portion of an office building or the dining area in a restaurant. This tool is primarily for smaller buildings. The accuracy is degraded when the area is larger than: Restaurant 21,000 ft 2 School 38,000 ft 2 Retail 300,000 ft 2 Small Office 25,000 ft 2 Savings Estimate - The savings estimate and incentive is provided on screen two of this tool. February 25, Version 1.1

109 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Injection Molding Machines High-efficiency injection molders use variable-speed drives (VSDs) and other energy efficiency techniques to reduce the energy usage of plastic injection molders. Standard-efficiency injection molders use a large hydraulic pump to inject the plastic and operate the molds. The pumps operate at full power continuously, bypassing the fluid when the pressure is not required. The VSD varies the speed of the motor to match the power requirements of the molders, cycling up and down the motor speed. A second approach uses variable volumes to achieve similar energy savings. Recently, a new type of machine has been introduced that does not use a hydraulic system to generate the pressure to inject the plastic, but instead generates the force with high-torque servomotors. Besides the drive system, other components of the machine such as the heaters have been improved. These machines are referred to as all-electric injection molders. They save significantly more energy than the variable-volume/variable-speed machines. All three types of machines are accepted as efficiency measures and are included in the estimation software Data Inputs Copies of manufacturer s specifications that support the proposed nameplate values must be supplied to the Utility Administrator with the Project Application. Data inputs include: Model/serial number Machine type: Standard Hydraulic, Variable volume, variable speed drive, all electric Capacity (tons) Hourly production rate: lbs/hr produced Annual operating hours - The annual hours must be the best estimate of the actual hours the machine is producing parts Basis for Energy Savings The energy savings estimating tool for high efficiency injection molders uses equations that are based on energy use per pound (kw/lb) of plastic produced. These parameters are based on measured performance data, which take into account variations in part size, production rates, and cycle time. Although individual machines may vary from these results, the predicted energy savings can be used for high-efficiency injection molders that produce at least pounds of plastic per ton of capacity. For machines with lower production rates, the energy savings are reduced by 20%. These low-production machines typically produce small, intricate parts requiring longer hold times, thus reducing the energy savings. The average specific energy use for the four types of injection molders is listed in Table 2-3. Table 2-3. Specific Energy Use of Different Injection Molders Machine Type Standard hydraulic Specific Energy Usage 0.91 kwh/kg Variable-volume hydraulic Variable-speed hydraulic All-electric 0.55 kwh/kg 0.55 kwh/kg 0.20 kwh/kg February 25, Version 1.1

110 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings The energy savings of the injection molder are based on the proposed production rates. The energy savings resulting from increased production are eligible in the 2009 program. The Project Sponsor is required to document the existing and proposed average production rates (lb/hr) of the injection machines. These rates shall take into account variation in parts produced. February 25, Version 1.1

111 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other Low Solar Heat Gain Coefficient Windows Low Solar Heat Gain Coefficient Windows save energy by reducing the transmission of heat from the outside to the inside of a structure during the hotter months. This results in a reduction in cooling load. In addition, during the colder months, heat loss is reduced due to an increase in the U-factor of the window. The 2010 Statewide Customized Offering software calculates savings using the Engage Software for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. Take special note of the following: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. Building Area Enter the total building area. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Seasons- Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o o Sheet 2 The user has the ability to define up to three seasons. Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. Low Solar Heat Gain Coefficient Windows inputs (Sheet 4): Orientation - Use these check boxes to indicate up to four orientations per glass type. The software allows orientation assignments for up to two glass types. The orientations selected for the existing windows case is applied to the proposed windows case. Performance Data Select either NFRC (national fenestration rating council) or glass manufacturer indicating the source utilized to obtain each window types U-factor and SHGC (solar heat gain coefficient). Solar Heat Gain Coefficient (SHGC) is the ratio of the solar heat gain entering the space through the window to the incident solar radiation. The U-factor is the overall coefficient of thermal transmittance of the whole window assembly (glass + frame), in Btu/(hr-sf-ºF), including air film resistance at both surfaces Window Area Enter total building window area in square feet, or enter window area by type and orientation in square feet. Savings Estimate - The estimated savings are reported on the fifth screen of this tool. Low Solar Heat Gain Coefficient Windows save energy by reducing the transmission of heat from the outside to the inside of a structure during the hotter months. This results in a reduction February 25, Version 1.1

112 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings in cooling load. In addition, during the colder months, heat loss is reduced due to an increase in the U-factor of the window. The 2009 software calculates savings using the DOE2 hourly energy simulation method. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. Take special note of the following: Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Orientation - Use these check boxes to indicate up to four orientations per glass type. The software allows orientation assignments for up to two glass types. The orientations selected for the existing windows case is applied to the proposed windows case. Performance Data Select either NFRC (national fenestration rating council) or glass manufacturer indicating the source utilized to obtain each window types U-factor and SHGC (solar heat gain coefficient). Window Area Enter total building window area in square feet, or enter window area by type and orientation in square feet. Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone. (The program uses the California Energy Commission s CTZ weather data, which breaks up the state into 17 weather zones.) Savings Estimate - The estimated savings are reported on the third screen of this tool. February 25, Version 1.1

113 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Motors Replacement or Early Retirement for Motors This tool covers early retirement of continuous-rated, polyphase squirrel cage induction motors rated from 1 to 500 horsepower. These motors include NEMA Design A and B, three-phase, 230/460 VAC, single-speed (900, 1200, 1800, and 3200 RPM) motors having open drip-proof (ODP) or totally enclosed fan-cooled (TEFC) or explosion-proof (TXPL) enclosures. This tool establishes the existing motor (baseline) efficiency to correspond to the 1992 Energy Policy Act (EPAct) minimum, except in the case of Early Retirement, which uses the industry standards at the time the motor was installed. If it does qualify for early retirement, the energy savings are calculated using the baseline efficiencies of the actual equipment rather than the current minimum standards. This results in a larger incentive than would be possible using the traditional Customized Approach. If the motor has been recently rewound, it may also qualify for early retirement. To establish the rewinding of a motor and when it was performed, supporting invoices are required. Data inputs for existing and proposed motors include: Year Manufactured Enter the year that the existing motor was manufactured. Rewound Select yes if the existing motor has been rewound Year Rewound If the motor has been rewound please enter the year in which it occurred. General data - Includes information such as the location (e.g., basement) and function of existing/replacement motors. Nameplate data - A comprehensive list of manufacturer s data is provided via pull-down menus. Copies of manufacturer s specifications that support the proposed motor nameplate values entered into the software must be submitted to the Utility Administrator with the Project Application. Load type - (e.g., fan, pump, mill, etc.). Estimated hours of operation - Operating hours under normal load conditions. Existing motor power measurements - These are critical for establishing brake horsepower (BHP, motor load). The preferred method is to measure power in kw, using a true RMS power meter. Next best would be to measure voltage, current, and power factor with a true RMS meter. At a minimum, both the voltage and current must be measured. Ensure that all voltages are measured line-to-line and measurements are taken under normal motor operation conditions. If power factor is not measured, then the software will estimate a power factor. The measured values are used to establish the load on the existing motor. For multiple motors with different horsepower, treat each motor size as a separate measure. February 25, Version 1.1

114 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Professional Wet Cleaning Replacement This measure is for the conversion of an existing dry cleaning (Perchlorethylene) facility to a professional wet cleaning facility. This measure is only for converting to professional wet cleaning, not CO2, Hydrocarbon, or Green Earth systems. This measure reduces the energy usage of cleaning facilities, while reducing containments to the air. This measure may qualify for additional incentives through your local air quality management district. This estimation tool is applicable only to professional cleaning facilities with a monthly average energy use of less than or equal to 4,000 kwh. Data inputs for existing and proposed motors include Average monthly electrical usage (kwh) - Electric usage for the past 12 months. This can be determined for your monthly electric bills from the past twelve months or by contacting you Electric Utility Service Representative. Facilities with a monthly average energy use of more than 4,000 kwh are not covered under this estimating tool. Average monthly electrical demand (kw) - Electric usage for the past 12 months. This can be determined for your monthly electric bills from the past twelve months or by contacting your Electric Utility Service Representative. The calculation model provides the following output: Estimated annual energy savings (kwh) Estimated demand reduction (kw) Incentive amount February 25, Version 1.1

115 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Pulse Cooling for Injection Molding Machines This tool is utilized to estimate savings achieved from the installation of pulse cooling retrofit units for injection molding machines. Injection molders typically inject molten plastic into a set mold, and release the final plastic product when sufficiently cooled. One conventional process to cool the plastic involves a constant flow chilled water system, which continuously cools the mold. However, this system often results in overcooling the mold at certain times in the molding cycle, which may result in a flawed product. To counteract this overcooling, thermolator units are often in place to cycle hot fluid (either oil or water) through the mold when needed. These thermolator units typically consist of an electric thermolator heater and a circulation pump. A pulse cooling unit consists of a controller, temperature probes, and water valves. This controller monitors the mold temperature and pulses chilled water to cool the mold only when needed to achieve a uniform product. At other times water flow is terminated, which avoids any overcooling of the mold. As overcooling is eliminated, the thermolator units often can be eliminated. The 2009 software calculates the electricity savings achieved by removing these thermolator units and replacing them with a pulse cooling unit, which consumes a relatively small amount of electricity. This 2009 software tool assumes the replacement of thermolator heating units with the installation of a pulse cooling unit. For injection molding retrofits which do not match the above scenario description, the engineering calculations approach should be used. Take special note of the following software inputs: Multiple circulation pumps - Multiple pumps may be entered together as long as they meet the following conditions: The pumps must be identical in capacity [HP or kw] (different model numbers are OK). If the pumps are serving multiple injection molders, the injection molder operating hours must be identical. Multiple thermolators - Multiple thermolators may be entered together as long as they meet the following conditions: The thermolators must be identical in capacity [kw] (different models numbers are OK). If the thermolators are serving multiple injection molders, the injection molders must have identical operating hours. The thermolators must have identical operating hours. Input power per thermolator, Nameplate rating option - The input power should be the capacity rating [kw] listed on the nameplate of the thermolator unit. If there is no nameplate rating visible, the rating should be found in the thermolator s manufacturer specifications literature. Input power per thermolator, Measured with power meter option - If power is measured with a meter and the instantaneous power of the thermolator fluctuates, power readings [kw] over an entire injection molding cycle shall be logged. An average of these readings shall be computed and input into this field. Annual hours of operation of thermolators - This value shall be the number of annual hours the thermolator heating units are in operation. This may differ from the injection molder hours, as thermolators may cycle on only when needed. The annual hours February 25, Version 1.1

116 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings should be determined by closely monitoring the thermolator operation runtime over a number of injection molding cycles. February 25, Version 1.1

117 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Pump-Off Controllers for Oil Wells This tool estimates savings for the installation of pump-off controllers on sucker rod pumping systems. Pump-off controllers save energy by reducing motor operation. Typically, these wells operate 24 hours per day regardless of their production level. When the wells are operating below capacity, the pump may experience a condition known as fluid pounding. Fluid pounding occurs when an insufficient amount of fluid, water and oil, is drawn into the well sleeve, decreasing the overall pumping efficiency. As a result, air can be drawn into the pump, decreasing the pumping efficiency of the well. The estimated savings is based on a simplified empirical model, which correlates volumetric efficiency, percentage runtime and percentage energy use. The results may not accurately reflect the performance of an individual well; rather they represent an average performance. Accurate modeling of an individual well requires a more complex simulation model, which is commercially available. The savings estimation tool requires the user to input a well s identification number, motor size, production level, annual hours of operation, pump diameter, pump downhole stroke length and pump stroke speed. Number of Wells - Enter the number of wells. Well Identification Number - Enter the well s identification number. This value can be numeric or alphanumeric. Motor Horsepower (hp) - Enter the rated motor capacity. Average Daily Production (bfpd) - Enter the average daily production in units of barrels of fluid per day. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment. Annual Hours (hr/yr) - Enter the estimated annual hours of operation. Pump Diameter (inches) - Enter the pump diameter. This is the inner diameter of the pump plunger. Stroke Length (inches) - Enter pump stroke length. This is the downhole stroke length of the pump. Strokes per Minute (spm) - Enter pump strokes per minute. February 25, Version 1.1

118 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other Pumping System Upgrades Pumping systems have been identified as one of the largest end use applications in industrial settings. Under the sponsorship of the DOE Motor Challenge program a computer program called PSAT (Pumping System Assessment Tool) was developed to assist end users in identifying and estimating pumping system energy saving opportunities. These opportunities include pump and/or motor replacement and resizing. This NRR-DR program estimation software utilizes some of the same methodologies as the PSAT tool but incorporates some basic assumptions to simplify its use. Savings associated with installation of variable speed drives (VSD) is also estimated; a measure that is not included in PSAT. This tool currently estimates savings for the following measures, either singly or in combination: Direct replacement of a pump with one of higher efficiency, Direct replacement of an electric pump drive motor with one of higher efficiency, and Installation of a variable speed drive on the electric pump drive motor. Currently the software will only accommodate measures involving a single pump. Therefore projects involving multi-pump systems should not use this tool to estimate savings Pump and Control Types The pump types and controls accommodated in the estimation tool software parallel those covered in the PSAT software. The exception is that this software will also calculate savings associated with positive displacement pumps while the PSAT software deals exclusively with centrifugal pumps. Table 20-1 summarizes the pump and control options covered by the estimation software. Table Equipment Included in Pump Savings Estimation Software System Type Pump Type Control Type Centrifugal Positive Displacement End Suction Slurry End Suction Sewage End Suction Stock End Suction ANSI/API API Double Suction Double Suction Vertical Turbine Large End Suction Multi-stage Boiler Feed Axial Flow Positive Displacement Throttling, On / Off, Variable Speed Drive* Recirc./Bypass w/ Constant Pressure, Variable Speed Drive* * -- part of energy savings measure only User Data Inputs The estimation tool software includes a total of eight input screens for entry of system, pump, drive motor, pump control, operating hour and energy efficient measure (EEM) information. User inputs can be divided into four basic categories pumping system, pump/drive description, usage/load profile and EEM selections. The following tables ( ) summarize the various estimation tool user inputs. February 25, Version 1.1

119 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Table Pump Savings Estimation Tool Inputs Input Screens 1 thru 3 Input Name Site / System: Type Input Sheet Description / Purpose Pump System Name Fill in 1 Identifies pump system involved Pump System Type Pull-down 1 Centrifugal or Positive Displacement Fluid Type Fill in 1 Fluid being pumped (i.e., water, etc.) Number of Pumps Pull-down 1 1 is the only selection Fluid Temperature, o F Fill in 1 Nominal temperature of fluid being pumped Fluid Specific Gravity Fill in 1 Specific gravity of pumped fluid (i.e., water at 60 F equals 1.0) System Design Flow, GPM Fill in 1 Maximum flow through pump(s) Total Developed Head (TDH) or Supply Pressure Max Flow, Ft Fill in 1 Total head at max system flow in Ft, or Supply Pressure (psig) for positive displacement pump applications System Static Head, Ft Fill in 1 System head requirement at 0 flow (centrifugal pump system only) Existing Pump Nameplate Data: Pump ID Fill in 2 Pump identifier / inspection purposes Manufacturer Fill in 2 Pump manuf. / inspection purposes Model Fill in 2 Pump model / inspection purposes Serial Number Fill in 2 Pump SN / inspection purposes Type Pull-down 2 See Table 3.x1 Control Type Pull-down 2 See Table 3.x1 Number of Stages Pull-down 2 Number of impellers / used to calculate specific speed (1-8) Flow, GPM Fill in 2 Flow at pump design point Total Developed Head (TDH), Ft or, Discharge Pressure, psig Fill in 2 Pump TDH at design flow (centrifugal) or, Pump Discharge Pressure (pos. displ.) Efficiency, % Fill in 2 Pump efficiency at design flow Existing Drive Motor Nameplate Data: Manufacturer Fill in 3 Motor manuf. / nameplate data Model Fill in 3 Motor model / nameplate data Size, HP Pull-down 3 Motor size / nameplate data Speed, RPM Pull-down 3 Motor rotating speed / nameplate data Enclosure Type Pull-down 3 ODP or TEFC/TXPL Service Rating Pull-down 3 Motor service rating; 1.15 or 1.25 NEMA Nominal Efficiency (full load) Fill in 3 EPACT min value is displayed for comparison purposes February 25, Version 1.1

120 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Table Pump Savings Estimation Tool Inputs Input Screens 4 & 5 Input Name Pump Operating Information: Type Input Sheet Description/Purpose Number of Operating Modes Pull-down 4 Number of different flow points that will be entered Operating Hour Input Pull-down 4 Yearly (total annual hours as input) or Daily (days/month as input) may be selected Operating Mode Information: Operating Mode Number Pull-down 4 Selections are 1 through the number of different operating modes entered above. Description Fill in 4 Name or description of operating mode (flow point) selected above (i.e., irrigating north fields, etc.) On-Peak Operation? Checkbox 4 Check this box if any pump operation during this operating mode occurs during the PG&E on-peak period. Average Flow Rate, GPM Fill in 4 Pump flow rate during this operating mode Pump Operating Information: Annual Operating Hours Fill in 5 Total annual operating hours for each operating mode. This field is only an input if the Operating Hour Input (sheet 4) selection was Yearly Day per Month Fill in 5 Table appears if Daily Operating Hour Input (sheet 4) was selected. Enter the number of days of operation for each operating mode for each month. Hours per Day Fill in 5 Table appears if Daily Operating Hour Input (sheet 4) was selected. Enter the number of hours of operation for each operating mode for each month. February 25, Version 1.1

121 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Table Pump Savings Estimation Tool Inputs Input Screens 6 thru 8 Input Name Measure Specification: Type Input Sheet Description/Purpose Pump Replacement/Modification Checkbox 6 Check this box if the pump or pump drive motor will be replaced Pump Replacement/Modification Pull-down 6 Select from this pull-down if the Pump Replacement/Modification checkbox was selected. Selections include Motor Only, Pump Only, Pump and Motor Variable Speed Drive (VSD) Installation Checkbox 6 Check this box if a variable speed drive will be installed. Full Load Efficiency, % Fill in 6 VSD efficiency at full load, 100% speed Minimum Operating Speed, % Fill in 6 VSD minimum operating speed Proposed Pump Data: Same inputs as existing pump -- 7 (see sheet 2) Drive Motor Nameplate Data: Same inputs as existing motor -- 8 (see sheet 3) Basis for Energy Savings As with any efficiency measure the estimated savings is the difference between the baseline and proposed energy usage. In the case of pump related measures the calculations can be divided into two basic types; those dealing with positive displacement pumps (i.e., rotary, screw, lobe, vane and reciprocating) and those dealing with dynamic pumps (i.e., centrifugal, mixed flow and axial) Baseline Energy Use -- Positive Displacement Pumps The electric demand of a positive displacement pump is calculated using the following expression. kw PUMP= Q D * P * D (Equation 20-A) 1714 * * where: Q D = Pump design flow (gpm) P D = Pump discharge pressure (psig) η p = Pump design efficiency η e = Drive motor efficiency P e Note that pump discharge pressure has been substituted for pump total developed pressure under the assumption that pump suction pressure will be very small relative to discharge pressure. February 25, Version 1.1

122 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings We assume that the baseline positive displacement pump is operating with a recirculating type control that provides for a constant pump flow and discharge pressure when driven by an electric motor without a variable speed capability. This is to say that while the system flow may vary for each of the operating modes, the pump flow and associated power will remain constant (as excess pump capacity is recirculated back to the pump suction). Likewise, pump efficiency is assumed to be equal to the design values regardless of system flow. The estimation software uses existing software functions (based on DOE MotorMaster) to estimate the electric motor efficiency (based on motor load). Baseline energy use is calculated as the product of the total operating hours and the pump electric demand with total operating hours equal to the sum of the operating hours for each of the system operating modes Baseline Energy Use Dynamic Pumps The electric demand of a dynamic pump such as a centrifugal or axial flow pump is calculated using the following expression. kw PUMP= S * Q * H * (Equation 20.B) 3960 * * P where: S = specific gravity of pumped fluid relative to water at 60F Q = fluid flow (gpm) H = Total developed head (Ft) η p = Pump efficiency η e = Drive motor efficiency e The specific gravity term in this expression, S, is considered constant and is based on the type and temperature of the pumped fluid. With the exception of pump flow, Q, the remaining terms will vary based on pump flow. Therefore this expression must be evaluated separately for each individual operating mode. Estimating Dynamic Pump Performance As noted previously, dynamic pump head and efficiency vary depending on pump flow and must be evaluated at each operating point. The total developed head and efficiency of a dynamic pump are typically characterized in a pump performance curve. These curves are generated by the pump manufacturer and are used to determine the pump operating point (head and efficiency) under varying flows. Since these curves can be difficult to locate for older pumps the estimation tool software assumes that pump performance will follow one of three generic pump curves. Curve selection is based on pump specific speed where pump specific speed is calculated using the following expression: RPM * Q Ns (Equation 20.C) 3 / 4 ( H / NS) where: NS Q H RPM = number of pump stages = pump design flow (gpm) = Total developed head (Ft) = Drive motor speed, rpm February 25, Version 1.1

123 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Pumps with a specific speed in the range of 300-4,999 are assumed to follow a radial pump curve (Figure 20. 1) while pumps with a specific speed in the 5,000 9,999 range are assumed to follow the mixed flow pump curve (Figure 20.2). Pumps with a specific speed equal to or exceeding 10,000 are assumed to follow the axial pump curve (Figure 20.3). Generic Head & Effcy Curve Shapes ( 300 > Ns > 5000) 1.40 H/HBEP N/NBEP Q / QBEP Figure Generic Dynamic Pump Curves (Radial) (normalized based on flow, head and efficiency at the Best Efficiency Point (BEP)) February 25, Version 1.1

124 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 1.80 Generic Head & Effcy Curve Shapes (5000 > Ns > 10000) 1.60 H/HBEP N/NBEP Q/QBEP Figure Generic Dynamic Pump Curves (Mixed Flow) (normalized based on flow, head and efficiency at the Best Efficiency Point (BEP)) February 25, Version 1.1

125 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 3.50 Generic Head & Effcy Curve Shapes (Ns > 10000) H/HBEP N/NBEP Q/QBEP Figure Generic Dynamic Pump Curves (Axial) (normalized based on flow, head and efficiency at the Best Efficiency Point (BEP)) Note that these pump performance curves are normalized based on pump design data. Normalizing the curves allows their use in estimating the performance of any dynamic pump as long as the pump design information (flow, head and efficiency) is provided by the user. It is important to note that actual pump performance may vary from the generic curve profile. Therefore, if the user has access to the manufacturer s pump curve information the user should use this information, either directly to estimate pump performance, or should compare the manufacturer s information against the generic curve to confirm that the estimation software is providing a reasonable estimate of pump performance. Matching System and Pump Performance In order to estimate the baseline energy use of a dynamic pump it is first necessary to locate where the pump is operating on its characteristic performance curve. In the case of a throttling type of control a control valve located on the pump discharge will increase or decrease the system loss causing the pump flow to decrease or increase until the pump flow matches the system requirement. For throttling type controls the pump flow is therefore equal to the system flow and the pump performance parameters are calculated using the previously discussed generic performance curves and the system flow value. For On/Off type controls there is no control valve on the discharge and the pump flow will therefore only be limited by the system losses. This limitation is represented by the intersection of the system loss and pump performance curves. For On/Off controls the estimation software must therefore locate this intersection. An example of this intersection is illustrated in Figure 20.4 below (using a radial pump curve). February 25, Version 1.1

126 Head, feet 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings System Static Head ,000 1,500 2,000 2,500 Flow, gpm Pump Operating Point Head System Loss Figure Dynamic Pump Operating Point Example The software uses the site/system information provided by the user (max system flow, max and static head) to generate the estimated system loss curve. The intersection is then located and the pump efficiency is estimated using the generic pump performance curves discussed earlier. Once the pump efficiency (for either On/Off or Throttling control types) is determined it is then possible to estimate the electric motor loading and efficiency using existing Statewide Customized Offering software functions (based on DOE MotorMaster). The resulting pump and electric motor efficiencies are then used in conjunction with Equation 20.B to estimate the pump kw for the specified operating mode. Baseline energy use for the operating mode is the product of the pump kw and the total annual operating hours that have been entered for the operating mode. The estimation software repeats the process of locating the pump operating point, estimating pump and motor efficiency and calculating the baseline energy usage for each of the operating modes (up to eight) specified by the user. Note that in the event that the software is unable to locate the estimated pump operating point (intersection of pump and system operating curves) or the estimated operating point is deemed invalid (flow is negative or exceeds system maximum flow) it will cause the calculation to be aborted and an error window will appear. The window will indicate that the specified pump appears incompatible with system requirements. This condition must be corrected (i.e. different pump or system specifications, etc.) before the calculations can be completed Efficiency Measure Pump Replacement The estimation software calculates the savings associated with replacement of an existing pump with a pump having a higher efficiency. The energy use of the new pump is calculated in the same manner as previously described for baseline energy use. The exception being that the new pump efficiency information is either directly substituted for the existing pump efficiency in equation 20.A (positive displacement pumps) or is used to generate a pump performance curve (dynamic pumps), which in turn allows a pump operating point and efficiency value to be estimated for the new pump. February 25, Version 1.1

127 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Efficiency Measure Drive Motor Replacement The estimation software calculates the savings associated with replacement of an existing pump drive motor with a motor having a higher efficiency. The energy use of the new motor is calculated in the same manner as previously described for baseline energy use. The exception being that the new motor efficiency is substituted for the existing motor efficiency in either equation 20.A (positive displacement pumps) or equation 20.B (dynamic pumps) depending on the pump type Efficiency Measure Variable Speed Drive (VSD) Installation Variable speed drives can achieve significant energy savings in pumping applications. Savings vary significantly depending on pump type and the estimation software therefore calculates the estimated savings associated with VSD operation differently depending on pump type. VSD Measure -- Positive Displacement Pumps The electric demand of positive displacement pumps when operating under VSD control is calculated using the following expression. kw PUMP= Q * P * D (Equation 20.D) 1714* * * P e VSD where: Q = fluid flow operating mode P D = Pump discharge pressure (psig) η p = Pump efficiency η e = Drive motor efficiency η VSD = VSD efficiency The baseline energy calculation for positive displacement pumps assumed constant pump flow regardless of the operating mode. Under VSD control, pump flow will match system flow and the flow value in the above expression is therefore equal to the operating mode flow specified by the user. Pump discharge pressure and pump efficiency are both assumed to be constant and equal to the pump design values (consistent with baseline calculation). The estimation software uses existing Statewide Customized Offering software functions (based on DOE MotorMaster) to estimate the electric motor efficiency (based on motor load). For positive displacement pumps the VSD speed (fraction of full speed) can be estimated as the ratio of the operating mode flow divided by the pump s rated flow capacity. The software uses this value along with the full load VSD efficiency (user input) to estimate VSD efficiency. The relationship between VSD speed and efficiency utilized by the software is illustrated in Figure Note that the software checks the estimated VSD operating speed against the minimum speed entered by the user on input sheet 6. If the estimated operating speed is less than the stated minimum the calculation will be aborted and an error window will appear indicating that Operating Mode X requires VSD operation below its minimum allowable range. The software will abort the calculations and return to the previous screen. The savings calculation cannot therefore be completed if one of the operation modes violates the minimum speed limit for the VSD. February 25, Version 1.1

128 % of Full Load Efficiency 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 0% 20% 40% 60% 80% 100% % of Full Speed Figure Generic Variable Speed Drive Performance (derived from EPRI TR Adjustable Speed Drives Application Guide) Once the VSD efficiency has been calculated it is then possible to calculate the electric demand of the VSD equipped pump using Equation 20.D. The difference between the previously calculated baseline electric demand and the proposed demand represents the average demand savings for this operating mode. The energy savings are calculated as the product of the average demand savings and the operating hours for the operating mode. The software repeats this process for each of the operating modes specified by the user. VSD Measure Dynamic Pumps The electric demand of a dynamic pump when operating under VSD control is calculated using the same basic expression as the baseline dynamic pump calculation with the exception that a VSD efficiency term is included. kw PUMP= S * Q * H * (Equation 20.E) 5310 * * * P where: S = specific gravity of pumped fluid relative to water at 60F Q = fluid flow (gpm) H = Total developed head (Ft) at this operating mode point η p = Pump efficiency η e = Drive motor efficiency η VSD = VSD efficiency e VSD However since dynamic pump performance varies with pump speed it not possible to assume constant pump efficiency or constant pump discharge pressure. Furthermore, it is not possible to calculate these performance parameters until the operating speed of the pump is calculated. February 25, Version 1.1

129 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Estimating VSD Operating Speed -- Dynamic Pumps The pump affinity laws state that with a constant impeller diameter and varying pump speed the following ratios are maintained without any change to pump efficiency. Q Q 1 2 n n 1 2 (Equation 20.F) H H 1 2 n n Q Q (Equation 20.G) where: Q = Pump fluid flow (gpm) H = Pump total developed head (Ft) n = Pump speed (RPM) In our case we set H 2 and Q 2 equal to the system loss (H OPMode ) and system flow at the specified operating point (Q OPMode ), respectively while H 1 and Q 1 represent the head and flow of the existing pump when operating at the same efficiency. Substituting and solving for H 1 yields: Q 2 1 H 1 H OPMode* (Equation 20.H) QOPMode To calculate the intermediate flow term (Q 1 ) we equate the above expression to the expression representing the existing pump head curve (polynomial expression based on generic curve shape) and solve for the pump flow (Q 1 ). Having solved for Q 1 the affinity laws are used to estimate the VSD operating speed (n VSD ): QOPMode nvsd nmotor * (Equation 20.I) Q 1 Pump efficiency at this operating point is calculated using the existing pump efficiency curve (generic curve, as before) at the intermediate flow, Q 1. The remaining terms, VSD and electric motor efficiency are calculated in the same manner as previously described for the positive displacement pump case. Once these terms have been calculated it is then possible to calculate the electric demand of the VSD equipped pump using Equation 20.E. The difference between the previously calculated baseline electric demand and the proposed electric demand represents the average demand savings for this operating mode. The energy savings are calculated as the product of the average demand savings and the operating hours for the operating mode. The software repeats this process for each of the operating modes specified by the user. Note that the software checks the estimated VSD operating speed against the minimum speed entered by the user on input sheet 6. If the estimated operating speed is less than the stated minimum the calculation will be aborted and an error window will appear indicating that Operating Mode X requires VSD operation below its minimum allowable range. The software will abort the calculations and return to the previous screen. The savings calculation cannot therefore be completed if one of the operation modes violates the minimum speed limit for the VSD. February 25, Version 1.1

130 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Refrigerated Wine Tank Insulation This tool estimates tank insulation savings. Use of this model is geared towards, but not limited to, winery storage tanks. The assumed tank geometry is a vertical cylinder. Use of this tool for other tank insulation projects will be reviewed by the program administrators. General Information: Number of Tank Types - Enter the number of tank types. Each type will define tank dimensions, location, existing and proposed insulation specifications, refrigeration system specifications, temperature settings and usage profiles. Tank Description Describe the type of tank to be retrofit with new or improved insulation. To edit the tank characteristics, highlight the line item of interest and select Edit Tank Details. Tank Characteristics: Number of Tanks - Enter the number of tanks. All tanks must have the same dimensions, location, existing and proposed insulation specifications, refrigeration system specifications, temperature settings and usage profiles. Tank Material - Select tank material. The default is Stainless Steel 304. Tank Thickness - Specify tank thickness. The default is 12-gauge, or inches. Tank Color Select the shade that best describes the tank color: light, medium or dark. Tank Dimensions (ft) - Enter tank dimensions: height, diameter and exterior cooling jacket width. City - Select a city. Location Selection the tank location: outside, inside (unconditioned space) or inside (conditioned space). If the tanks are located in a conditioned space the user needs to input the monthly temperature set points. Refrigeration System Efficiency - Enter the rated efficiency of the refrigeration system in terms of kw/ton. The rated efficiency should be based on design conditions at entering ambient air temperatures of 95 F dry-bulb for air-cooled condensers and 75 F wet-bulb for evaporative-cooled condensers, and 85 F entering water temperature for water-cooled condensers. Condenser Type Selection the refrigeration system condenser type: air-cooled, watercooled, or evaporative-cooled. Controls Select the refrigeration controls: fixed or floating head. Insulation Specifications - Enter insulation parameters of thermal resistance (h ft2 F/Btu in) and thickness (in), existing (if applicable) and proposed. Operating Characteristics: Conditioned Space Temperature ( F) If the tanks are located in a conditioned space, the user needs to estimate and input the average monthly space temperatures; otherwise, the model uses typical weather data. Glycol/Water Temperature ( F) - Enter the monthly refrigerant temperature ( F) set point. This is the temperature set point of the refrigeration system. The default value is 33 F. If the user assumes a set point temperature below the default value for more than February 25, Version 1.1

131 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings one month, allowing for one month of cold stabilization, supporting documentation will be required. Tank Temperature ( F) - Enter the average monthly tank temperature ( F) set point. The default value is 50 F. If the user assumes a set point temperature below the default value for more than one month, allowing for one month of cold stabilization, supporting documentation will be required. Days per Month - Enter days of operation per month. The default value is 24 days per month, which is based on a tank utilization rate of 80%. If the user assumes greater tank utilization per month, supporting documentation will be required. February 25, Version 1.1

132 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Tape Drip Irrigation The tape drip irrigation measure saves energy by increasing irrigation efficiency and reducing pressure head. Tape drip refers to thin walled hoses ranging from 4 to 20 millimeters. Other types of drip irrigation are eligible as Itemized (Express Efficiency) Measures. The methodology for estimating energy savings form crop irrigation focuses on changes to irrigation and pumping efficiencies, and irrigation requirements. The amount of irrigation required depends on local weather conditions, crop type and soil type. For analysis purposes, it is assumed that there is a single pumping plant supplying water to a site irrigation system. This provides a simple conceptual basis for calculating energy savings. The input variables and equations are relatively straight forward, except for the determination of the required irrigation, which is a function of crop evapotranspiration (ET c ) and effective precipitation (PPT eff ). This model is based on monthly averages of evapotranspiration and precipitation, with a simplified determination of effective precipitation. Site specific information: Manufacturer - Enter tape drip manufacturer. Name - Enter tape drip name. Model - Enter tape drip model number. ET o Zone - Select an appropriate evapotranspiration zone. There are 18 evapotranspiration zones in California. See the evapotranspiration reference map developed by the California Department of Water Resource ( Average Pumping Depth (ft) - Enter the average pumping depth for the site. Pumping depth is the sum of the well water depth and well drawdown. Average Pumping Lift (ft) - Enter the average elevation the water needs to be lifted prior to irrigation. Average Water Main Length (ft) - Enter the average distance of the water main. This is the distance from the pump to the submain. Average Well Flow (gpm) - Enter average well pump flow rate. Average Water Main Diameter (inches) - Enter the average diameter of main water line. Sprinkler Pressure Head (psi) - Enter the sprinkler pressure head. This should be consistent with equipment specifications and operating conditions. Crop specific information: Crop Type - Select crop type: row crop, or tree and vine. Crop Name - Select crop name. Crop Area (acres/crop) - Enter the crop area. Crop Planting Dates (month/day) - Enter the date planting begins for row crop, or date leaf out begins for tree and vine. Crop Harvest Dates (month/day) - Enter the date harvest begins. Soil Type - Select the soil type for each crop. There are four types of soil to select from: coarse sand, fine sand, loam and heavy clay. February 25, Version 1.1

133 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Crop Irrigation Method for Each Phase - Enter the irrigation method during each phase of growth. For row crops, there are four phases of growth (A-B = initial, B-C = rapid, C-D = mid-season, and D-E = late-season ). For tree and vine crops, there are three phase of growth (B-C = rapid, C-D = mid-season, and D-E = late-season ). February 25, Version 1.1

134 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Variable-Speed Drives for Cooling Tower Fan Motors This tool is utilized to estimate savings achieved from the installation of variable speed drives on cooling tower fan motors. The 2010 Statewide Customized Offering software calculates savings using the Engage Software for a measure of this type. The Engage software is a stand-alone, DOE2 based modeling program. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. For cooling and heating units not covered by this estimating tool, you will have to use the Engineering Calculations approach to determine the energy savings. This tool has four input screens. The following inputs should be noted: Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone or select the weather zone directly from the pull down menu. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions). If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. Vintage Select the vintage of the building. Building Area Enter the total building area. HVAC System Type Select a predefined HVAC system type from the drop down list. Choices change depending on building type selected. Building Seasons Sheet 2 and Sheet 3 are used to input the operating schedule of the building. o o Sheet 2 The user has the ability to define up to three seasons. Sheet 3 The user may select the appropriate building shell and define the hourly schedule of each season. Cooling tower specification inputs (Sheet 4): Fan Motors - Enter motor count and motor horsepower for up to twenty (20) different motor horsepowers. Baseline Temperature Control- Select either Fixed or Reset and enter the set points for the control type. o o Fixed The condenser entering (i.e., tower leaving) temperature is controlled to a fixed value, specified by the Setpoint input. Reset The condenser entering (i.e., tower leaving) temperature is allowed to float with the chiller heat rejection load and wet-bulb temperature. The minimum tower leaving temperature is specified by the Min Temperature input. Baseline Cooling Tower Fan Capacity Control - Select the existing capacity control cooling tower fans from the pull down menu. Proposed Temperature Control- Select either Fixed or Reset and enter the set points for the control type. o Fixed The condenser entering (i.e., tower leaving) temperature is controlled to a fixed value, specified by the Setpoint input. February 25, Version 1.1

135 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings o Reset The condenser entering (i.e., tower leaving) temperature is allowed to float with the chiller heat rejection load and wet-bulb temperature. The minimum tower leaving temperature is specified by the Min Temperature input. Proposed Cooling Tower Fan Capacity Control - Select the existing capacity control cooling tower fans from the pull down menu. Savings Estimate - The estimated savings are reported on the fifth screen of this tool. February 25, Version 1.1

136 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Variable-Speed Drives for Dairy Vacuum Pump This tool estimates the potential annual electrical energy savings and peak demand reduction that can be achieved by adding a variable-speed drive (VSD) to a standard dairy vacuum milking system. The program contains efficiency tables for standard- and premium-efficiency motors. Savings estimates are based on the following assumptions: The existing standard dairy milking vacuum pump system is significantly oversized and runs at a constant speed. Piping changes are made to move the vacuum system regulator (or controller), increase the vacuum system efficiency, and replace and downsize the main vacuum pump. The new, smaller vacuum pump motor is controlled by a VSD, which in turn receives feedback from the vacuum system through a pressure transducer. Any additional vacuum pumps and motors are either removed from service or replaced with premiumefficiency models. All motors are three phase, 1800 RPM, and operating at 90% load Energy Calculations This tool estimates existing energy usage using the nameplate horsepower of the vacuum pump motors and the average number of hours the system operates every day. The annual energy usage is determined as follows: Energy Usage (kwh) = Demand x Average Daily Operating Hours x 365 days/year When a VSD is installed to control a motor, the total energy savings depends on how the load changes over time and the amount of time spent at each load level. Testing at several dairies retrofitted with a VSD to control a downsized vacuum pump motor recorded savings close to half of the expected energy usage for the new system. This estimating tool uses a VSD motor speed and operating time distribution that yields an average annual energy savings of 46.3%. However, the peak demand for the combination of the new motor and a VSD is assumed to be 5% greater than for the new motor alone, due to the energy draw of the VSD controller itself Demand Calculations The software estimates the existing electrical demand and energy usage using the nameplate horsepower of the vacuum pump motors and the average number of hours the system operates every day. Survey data indicate that most dairy vacuum pump motors run close to 90% load. Thus, the electrical demand of each vacuum pump motor is calculated as follows: Demand (kw) = [Motor Horsepower (HP) x x 90%] / Motor Efficiency (%) where is the factor used to convert HP to kw, and Motor Efficiency is a value dependent on motor type and load EPAct Savings The estimated savings calculated by the program exceed the requirements of the national Energy Policy Act (EPAct) of 1992, and are therefore reportable. The software incorporates EPAct motor efficiency requirements to determine the amount of motor replacement energy savings that exceed the 1992 EPAct requirements and qualify for energy efficiency incentives. February 25, Version 1.1

137 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Variable-Speed Drives for HVAC Fans > 100 HP This tool addresses variable-speed drives (VSDs) on HVAC supply-air fans greater than 100 horsepower. A number of assumptions (stipulations) were made in order to simplify the savings calculations for this common measure: The fan is assumed to be on continuously during the building s operating hours. The tool does not cover intermittent fan operation. Fan speed is assumed to follow the cooling load but is not allowed to drop below 25% of rated speed. During heating, the fan speed is assumed to always be 100%. No cooling or heating, and therefore no fan operation, is allowed during the unoccupied period. The 2009 software calculates savings using the DOE2 hourly energy simulation method. If you believe the simulation does not fairly represent the project s savings, use the engineering calculations approach to estimate the energy savings. Take special note of the following: Multiple Units - Multiple supply fans may be combined under a single measure if the value entered represents the sum of all supply-air fans with their associated new VSDs. Note that only one drive manufacturer may be entered per measure and the model of the drives (when multiple drives are involved) must be of similar type and applied to fan motors with identical motor efficiency. If capacity is combined, an explanation of fans and motors involved should be included with the backup materials. Building Type - Select a predefined building configuration from the list of prototypical buildings (see Appendix D for detailed descriptions) or define a new building type using the custom building type option. If one of the predefined building types is a fair representation of your project site, you can simply input the building location, square footage of conditioned space, and building operating hours. If you choose the custom building option the software will instruct you on how to initiate the Engage software. The Engage software is a stand-alone, DOE2 based modeling program. Note that the custom building option must be used if a VSD-modified supply-air fan is used to cool/heat only a portion of a building. Building Location - From the pull-down menu, select a city that best represents the building location; this will, in turn, automatically select a weather zone. (This program uses the California Energy Commission s CTZ weather data, which breaks up the state into 17 weather zones.) February 25, Version 1.1

138 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Variable-Speed Drives for Process Applications This tool covers the installation of variable-speed drives (VSDs) for process applications. It includes direct drives (mixers and agitators) and fans. The existing controls for fans can be inlet guide vanes, outlet dampers, or no controls. Data inputs for existing and proposed motors include: General data - such as the quantity, location (e.g., 2 nd floor) and function (e.g., drive for conveyor belt). Nameplate data - If the measure includes more than one motor, then all the motors must be of equal size and have equal nameplate ratings. Copies of manufacturer s specifications that support the proposed motor/drive nameplate values must be submitted to the Utility Administrator with the Project Application. Operational hours - i.e., the hours that each motor is actually running. If two or more motors being replaced have unequal hours of operation, then these should be treated separately. Existing motor power measurements - These are critical for establishing brake horsepower (BHP, motor load). The preferred method is to measure power in kw, using a true RMS power meter. Next best would be to measure voltage, current, and power factor with a true RMS meter. At a minimum, both the voltage and current must be measured. If the power factor is not measured, the software will estimate a power factor. Ensure that all voltages are measured line-to-line with measurements taken under normal full-load motor operating conditions. February 25, Version 1.1

139 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Other - Wastewater Retrocommissioning This tool estimates savings for four different energy efficiency measures common to wastewater treatment facilities. The measures are (1) aeration device replacement, (2) control improvements, (3) increased blower efficiency, and (4) increased pumping efficiency Aeration Device Replacement Activated sludge plants typically account for 45-60% of the energy consumed at a conventional municipal wastewater treatment facility. Aeration methods include waterfall aerators diffusedgas aerators, and mechanical aerator. For each method there are a number of different aeration devices. An aerator s performance is defined by the energy required to deliver dissolved oxygen (DO) and the effectiveness of treating the biological oxygen demand (BOD). Existing Aeration Device - Select existing aeration device. Proposed Aeration Device - Select proposed aeration device. Average Daily Flowrate (mgd) - Enter the average daily flowrate in units of millions of gallons per day. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment. Average Daily Biological Oxygen Demand of Influent (mg/l) - Enter the average BOD entering the aeration zone in units of milligram per liter. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment. Average Daily Biological Oxygen Demand of Effluent (mg/l) - Enter the average BOD leaving the aeration zone in units of milligram per liter. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment Aeration Controls This control measure saves energy by reducing overall aeration. The objective of automation is to more consistently control of the DO level regardless of fluctuations in the BOD load. For example, DO sensors can be used to adjust air flow, tank level or mechanical aerator speed. Small treatment systems with no control can be operating at dissolved oxygen rate of 4-5 mg/l. Ideal control levels are 1-2 mg/l. Aeration Device - Select aeration device. If this measure is being installed in conjunction with an Aeration Device Replacement, this should be the proposed aeration device. Average Daily Flowrate (mgd) - Enter the average daily flowrate in units of millions of gallons per day. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment. Existing Controls - Describe existing controls. Existing Average Daily Dissolved Oxygen Levels (mg/l) - Enter the average dissolved oxygen level prior to the installation of aeration control improvements. The estimate should be based on the last twelve months of operation. Include supporting data as an attachment. Proposed Controls - Describe proposed controls. Include equipment specifications. Proposed Average Daily Dissolved Oxygen Levels (mg/l) - Enter the average dissolved oxygen level after the installation of aeration control improvements. February 25, Version 1.1

140 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Blower Efficiency Improvements This measure can save energy by increasing blower efficiency. Efficiency can be improved by installing a more efficient motor and blower, impeller rightsizing, blower downsizing and improved air flow control. If the measure is motor replacement only, than the appropriate measure category is High-Efficiency Motor Replacement or Early Retirement. See Section Annual Hours (hr/yr) - Enter the estimated annual hours of operation. Mass Flowrate (lb/s) - Enter the average mass flowrate. If this measure is being installed in conjunction with an Aeration Device Replacement and/or Aeration Control, this should be the post-installation mass flowrate. Absolute Inlet Temperature ( R = F) - Enter the absolute inlet temperature. Blower Efficiency (%) - Enter the blower efficiency (pre- and post-installation). Motor efficiency (%) - Enter the rated motor efficiency (pre- and post-installation). Absolute Inlet Pressure (lb f /in 2 ) - Enter the absolute inlet pressure. Absolute Outlet Pressure (lb f /in 2 ) - Enter the absolute outlet pressure (pre- and postinstallation) Pumping Efficiency Improvements This measure can save energy by increasing pumping efficiency. Efficiency can be improved by installing a more efficient motor and pump, impeller rightsizing, pump downsizing and improved flow control. If the measure is motor replacement only, than the appropriate measure category is High-Efficiency Motor Replacement or Early Retirement. See Section Annual Hours (hr/yr) - Enter the estimated annual hours of operation. Average Flowrate (gpm) - Enter the average flowrate in units of gallons per minute. The estimate should be based on the last twelve months of operation. Include supporting documentation as an attachment. System Head (ft) - Enter the system head. Fluid Specific Gravity (dimensionless) - Enter the specific gravity. The specific gravity of a substance is a comparison of its density to that of water. The default value is 1.0. Pump Efficiency (%) - Enter the pumping efficiency (pre- and post-installation). Motor Efficiency (%) - Enter the rated motor efficiency (pre- and post-installation). February 25, Version 1.1

141 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 2.3 Customized Measures - Engineering Calculations If you cannot find an existing program savings calculation method that adequately represents your measure you can choose to submit your own savings estimate (Engineering Calculations). The purpose of this section is to provide basic guidelines in preparing your savings estimate that will help ensure a timely and successful review by the Utility Administrator. An engineering calculation worksheet is available (see Appendix E) to assist in the documentation process. Preparation Basics When preparing your application assume that the reviewer, while having a technical background, will not have direct knowledge of your specific project. Therefore, the description(s) that you provide should contain sufficient detail to clearly understand the processes involved, the proposed savings measure, and how the measure will achieve the stated savings. To facilitate the review process, please consider the following: Break up your calculations and associated descriptions into smaller steps, since this will make your thought process easier to follow, Fully describe how you obtained any data used in the calculations (i.e., equipment load, operating hours, etc.), Fully describe any simulations/software used, Attach (and be able to electronically submit) printouts/reports summarizing both the inputs and results of simulations or other software used in preparing the calculation(s), and Attach any manufacturer s data, production data and/or other documentation that supports the inputs and assumptions used in your calculations or descriptions. Note that spot measurements of load, whether in kw or amps, under realistic operating conditions are preferred over assumed loads and or use of manufacturer s design values. The process of preparing and documenting your savings estimate can be divided into four basic steps, which are described in detail in the following sections. Step 1. Process / Measure Description The importance of providing a detailed description of the process and associated energy saving measure cannot be overstated, since it provides the reviewer with the necessary background information to understand the calculations that follow. Your description should be divided into the following three sections: 1. Existing process/equipment (w/o measure), 2. Proposed new equipment retrofit or enhancement, and 3. Resultant equipment and/or process (post installation). In each section include sufficient information on the process and equipment involved making it clear to the reviewer how the proposed measure will be implemented and how it will achieve the stated savings. For instance, if energy savings will be achieved using an energy management system (EMS) that implements a new control strategy, then you provide a complete description of the EMS, the existing and proposed control strategies, and the controlled equipment. February 25, Version 1.1

142 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Step 2. Establish Baseline Annual Energy Use and Demand Statewide Customized Offering incentives are based on equipment/improvements that go beyond standard efficiency or baseline equipment. Standard efficiency refers to equipment that meets either State/Federal efficiency requirements or current industry practice. The baseline for any given project is the standard efficiency or Title 24 requirement for an individual measure. Baseline energy use is established using accepted standards for currently available equipment. For instance, the Energy Policy Act of 1992 established Federal guidelines for electric motor efficiency (See Appendix E for a list of equipment types and applicable standards, or contact your Utility Administrator). The simplified equation used for the baseline energy use calculation is shown below. Baseline Energy Use (kwh or Therms/year) = (Op Hours * Equipment Load(kW or Therms/hr)) base Note that it may be necessary to develop a table of equipment loads and the annual operating hours at each load to arrive at an annual energy use estimate (see Appendix E for engineering calculation worksheet). To obtain the baseline value, it may be necessary to adjust the energy use estimate for the existing equipment to account for standard equipment efficiency. For example, a customer that proposes to replace an existing 50-hp motor with a nominal full-load efficiency of 90.2% with a premium efficiency motor having an efficiency of 94.1% must establish the baseline energy using the accepted standard motor efficiency. In this case, the previously mentioned Energy Policy Act of 1992 guideline for a 50-hp motor is 93%. The baseline energy use of the existing motor must therefore be calculated based on the higher 93% efficiency value, which reduces the baseline (and associated savings) value. The baseline energy use and demand calculations are critical to the savings calculations, so it is important that your calculations and associated descriptions provide sufficient information on the process, equipment and applicable standards to justify the proposed baseline energy use and demand. Step 3. Establish Post-Installation Annual Energy Use and Demand The simplified equation used for the post-installation energy use calculation is essentially the same as for the baseline calculation. Post Install Energy Use (kwh or Therms/year) = (Op Hours * Equip Load (kw or Therms/hr) ) post Note that it may be necessary to develop a table of equipment loads and the annual operating hours at each load to arrive at an annual energy use estimate (see engineering calculation worksheet, Appendix E). While the baseline energy use calculation is based on standard efficiency equipment, the postinstallation calculation is based on the projected performance of the new equipment or process. Use of simulation software such as Engage, equest, or another DOE2 based software package is acceptable as long as the inputs and associated assumptions (if any) are clearly stated and can be verified. Use of a manufacturer-specific simulation product can be acceptable but will require additional information on the underlying principles used by the software. Again, it is important that your description provide sufficient detail so that the reviewer will understand the basis for your projection. It is important to note that the reviewer has the option of substituting an alternative method of estimating the post-installation energy use and/or may require monitoring to confirm the estimate. Step 4. Calculate Energy Saving, Demand Savings, and Incentive Amount Once the baseline and post-installation annual energy use and demand estimates are completed then the savings estimate is simply the difference between the annual baseline and post installation use and demand estimates. February 25, Version 1.1

143 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings Savings (kwh/year) = Baseline Energy Use - Post-Installation Energy Use The peak demand savings (kw) are based on the DEER Peak Definition (see section 1.4.8). The total incentive amount is then calculated by multiplying the savings estimate by the appropriate program incentive multiplier (see Section 1, Table 1-3). Incentive ($) = program Incentive Multiplier ($/(kwh or Therms)) * Savings (kwh or Therms/year) Note that the calculated incentive is limited to 50% of the installed measure cost see Section February 25, Version 1.1

144 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings 2.4 Measurement & Verification (M&V) Process The M&V process begins after the Utility Administrator reviews the submitted application and has determined at its sole discretion that an M&V process is appropriate for the proposed project. The M&V process proceeds as follows: 1. M&V Requirement Notification. The Utility Administrator contacts the Project Sponsor and notifies them of the M&V requirement. The Utility Administrator sends the Project Sponsor the Measurement & Verification Guidelines. 2. M&V Plan Development. The Project Sponsor develops an M&V plan based on the M&V Guidelines. The Project Sponsor submits the M&V plan, and any required baseline data to the Utility Administrator. 3. Application and M&V Plan Approval. If the application and the M&V plan are approved, incentive funding for the project is reserved and the Project Sponsor and Utility Administrator initiate the application approval review. 4. Project Installation. For SDG&E and SCE service territories, the Project Sponsor submits a signed Installation Report and invoices after all project measure(s) have been installed and are fully commissioned and fully operational. For PG&E service territory, the Project Sponsor notifies the Utility Administrator in writing and submits invoices after all project measure(s) have been installed and are fully commissioned and fully operational. 5. Installation Review. Upon receipt of Installation Report (SCE and SDG&E), or Installation notification (PG&E), the Reviewer will evaluate the submittal package and conduct a postinstallation inspection to verify project installation and ensure the scope of work has not altered from the agreed-upon project. 6. First Payment. For SDG&E service territory, the designated Payee receives 60 percent of the Installation Report approved incentive along with an M&V adder, upon approval of the Installation Report. For SCE and PG&E service territories, the designated payee receives the 10% M&V adder, to defray the M&V cost, upon approval of the Installation Review. The M&V adder is10% of the IR approved incentive amount, not to exceed $50, Project Performance Period. The Applicant performs the agreed-upon M&V activities on the new operating equipment for a period up to two years (at discretion of Utility Administrator). At the end of the project performance period, the Project Sponsor submits the Operating Report. 8. Operating Report. The Applicant submits the Operating Report and operating data to the Utility Administrator. Upon receipt, the Utility Administrator reviews the report and data. 9. Final Payment. For SDG&E service territory, the designated Payee receives the remaining balance of the incentive based on the measured savings upon approval of the Operating Report. For SCE and PG&E service territories, 100% of the incentive is paid at the end of the project performance period when the Operating Report is approved. February 25, Version 1.1

145 2010 Statewide Customized Offering Procedures Manual for Business Section 2: Estimating Energy Savings The energy savings incentive is based on actual performance as indicated by the M&V results. February 25, Version 1.1

146 Section 3: (SCE-Only) Technical Assistance and Demand Response (DR) Technology Incentives 3.1 Eligibility Technical Assistance and DR Technology Incentives Technical Assistance (TA) DR Technology Incentive (TI) DR Technology Incentive Payment... 2 February 25, Version 1.1

147 3.1 Eligibility The Technical Assistance and Demand Response (DR) Technology Incentives program is open to all SCE business customers in SCE s service territory with registered demands of 200 kw or more. This registered demand of 200 kw can be one service account or be made up of multiple service accounts (see meter requirements below). The aggregated load of the participating service accounts from one SCE customer account must be 200 kw or more. Aggregated Technical Assistance and DR Technology Incentive service accounts must all be from one SCE customer (not multiple SCE customers). Each service account participating in Technical Assistance and DR Technology Incentive in any way (e.g., Technical Assistance Preliminary Assessment, Technical Audit, Technology Incentives) must have an interval meter. 3.2 Technical Assistance and DR Technology Incentives SCE s Technical Assistance and DR Technology Incentives Program enables you to participate in Demand Response programs by providing these offerings Technical Assistance (TA) Qualified applicants can receive free demand response audits of their facilities. To request a free audit or find out more about the program, contact your SCE Account Representative or visit DR Technology Incentive (TI) Customers can receive reimbursements of up to $125 per kw of verified load reduction for the purchase and installation of technologies that reduce electricity use during peak periods. Customers can be eligible for up to $300 per kw of verified load reduction1 for the purchase and installation of technologies that automatically reduce electricity use during peak periods without manual intervention (Automated Demand Response, or Auto-DR ). Incentives are not granted for manual improvements to existing equipment, customer behavior changes, or metering equipment. Customers will be required to make a minimum one-year commitment to a qualifying Demand Response program. To be eligible for a technology incentive from the TA&TI program, your facility (i) must be receiving bundled or direct access electric service from SCE, (ii) must have an interval electric meter, (iii) must be billed on an SCE commercial, industrial, or agricultural electric rate schedule, and (iv) must have purchased and installed a qualifying demand response solution within the previous 18 months from the date the customer submits its application for a TA&TI technology incentive. Auto-DR technology incentives require a minimum one-year commitment to an Auto- DR supported Demand Response program. February 25, Version 1.1

148 3.3 DR Technology Incentive Payment To qualify for DR Technology Incentive funding, a verification/demonstration of the load shed capability and functionality of the equipment must be performed. This verification is performed by an independent third party, Program Verification Engineer (PVE), not affiliated with the assigned engineer or the controls contractor (For complete terms and conditions, go to The demonstration is simple and consists of three steps: 1. Identify demand enabling equipment/device for which the customer is requesting TI funds. 2. Demonstrate enabling demand response by activating this equipment and holding the targeted load shed for two hours 3. Return to normal facility operations The quantification of the approved kw will be performed by the PVE using interval meter data for the facility and comparing this with an established baseline. Details of these calculations can be provided upon request. Once the kw is validated and approved, the incentive is processed. Additionally With any TA&TI application you will be required to provide proof of purchase and installation (including, if applicable, proof of payment of third-party installation), of the qualifying demand response solution within the previous 18 months from the date you submit your application by attaching receipts, cancelled checks, credit card statements and other documentary proof to the application. If applicable, for proof of payment of third-party installation, SCE requires an itemized invoice from the third-party installation contractor that clearly breaks down each item of labor and material (if any) that was invoiced by the third-party contractor for the installation of the qualifying demand response solution, and proof of payment of the invoiced costs. The TA&TI program will reimburse reasonable in-house labor costs and related expenses associated with the installation of the qualifying solution(s). Reimbursable in-house costs shall be limited to labor and other expenses directly incurred for design, engineering, and installation activities, and shall not include indirect labor or overhead costs. SCE reserves the right to consult with one or more qualified third parties of its own choosing to determine the reasonableness of your in-house labor-related expenses. Note: To be eligible for an incentive, a customer must own the qualifying demand response solution outright. Lease or financing arrangements do not qualify under the program. SCE may request proof of progress towards completing a project for which a reservation was approved at any time during the reservation period. Failure to demonstrate adequate performance towards completion of a project for which a reservation was approved may result in forfeiture of the reservation. SCE also reserves the right to modify or reject any reservation request that, in SCE s sole judgment, contravenes the requirements of the TA&TI program. I understand and acknowledge that this reservation does not guarantee future payment under the TA&TI program. While a reservation reserves funds for a project, payment of incentive is not guaranteed and is subject to post-installation performance verification. February 25, Version 1.1

149 Appendix A Sample Statewide Customized Offering Agreement These are sample 2010 Statewide Customized Offering Agreements. It is subject to change, therefore be sure to review the actual agreement you receive before signing.

150 PG&E Statewide Customized Retrofit and Demand Response Agreement Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

151 2010 CUSTOMIZED RETROFIT AND DEMAND RESPONSE AGREEMENT This Agreement is entered into by [Pacific Gas and Electric Company] ( UTILITY ) and the Project Sponsor (third party entity or UTILITY Customer if self sponsored), as indicated. Project Sponsor agrees to review these terms and conditions. Any implementation of this project will be deemed the Project Sponsor s acceptance of these terms and conditions. If these terms and conditions are not acceptable, the Project Sponsor must notify UTILITY and refrain from any implementation of the project, otherwise will do so at their own risk. Application Information Project Name: App. Number: Date Received: Demand Response Calculated Approach M&V Required Utility Customer Information COMPANY NAME CORP. PARENT NAME (if applicable) ADDRESS CITY/STATE ZIP CODE CONTACT NAME ADDRESS ( ) ( ) TITLE TELEPHONE NO. FAX NO. TAX STATUS: Corp. Non-Corp. Exempt Exempt Reason: COMPANY/CORP. FEDERAL TAX ID Project Sponsor Information COMPANY NAME CORP. PARENT NAME (if applicable) ADDRESS CITY/STATE ZIP CODE CONTACT NAME ADDRESS ( ) ( ) TITLE TELEPHONE NO. FAX NO. TAX STATUS: Corp. Non-Corp. Exempt Exempt Reason: COMPANY/CORP. FEDERAL TAX ID Site Information SITE NAME SITE I.D. # (if applicable) SITE ADDRESS CITY/STATE ZIP CODE SITE CONTACT NAME CONTACT PHONE # ELECTRIC SERVICE AGREEMENT(S) # GAS SERVICE AGREEMENT(S) # Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

152 Approved Customized Retrofit Estimate MEASURE DESCRIPTION kwh Permanent kw therms $ Amount Sub-Total Measure Cost Adjustment Site Cap Adjustment Total Incentive 10% Measurement and Verification Adder Approved Demand Response Dispatch-able Peak Demand Reduction Estimate MEASURE DESCRIPTION Dispatch-able Peak kw $ Amount Total Incentive 10% Measurement and Verification Adder 1.0 PROJECT DESCRIPTION This Agreement is limited to the Customized Retrofit and Demand Response Project(s) ( Project(s) ) described on the Customized Retrofit and Demand Response Incentive Application and Form (both together referred as Application ) incorporated by reference into this Agreement. As stated in the Application, UTILITY shall pay incentives in accordance with the terms and conditions of this Agreement. 1.1 DOCUMENTS INCORPORATED BY REFERENCE The following documents are incorporated by reference and are made part of this Agreement: Project Sponsor s approved Application, UTILITY acceptance letter(s) based on measures proposed in the Application, and the 2010 Statewide Customized Offering Procedures Manual for Business ( Program Manual ). 2.0 ELIGIBILITY Customized Retrofit and Demand Response funding is limited and is available on a first come, first served basis. Funds will be reserved only upon UTILITY approval of the Application. The Customized Retrofit and Demand Response Program offers two types of incentives, Customized Retrofit and Demand Response. A Project may be eligible for one or both of these incentives. Customized Retrofit Projects must meet the following requirements to be eligible for incentives: (1) Project must be nonresidential and be located within UTILITY s service territory. (2) UTILITY Customers must pay the Public Purpose Programs ( PPP ) surcharge on their UTILITY bills. (3) Projects will be evaluated using either the Customized Savings Approach or the Measured Savings Approach. (4) Projects must exceed the Title 24 energy efficiency requirements set by the California Energy Commission ( CEC applicable at the time this Agreement is signed, or current industry standards using UTILITY-approved project baselines if Title 24 standards are not available. (5) Projects must meet all other Customized Retrofit and Demand Response requirements. (6) The Project Sponsor certifies that the energy savings and permanent peak reduction components of this Project have not and will not receive funds from any other energy conservation program funded by the PPP fund, the CEC or the California Public Utilities Commission ( CPUC ). Demand Response Projects must meet the following requirements to be eligible for incentives: (1) Project must be commercial, industrial, or agricultural and be located within UTILITY s service territory. (2) Customer must receive retail electric service from UTILITY. (3) Customer must have an existing electric meter that is capable of recording usage in 15-minute intervals and that Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

153 can be read remotely by UTILITY. (4) Project site s associated service agreement must have a maximum demand greater than or equal to 200 kw within the last 12 billing months, or the facility must be able to demonstrate a load reduction greater than or equal to 30 kw. (5) Projects will be evaluated using either the Calculated Savings Approach or the Measured Savings Approach (for measures requiring Measurement and Verification (M&V)). (6) Projects must meet all other Customized Retrofit and Demand Response Program requirements. (7) Project Sponsor certifies that the dispatch-able peak reduction components of the Project have not and will not receive funds from any energy conservation program funded by the PPP fund, the CEC or the CPUC. 3.0 SUBMITTAL REQUIREMENTS FOR PAYMENT As a condition of payment, Project Sponsor shall submit to UTILITY the documents described below. Required documents include but are not limited to: 1) Completed, signed Application; 2) Complete engineering calculations and documentation to demonstrate energy savings, permanent peak demand reduction, and dispatch-able peak demand reduction (including archival diskette if applicable); 3) Schematic drawings and/or manufacturer specification sheets if applicable; 4) Invoices and/or documentation to support Project cost at UTILITY S request; 5) Additional Project-specific documents as requested by UTILITY prior to payment of incentives; and 6) Operating Report if the Measured Savings Approach is used. 4.0 INSPECTIONS As a condition of payment, Project Sponsor is responsible for ensuring that UTILITY has reasonable access for all inspections, including but not limited to those as described below: 1) Customized Retrofit and Demand Response Pre-Installation Equipment Inspection to examine the existing/baseline equipment and to check the accuracy of Project Sponsor s equipment survey; 2) Customized Retrofit Post-Installation Equipment Inspection to check installed equipment and to verify accuracy of Project Sponsor s equipment survey; 3) DR Post-Installation dispatch-able load reduction demonstration(s), 4) Customized Retrofit and Demand Response Post-operation inspection to check the energy savings of the Measures after installed equipment has been operating. This inspection can take place after the Operating Report has been submitted or earlier, at UTILITY s discretion. 5.0 REVIEW AND DISCLAIMER UTILITY S AND/OR ITS CONSULTANTS REVIEW OF THE DESIGN, CONSTRUCTION, OPERATION OR MAINTENANCE OF THE PROJECT, ENERGY EFFICIENCY MEASURES, OR DEMAND RESPONSE MEASURES DO NOT CONSTITUTE ANY REPRESENTATION AS TO THE ECONOMIC OR TECHNICAL FEASIBILITY, OPERATIONAL CAPABILITY, OR RELIABILITY OF THE PROJECT MEASURES. PROJECT SPONSOR SHALL IN NO WAY REPRESENT TO ANY THIRD PARTY THAT UTILITY S REVIEW OF THE MEASURES OR PROJECT, INCLUDING, BUT NOT LIMITED TO, UTILITY S AND/OR ITS CONSULTANTS REVIEW OR ANALYSIS OF THE DESIGN, CONSTRUCTION, OPERATION OR MAINTENANCE OF THE MEASURES OR PROJECT, IS A REPRESENTATION BY UTILITY AS TO THE ECONOMIC OR TECHNICAL FEASIBILITY, OPERATIONAL CAPABILITY, AND RELIABILITY OF SUCH MEASURES OR PROJECT. PROJECT SPONSOR IS SOLELY RESPONSIBLE FOR THE ECONOMIC AND TECHNICAL FEASIBILITY, OPERATIONAL CAPABILITY AND RELIABILITY OF PROJECT SPONSOR S PROJECT AND MEASURES. 6.0 PAYMENTS Incentive payments will only be paid after all Customized Retrofit and Demand Response requirements are met by Project Sponsor to UTILITY s satisfaction. UTILITY retains sole discretion to determine the appropriate baseline values, dispatch-able peak reduction and energy savings calculations used to determine incentive payments. Incentive payments shall only be paid on Customized Retrofits that exceed Title 24 standards applicable when this Agreement is signed or industry standards in the absence of Title 24 standards. DR Projects are not subject to a standard baseline. UTILITY reserves the right to modify or cancel the incentive amount if the actual system installed differs from the installation in Project Sponsor s approved Application(s). 6.1 CUSTOMIZED RETOFIT INCENTIVE PAYMENTS The total incentive payment under the Calculated Savings Approach or Measured Savings Approach shall not exceed the total incentive in the Final Approved Energy Savings Estimate (as presented on Page 2 of this Agreement). Projects with increased measure costs or installation of more efficient equipment are eligible for incentive payments above the total incentive, based on actual installed measure costs and energy savings from the actual installed equipment. Projects using the Measured Savings Approach are eligible for up to an additional 10% of the approved incentive amount in the event that actual energy savings are higher than projected. See Program Manual for details. The total incentive payment may be limited as described in the Program Manual. The calculations shall be in accordance with the Program Manual. The following Energy Savings incentive rates shall apply for the types of retrofit projects: Lighting, 5 cents/kwh; AC & Refrigeration I, 15 cents/kwh; AC & Refrigeration II, 9 cents/kwh; Other (motors, etc), 9 cents/kwh; and Natural Gas, 1.00 cents/therm. The following Demand Reduction rates shall apply for the types of retrofit projects: Lighting, $100/kW; AC & Refrigeration I, $100/kW; AC & Refrigeration II, $100/kW; and Other (motors, etc), $100/kW. UTILITY will make the applicable incentive payment to Customers, in one or more installments, only after the appropriate documents have been submitted and approved, and the appropriate inspections of the Project have been satisfactorily completed, in accordance with the rules set forth in the Program Manual. All Project(s) must be installed and fully operational by June 1, UTILITY reserves the right to cease making incentive payments, required the return of incentive payments and or/terminate this Agreement if the projects(s) is not installed and fully operational by June 1, Energy savings for which incentives are paid cannot exceed the actual usage provided by the UTILITY Non-utility supply, such as cogeneration or deliveries from another commodity supplier, does not qualify as usage from the UTILITY (with the exception of Direct Access customers or customers paying departing load fees for which the UTILITY collects PPP surcharges). 6.2 DR INCENTIVE PAYMENTS The total dispatch-able peak incentive payment under either the Calculated Savings or Measured Savings Approach shall not exceed the total incentive approved in the Approved Demand Response Dispatch-able Peak Demand Reduction Estimate (as presented in this Agreement), and is limited to $300,000 per customer. The total dispatch-able peak demand reduction (DR) incentive is limited to 50% of the incremental DR measure cost. The calculations Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

154 shall be in accordance with the Program Manual. The following dispatch-able peak reduction incentive rates shall apply for the DR program enrollment categories: Category 1, $125/kW; Category 2, $50/kW. Enrollment category 1 includes the following DR programs: AMP, BIP, CPP and PeakChoice with committed load reduction efforts option. Enrollment category 2 includes the following DR programs: DBP and PeakChoice Best Efforts Options. UTILITY will make the applicable incentive payment in one or more installments, only after the appropriate documents have been submitted and approved, and the appropriate inspections of the Project have been satisfactorily completed, in accordance with the rules set forth in the Program Manual. The first installment, 25% of the total DR incentive, will be paid upon successful post-field inspection, and completion and approval of the Post Installation Review. The last installment, and final 75% of the total DR incentive, will be paid after successful load reduction demonstration, completion of the DR Load Verification Review, and enrollment in a Demand Response Program for at least 3 years. Customer must enroll in a DR program upon receiving the first incentive payment installment. The customer is required to stay in a DR program for three years. Customer can move from one DR program to another, within an enrollment category, according to PG&E tariff. Customer can change from Category 2 to Category 1, but not from Category 1 to Category 2. If the customer cancels out of the DR program prior to three years, UTILITY is entitled to a 100% refund of the incentive. The equipment needs to be in place for a period of not less than five years. All 2010 Project(s) must be installed and fully operational by June 1, UTILITY reserves the right to cease making incentive payments, require the return of incentive payments and or/terminate this Agreement if the Project is not installed and fully operational by December 31, PAYMENT DISQUALIFICATION A prorated part of the incentives shall be repaid by Project Sponsor to UTILITY if: For Customized Retrofit, Customer fails to pay the PPP surcharge throughout the Term of this Agreement. For DR Projects, Customer ceases to receive retail electric service from UTILTY any time throughout the Term of this Agreement. For both Customized Retrofit and DR Projects, UTILITY did not receive the energy benefit for which the incentive is paid, for a period of not less than five years. 7.1 Project Sponsor agrees that if 1) Project Sponsor does not provide UTILITY with 100 percent of the related benefits specified in the Application, for a period of five years from the UTILITY approved installation date, or 2) the energy benefit to UTILITY ceases (for example, if UTILITY Customer stops using the equipment, no longer pays the PPP surcharge for energy efficiency projects, or discontinues retail electric service with UTILITY), Project Sponsor will return to UTILITY the prorated portion of the Incentive dollars based on the actual period of time for which UTILITY Customer provided the energy benefit. 7.2 Project Sponsor shall repay any payments made by UTILITY within 30 days of notification by UTILITY that repayment is required. UTILITY is entitled to offset against payments owed to Project Sponsor any amount due to UTILITY which remains unpaid 40 calendar days after UTILITY S written demand for payment. Project Sponsor may designate in writing a third party to whom UTILITY shall make incentive payments. 8.0 TERM AND TERMINATION The Term of this Agreement shall commence on the last date that a Party executes this Agreement and shall terminate no later than five years from the Project Installation Report approval date, unless terminated earlier pursuant to this Agreement. 9.0 ASSIGNMENT Project Sponsor consents to UTILITY s assignment of all of UTILITY s rights, duties and obligations under this Agreement to the CPUC and/or its designee. Such assignment shall relieve UTILITY of all rights, duties and obligations arising under this Agreement. Other than UTILITY s assignment to the CPUC or its designee, neither Party shall assign its rights or delegate its duties without the prior written consent of the other Party, except in connection with the sale or merger of a substantial portion of its properties. Any such assignment or delegation without written consent shall be null and void. Consent to assignment shall not be unreasonably withheld. If an assignment is requested, the Project Sponsor is obligated to provide additional information if requested by UTILITY PERMITS AND LICENSES Project Sponsor, at its own expense, shall obtain and maintain licenses and permits needed to perform its work. Failure to maintain necessary licenses and permits constitutes a material breach of Project Sponsor s obligations ADVERTISING, MARKETING AND USE OF UTILITY S NAME Project Sponsor shall not use UTILITY s corporate name, trademark, trade name, logo, identity or any affiliation for any reason, including to solicit customers to participate in the Project, without UTILITY s prior written consent. Project Sponsor shall make no representations to its customers on behalf of UTILITY. Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

155 12.0 INDEMNIFICATION Project Sponsor shall indemnify, defend and hold harmless, and releases UTILITY, its affiliates, subsidiaries, parent company, officers, directors, agents and employees, from and against all claims, demands, losses, damages, costs, expenses, and liability (legal, contractual, or otherwise), which arise from or are in any way connected with any: injury to or death of persons, including but not limited to employees of UTILITY or Project Sponsor; (ii) injury to property or other interests of UTILITY, Project Sponsor, or any third party; (iii) violation of local, state, or federal common law, statute, or regulation, including but not limited to environmental laws or regulations; or (iv) strict liability imposed by any law or regulation; so long as such injury, violation, or strict liability (as set forth in (i) - (iv) above) arises from or is in any way connected with Project Sponsor's performance of, or failure to perform, this Agreement, however caused, regardless of any strict liability or negligence of UTILITY whether active or passive, excepting only such loss, damage, cost, expense, liability, strict liability, or violation of law or regulation that is caused by the sole negligence or willful misconduct of UTILITY, its officers, managers or employees Project Sponsor acknowledges that any claims, demands, losses, damages, costs, expenses, and legal liability that arise out of, result from, or are in any way connected with the release or spill of any legally designated hazardous material or waste as a result of the work performed under this Agreement are expressly within the scope of this indemnity, and that the costs, expenses, and legal liability for environmental investigations, monitoring, containment, abatement, removal, repair, cleanup, restoration, remedial work, penalties, and fines arising from strict liability, or violation of any local, state, or federal law or regulation, attorney's fees, disbursements, and other response costs incurred as a result of such releases or spills are expressly within the scope of this indemnity Project Sponsor shall, on UTILITY s request, defend any action, claim or suit asserting a claim which might be covered by this indemnity. Project Sponsor shall pay all costs and expenses that may be incurred by UTILITY in enforcing this indemnity, including reasonable attorney's fees If this Agreement is assigned pursuant to Section 9.0, the Project Sponsor agrees that this indemnification shall continue to apply to UTILITY and shall apply to the assignee LIMITATION OF LIABILITY UTILITY shall not be liable for any incidental or consequential damages, including without limitation, loss of profits or commitments to Subcontractors, and any special, incidental, indirect or consequential damages incurred by Project Sponsor or its Customer CPUC AUTHORITY TO MODIFY This Agreement shall at all times be subject to such changes or modifications by the CPUC as it may from time to time direct in the exercise of its jurisdiction INTEGRATION This Agreement constitutes the entire agreement and understanding between the Parties as to the subject matter of the Agreement. It supersedes all prior or contemporaneous agreements, commitments, representations, writings, and discussions between Project Sponsor and UTILITY, whether oral or written, and has been induced by no representations, statements or agreements other than those expressed herein. Neither Project Sponsor nor UTILITY shall be bound by any prior or contemporaneous obligations, conditions, warranties or representations with respect to the subject matter of this Agreement. NO AMENDMENT, MODIFICATION OR CHANGE TO THIS AGREEMENT SHALL BE BINDING OR EFFECTIVE UNLESS EXPRESSLY SET FORTH IN WRITING AND SIGNED BY UTILITY S REPRESENTATIVE AUTHORIZED TO EXECUTE THE AGREEMENT WRITTEN NOTICE Any written notice, demand or request required or authorized in connection with this Agreement, shall be deemed properly given if delivered in person or sent by facsimile, , nationally recognized overnight courier, or first class mail, postage prepaid, to the address specified below, or to another address specified in writing by UTILITY. UTILITY UTILITY Project Manager: Address: City, State Zip: Fax # (facsimile): Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

156 PROJECT SPONSOR Name Company Address City, State, Zip Fax # (facsimile) Notices shall be deemed received (a) if personally or hand-delivered, upon the date of delivery to the address of the person to receive such notice if delivered before 5:00 p.m., or otherwise on the Business Day following personal delivery; (b) if mailed, three Business Days after the date the notice is postmarked; (c) if by facsimile, upon electronic confirmation of transmission, followed by telephone notification of transmission by the noticing Party; (d) if by ; or (e) if by overnight courier: on the Business Day following delivery to the overnight courier within the time limits set by that courier for next-day delivery CONFLICTS BETWEEN TERMS Should a conflict exist between the main body of this Agreement and the Documents Incorporated by reference, the main body of this Agreement shall control. Should a conflict exist in the Documents Incorporated by reference, the Documents shall control in the following order: 1) Program Manual; 2) UTILITY acceptance letter(s) and incentive estimate(s) based on Measures as approved in Application(s); and 3) Project Sponsor s approved Application(s). Should a conflict exist between an applicable federal, state, or local law, rule, regulation, order or code and this Agreement, the law, rule, regulation, order or code shall control. Varying degrees of stringency among the main body of this Agreement, the Documents Incorporated by reference, and laws, rules, regulations, orders, or codes are not deemed conflicts, and the most stringent requirement shall control. Each Party shall notify the other immediately upon the identification of any conflict or inconsistency concerning this Agreement CANCELLATION OF AGREEMENT UTILITY may suspend or terminate the Agreement, without cause, upon written notice to Customer/ Project Sponsor. This program is funded by California Utility Customers and administered by UTILTY under the auspices of the CPUC. Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

157 SCE Statewide Customized Offering Agreement Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

158 SDG&E Statewide Customized Offering Agreement Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

159 2010 Energy Efficiency Business Incentive Customized Offering Application Information Project Name: App. Number: Service Account/Agreement <500kW or <250,000 therms Service Account/Agreement >=500kW or >=250,000 therms Date Received: Calculated Approach M&V Required Utility Customer Information COMPANY NAME CORP. PARENT NAME (if applicable) ADDRESS CITY/STATE ZIP CODE CONTACT NAME ADDRESS ( ) ( ) TITLE TELEPHONE NO. FAX NO. TAX STATUS: Corp. Non-Corp. Exempt Exempt Reason: COMPANY/CORP. FEDERAL TAX ID Project Sponsor Information COMPANY NAME CORP. PARENT NAME (if applicable) ADDRESS CITY/STATE ZIP CODE CONTACT NAME ADDRESS ( ) ( ) TITLE TELEPHONE NO. FAX NO. TAX STATUS: Corp. Non-Corp. Exempt Exempt Reason: COMPANY/CORP. FEDERAL TAX ID Site Information SITE NAME SITE I.D. # (if applicable) SITE ADDRESS CITY/STATE ZIP CODE SITE CONTACT NAME CONTACT PHONE # ELECTRIC ACCOUNT(S) # GAS ACCOUNT(S) # Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

160 Final Approved Savings Amount MEASURE DESCRIPTION kwh kw therms $ Amount Sub-Total Adjustments Grand Total The 2010 Energy Efficiency Business Incentive ("Agreement") is entered into by San Diego Gas & Electric Company ( SDG&E ) and (the Project Sponsor ). SDG&E and Project Sponsor may be individually referred to as a Party and collectively as the Parties. 1.0 PROJECT DESCRIPTION This Agreement is limited to the 2010 Energy Efficiency Business Incentive Project(s) ( Project(s) ) described on the 2010 Energy Efficiency Business Incentive ( Program ) Application executed by Project Sponsor and all forms attached thereto ( Application ) and incorporated by reference into this Agreement. As stated in the Application, SDG&E shall pay Project Sponsor, or such other party properly authorized to receive payment, incentives in accordance with the terms and conditions of this Agreement. 2.0 DOCUMENTS INCORPORATED BY REFERENCE The following documents are hereby incorporated by reference and made part of this Agreement: the Application, SDG&E acceptance letter(s) of the energy saving measures proposed in the Application, and the 2010 Customized Statewide Procedures for Business Manual ( Program Manual ). 3.0 ELIGIBILITY Program funding is limited and is available on a first-come, first-served basis until program funds are no longer available, or December 31, 2010, whichever comes first. Funds will be reserved only upon SDG&E s approval of the Application. Projects must meet the following requirements to be eligible for payment of Program incentives ( Incentive(s) ): (1) Project Site must be a nonresidential facility located within SDG&E s service territory; (2) Customer must pay the Public Purpose Program ( PPP ) surcharge, Public Goods Charge ( PGC ) surcharge or the Gas Demand Side Management ( DSM ) surcharge, within SDG&E s service territory, on the gas or electric meter on which the energy efficiency measure listed in the Final Approved Savings Amount table above is installed throughout the Term of this Agreement; (3) Projects must be evaluated using the Calculated Approach and/or Measurement and Verification ( M&V ); (4) Projects must exceed the Title 24 energy efficiency requirements set by the California Energy Commission ("CEC") applicable at the time this Agreement is signed or current industry standards using SDG&E-approved project baselines if Title 24 standards are not available; (5) Projects must meet all other Program requirements, terms and conditions; and (6) Project Sponsor and Customer must not receive any funds from any other program (energy efficiency or otherwise) funded by the PPP surcharge, PGC surcharge or the DSM surcharge, the CEC or the California Public Utilities Commission ("CPUC") for the Project or any measure applied for herein. Project Sponsor represents and warrants that neither Project Sponsor nor Customer has received or will receive any funds from any other program funded by the PPP surcharge, PGC surcharge or the DSM surcharge, the CEC or the CPUC for the Project or any measure applied for herein. 4.0 SUBMITTAL REQUIREMENTS FOR PAYMENT Project Sponsor shall submit to SDG&E the documents described below prior to being eligible for payment of any Incentives. Required documents include the following: (1) completed and executed Application; (2) complete engineering calculations to demonstrate energy savings and documentation, if applicable (including archival diskette, if applicable); (3) schematic drawings and/or manufacturer specification sheets, if applicable; (4) invoices and/or documentation to support measure costs at SDG&E S request; (5) additional Project-specific documents as requested by SDG&E; (6) Project Installation Report; (7) Operating Report, if M&V is required; and (8) any other documents related to the Project, Project Site, measures, energy savings or otherwise requested by SDG&E, in its sole discretion. 5.0 INSPECTIONS Project Sponsor is solely responsible for ensuring that SDG&E has reasonable access for all inspections required under the Program, including, but not limited to, the following: (1) pre-installation equipment inspection to examine the existing/baseline equipment and to check the accuracy of Project Sponsor s equipment survey; (2) post-installation equipment inspection to check installed equipment and to verify accuracy of Project Sponsor s equipment survey; and (3) inspection for any other reason that SDG&E, in its sole discretion, deems necessary. 6.0 REVIEW AND DISCLAIMER SDG&E S AND/OR ITS CONSULTANTS REVIEW OF THE DESIGN, CONSTRUCTION, OPERATION OR MAINTENANCE OF THE PROJECT OR ENERGY EFFICIENCY MEASURES ("EEMs") SHALL NOT CONSTITUTE ANY REPRESENTATION AS TO THE ECONOMIC OR TECHNICAL FEASIBILITY, OPERATIONAL CAPABILITY, OR RELIABILITY OF THE PROJECT OR EEMs, NOR SHALL PROJECT SPONSOR, IN ANY WAY, MAKE SUCH A REPRESENTATION TO A THIRD PARTY. PROJECT SPONSOR IS SOLELY RESPONSIBLE FOR THE ECONOMIC AND TECHNICAL FEASIBILITY, CONSTRUCTION, OPERATIONAL CAPABILITY AND RELIABILITY OF PROJECT SPONSOR'S PROJECT AND EEMs. SDG&E MAKES NO WARRANTY, WHETHER STATUTORY, EXPRESS OR Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

161 IMPLIED, INCLUDING, WITHOUT LIMITATION, THE IMPLIED WARRANTIES OF MERCHANTABILITY AND FITNESS FOR ANY PARTICULAR PURPOSE, USE OR APPLICATION. 7.0 PAYMENTS Payments of Incentives will be made only after all Program requirements are met by Project Sponsor to SDG&E s sole satisfaction. Project Sponsor may authorize payment of the Incentives to Customer, and Customer may authorize payment of the Incentives to Project Sponsor. Such authorization is strictly between Customer and Project Sponsor and may be revoked or modified at any time by providing written notification to SDG&E specifying the change. Should a dispute arise regarding the authorization, the most recently dated written communication or authorization shall govern. 7.1 SDG&E retains sole discretion to determine the appropriate baseline values and energy savings calculations used to determine Incentive payments. Incentives shall only be paid on Projects that exceed Title 24 standards applicable when this Agreement is signed or industry standards in the absence of Title 24 standards. SDG&E reserves the right to modify or cancel the Incentive amount if the actual measure installed differs from the measure described in Project Sponsor s approved Application(s). 7.2 The total Incentive payment shall not exceed the total incentive amount listed in the Final Approved Savings Amount table in this Agreement. The total Incentive payment will be limited by a Customer Project Site Cap of approximately 15% of the average annual 2010 Energy Efficiency Business Incentive Budget as filed in the Application of San Diego Gas & Electric Company (U-902-M) for Approval of Electric and Natural Gas Energy Efficiency Programs and Budget for Year 2010, and/or the Project Cost Cap of 50% of the total measure costs for calculated measures, which are calculated on a per measure basis, whichever is less. The following incentive rates shall apply for the types of retrofit projects: Lighting, $0.05/kWh; Air Conditioning & Refrigeration, $0.15/kWh; Air Conditioning & Refrigeration II, $0.09/kWh; Natural Gas, 1.00/therm; and Other, $0.09/kWh. The following Peak Demand Reduction Incentive Rates shall apply for the type of retrofit projects: Lighting, $100/kW; Air Conditioning & Refrigeration, $100/kW; and Other, $100/kW. 7.3 The total Incentive payment is based on the calculated energy savings derived from the actual use of electricity and/or gas provided by SDG&E. Electricity and/or gas provided by any party other than SDG&E, including, but not limited to, cogeneration or deliveries from another commodity supplier, do not qualify (with the exception of Direct Access customers or customers paying departing load fees for which SDG&E collects the PPP surcharge, the PGC surcharge and/or the DSM surcharge). 7.4 SDG&E will make the applicable Incentive payment to the designated payee, in one (1) or more installments, only after all required and/or requested documents have been submitted to and approved by SDG&E and the appropriate inspection(s) of the Project or Project Site have been completed to SDG&E s satisfaction. 7.5 All Projects and/or measures must be installed and fully operational one year from approval date to be eligible for Incentive payments. SDG&E reserves the right to cease making Incentive payments, require the return of Incentive payments and/or terminate this Agreement if the Project(s) is not installed and fully operational one year from the approval date, unless an extension is granted by SDG&E, at its sole discretion. 8.0 PAYMENT DISQUALIFICATION Any Incentives received by Project Sponsor shall be repaid to SDG&E, in whole or in part, as follows: 8.1 If Customer fails to pay the PPP surcharge, the PGC surcharge or the DSM surcharge at any time during the Term of this Agreement, Project Sponsor shall refund to SDG&E any prorated amount of the Incentive dollars that SDG&E determines must be repaid, in its sole discretion, based on the energy savings that occurred during the payment of the PPP surcharge, the PGC surcharge or the DSM surcharge. 8.2 If (1) Project Sponsor does not provide SDG&E with 100% of the related benefits specified in the Application for a period of five (5) years from the Project Installation Report approval date, or (2) the energy benefit to SDG&E ceases in any way during the five (5) year period from the Project Installation Report approval date, including, but not limited to, Customer and/or the Project Site ceasing to receive electricity and/or gas service from SDG&E, the measure, equipment and/or Project ceasing to function, or Customer ceasing the use of the equipment, measure or Project Site, Project Sponsor shall refund to SDG&E any prorated amount of the Incentive dollars that SDG&E determines must be repaid, in its sole discretion, based on the actual period of time for which Customer provided the energy benefit. 8.3 Project Sponsor shall repay any amounts due to SDG&E within thirty (30) calendar days of notification bysdg&e that repayment is required in accordance with Sections 8.1 and 8.2 above. SDG&E shall be entitled to offset against payments owed to Project Sponsor any amount due to SDG&E that remains unpaid forty (40) calendar days after SDG&E S written demand for payment. 9.0 TERM AND TERMINATION The term of this Agreement shall commence on the last date that a Party executes this Agreement and shall terminate no later than five (5) years from the Project Installation Report approval date, unless terminated earlier pursuant to this Agreement ("Term") ASSIGNMENT Project Sponsor consents to SDG&E's assignment of all of SDG&E's rights, duties and obligations under this Agreement to the CPUC and/or its designee. Such assignment shall relieve SDG&E of all rights, duties and obligations arising under this Agreement. Other than SDG&E's assignment to the CPUC or its designee, neither Party shall assign its rights or delegate its duties without the prior written consent of the other Party, except in connection with the sale or merger of a substantial portion of its properties. Any such assignment or delegation without written consent shall be null and void. Consent to assignment shall not be unreasonably withheld. If an assignment is requested, Project Sponsor is obligated to provide additional information if requested by SDG&E. Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

162 11.0 PERMITS AND LICENSES Project Sponsor, at its own expense, shall obtain and maintain and cause its contractors and/or subcontractors to obtain and maintain licenses and permits required by federal, state, local, or other relevant governing or regulatory bodies to perform its work. Any failure by Project Sponsor or its contractors and/or subcontractors to maintain necessary licenses and permits constitutes a material breach of Project Sponsor s obligations under this Agreement ADVERTISING, MARKETING AND USE OF SDG&E S NAME Project Sponsor shall not use SDG&E s corporate name, trademark, trade name, logo, identity or any affiliation for any reason, including to solicit customers to participate in the Project, without SDG&E s prior written consent. Project Sponsor shall make no representations to its customers on behalf of SDG&E INDEMNIFICATION Project Sponsor shall indemnify, defend and hold harmless, and release SDG&E, its affiliates, subsidiaries, parent companies, officers, directors, agents and employees, from and against all claims, demands, losses, damages, costs, expenses, and liability (legal, contractual, or otherwise), which arise from or are in any way connected with any: (i) injury to or death of persons, including, but not limited to, employees of SDG&E or Project Sponsor; (ii) injury to property or other interests of SDG&E, Project Sponsor, or any third party; (iii) violation of local, state, or federal common law, statute, or regulation, including, but not limited to, environmental laws or regulations; or (iv) strict liability imposed by any law or regulation; so long as such injury, violation, or strict liability (as set forth in (i) - (iv) above) arises from or is in any way connected with Project Sponsor's performance of, or failure to perform, this Agreement, however caused, regardless of any strict liability or negligence of SDG&E whether active or passive, excepting only such loss, damage, cost, expense, liability, strict liability, or violation of law or regulation that is caused by the sole negligence or willful misconduct of SDG&E, its officers, managers or employees Project Sponsor acknowledges that any claims, demands, losses, damages, costs, expenses, and legal liability that arise out of, result from, or are in any way connected with the release or spill of any legally designated hazardous material or waste as a result of the work performed under this Agreement are expressly within the scope of this indemnity, and that the costs, expenses, and legal liability for environmental investigations, monitoring, containment, abatement, removal, repair, cleanup, restoration, remedial work, penalties, and fines arising from strict liability, or violation of any local, state, or federal law or regulation, attorney's fees, disbursements, and other response costs incurred as a result of such releases or spills are expressly within the scope of this indemnity Project Sponsor shall, on SDG&E s request, defend any action, claim or suit asserting a claim that may be covered by this indemnity. Project Sponsor shall pay all costs and expenses that may be incurred by SDG&E in enforcing this indemnity, including reasonable attorney's fees. This indemnity shall survive the termination of this Agreement for any reason If this Agreement is assigned pursuant to Section 10.0, Project Sponsor agrees that this indemnification shall continue to apply to SDG&E and shall apply to the assignee LIMITATION OF LIABILITY SDG&E shall not be liable for any special, incidental, indirect, or consequential damages, including without limitation, loss of profits or commitments to subcontractors, and any special, incidental, indirect or consequential damages incurred by Project Sponsor or Customer WRITTEN NOTICE Any written notice, demand or request required or authorized in connection with this Agreement shall be deemed properly given if delivered in person or sent by facsimile, , nationally recognized overnight courier, or first class mail, postage prepaid, to the address specified below, or to another address specified in writing by SDG&E. SDG&E PROJECT SPONSOR Program Manager SDG&E Address 8335 Century Park Court, CP12C City, State, Zip San Diego, CA Fax # (facsimile) (619) Name Company Address City, State, Zip Fax # (facsimile) Notices shall be deemed received (a) if personally or hand-delivered, upon the date of delivery to the address of the person to receive such notice if delivered before 5:00 p.m., or otherwise on the Business Day following personal delivery; (b) if mailed, three (3) Business Days after the date the notice is postmarked; (c) if by facsimile or , upon electronic confirmation of transmission, followed by telephone notification of transmission by the noticing Party; or (d) if by overnight courier, on the Business Day following delivery to the overnight courier within the time limits set by that courier for next-day delivery. Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

163 16.0 CONFLICTS BETWEEN TERMS Should a conflict exist between this Agreement and the documents incorporated by reference, this Agreement shall control. Should a conflict exist in the documents incorporated by reference, the documents shall control in the following order: 1) Program Manual; 2) SDG&E acceptance letter(s) and incentive estimate(s) based on EEMs as approved in the Application(s); and 3) Project Sponsor s approved Application(s). Should a conflict exist between an applicable federal, state, or local law, rule, regulation, order or code and this Agreement, the law, rule, regulation, order or code shall control. Varying degrees of stringency among the main body of this Agreement, the documents incorporated by reference, and laws, rules, regulations, orders, or codes are not deemed conflicts, and the most stringent requirement shall control. Each Party shall notify the other immediately upon the identification of any conflict or inconsistency concerning this Agreement MISCELLANEOUS This Agreement shall at all times be subject to such changes or modifications by the CPUC as it may from time to time direct in the exercise of its jurisdiction. This Agreement shall be governed and construed in accordance with the laws of the State of California, without regard to its conflict of laws provisions. If any provision of this Agreement shall be held by a court of competent jurisdiction to be illegal, invalid or unenforceable, the remaining provisions shall remain in full force and effect. This Agreement constitutes the entire agreement and understanding between the Parties as to the subject matter of this Agreement and supersedes all prior agreements, representations, writings and discussions between the Parties, whether oral or written, with respect to the subject matter hereof. No amendment, modification or change to this Agreement shall be binding or effective unless expressly set forth in writing and signed by SDG&E s representative authorized to execute the Agreement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their duly authorized representatives as of the date set forth below. UTILITY PROJECT SPONSOR By: Title: Name Printed: Date: By: Title: Name Printed: Date: Supervisor,Commercial & Industrial, Customer Programs Version STATEWIDE CUSTOMIZED OFFERING AGREEMENT

164 Appendix B Table of Standard Fixture Wattages and Sample Lighting Table

165 Appendix B: Table of Standard Fixture Wattages The 2010 Table of Standard Fixture Wattages was generated under the following guidelines: 1. All fixtures must comply with Title 10 of the Code of Federal Regulations (same as CWT) as well as California s Title 24 Regulations; and 2. All fixtures using 4-foot or U-tube standard 40 W fluorescent lamps (F40T12 or FU40T12) are excluded, with the exception of equivalent standard high-output and instant-start fixtures. All fixtures with 8-foot standard 75 W lamps (F96T12) are excluded as well as all fixtures with 8-foot high output 110 W lamps (F96T12HO). The motivation for the exclusion of these standard lamp fixtures is that most cool-white and warm-white general purpose lamps of the above types do not meet federal code (Title 10). New codes that do not conform to these guidelines will not be added to the 2010 table. Lighting fixtures are uniquely identified based on the first five columns of the table (Fixture Code, Lamp Code, Ballast Type, Nominal Watts/Lamp, and Lamps/Fixture). Screw-in lamps CFLs are not eligible for Statewide Customized Offering incentives. February 25, 2010 B - 1 Version 1.1

166 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION kw/ FIXT Compact Fluorescent Fixtures CF10/2D CFD10W Mag-STD 10 1 Compact Fluorescent, 2D, (1) 10W lamp CF16/2D CFD16W Mag-STD 16 1 Compact Fluorescent, 2D, (1) 16W lamp CF21/2D CFD21W Mag-STD 21 1 Compact Fluorescent, 2D, (1) 21W lamp CF28/2D CFD28W Mag-STD 28 1 Compact Fluorescent, 2D, (1) 28W lamp CF38/2D CFD38W Mag-STD 38 1 Compact Fluorescent, 2D, (1) 38W lamp CFQ10/1 CFQ10W Mag-STD 10 1 Compact Fluorescent, quad, (1) 10W lamp CFQ13/1 CFQ13W Mag-STD 13 1 Compact Fluorescent, quad, (1) 13W lamp CFQ13/1-L CFQ13W Electronic 13 1 Compact Fluorescent, quad, (1) 13W lamp, BF= CFQ13/2 CFQ13W Mag-STD 13 2 Compact Fluorescent, quad, (2) 13W lamp CFQ13/2-L CFQ13W Electronic 13 2 Compact Fluorescent, quad, (2) 13W lamp, BF= CFQ13/3 CFQ13W Mag-STD 13 3 Compact Fluorescent, quad, (3) 13W lamp CFQ15/1 CFQ15W Mag-STD 15 1 Compact Fluorescent, quad, (1) 15W lamp CFQ17/1 CFQ17W Mag-STD 17 1 Compact Fluorescent, quad, (1) 17W lamp CFQ17/2 CFQ17W Mag-STD 17 2 Compact Fluorescent, quad, (2) 17W lamp CFQ18/1 CFQ18W Mag-STD 18 1 Compact Fluorescent, quad, (1) 18W lamp CFQ18/1-L CFQ18W Electronic 18 1 Compact Fluorescent, quad, (1) 18W lamp, BF= CFQ18/2 CFQ18W Mag-STD 18 2 Compact Fluorescent, quad, (2) 18W lamp CFQ18/2-L CFQ18W Electronic 18 2 Compact Fluorescent, quad, (2) 18W lamp, BF= CFQ18/4 CFQ18W Mag-STD 18 2 Compact Fluorescent, quad, (4) 18W lamp CFQ20/1 CFQ20W Mag-STD 20 1 Compact Fluorescent, quad, (1) 20W lamp CFQ20/2 CFQ20W Mag-STD 20 2 Compact Fluorescent, quad, (2) 20W lamp CFQ22/1 CFQ22W Mag-STD 22 1 Compact Fluorescent, Quad, (1) 22W lamp CFQ22/2 CFQ22W Mag-STD 22 2 Compact Fluorescent, Quad, (2) 22W lamp CFQ22/3 CFQ22W Mag-STD 22 3 Compact Fluorescent, Quad, (3) 22W lamp CFQ25/1 CFQ25W Mag-STD 25 1 Compact Fluorescent, Quad, (1) 25W lamp CFQ25/2 CFQ25W Mag-STD 25 2 Compact Fluorescent, Quad, (2) 25W lamp CFQ26/1 CFQ26W Mag-STD 26 1 Compact Fluorescent, quad, (1) 26W lamp CFQ26/1-L CFQ26W Electronic 26 1 Compact Fluorescent, quad, (1) 26W lamp, BF= CFQ26/2 CFQ26W Mag-STD 26 2 Compact Fluorescent, quad, (2) 26W lamp CFQ26/2-L CFQ26W Electronic 26 2 Compact Fluorescent, quad, (2) 26W lamp, BF= CFQ26/3 CFQ26W Mag-STD 26 3 Compact Fluorescent, quad, (3) 26W lamp CFQ26/6-L CFQ26W Electronic 26 6 Compact Fluorescent, quad, (6) 26W lamp, BF= CFQ28/1 CFQ28W Mag-STD 28 1 Compact Fluorescent, quad, (1) 28W lamp February 25, 2010 B - 2 Version 1.1

167 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION CFQ9/1 CFQ9W Mag-STD 9 1 Compact Fluorescent, Quad, (1) 9W lamp CFQ9/2 CFQ9W Mag-STD 9 2 Compact Fluorescent, Quad, (2) 9W lamp CFT13/1 CFT13W Mag-STD 13 1 Compact Fluorescent, twin, (1) 13W lamp CFT13/2 CFT13W Mag-STD 13 2 Compact Fluorescent, twin, (2) 13W lamp CFT13/3 CFT13W Mag-STD 13 3 Compact Fluorescent, twin, (3) 13 W lamp CFT18/1 CFT18W Mag-STD 18 1 Compact Fluorescent, Long twin., (1) 18W lamp CFT22/1 CFT22W Mag-STD 22 1 Compact Fluorescent, twin, (1) 22W lamp CFT22/2 CFT22W Mag-STD 22 2 Compact Fluorescent, twin, (2) 22W lamp CFT22/4 CFT22W Mag-STD 22 4 Compact Fluorescent, twin, (4) 22W lamp CFT24/1 CFT24W Mag-STD 24 1 Compact Fluorescent, long twin, (1) 24W lamp CFT28/1 CFT28W Mag-STD 28 1 Compact Fluorescent, twin, (1) 28W lamp CFT28/2 CFT28W Mag-STD 28 2 Compact Fluorescent, twin, (2) 28W lamp CFT32/1-L CFM32W Electronic 32 1 Compact Fluorescent, twin or multi, (1) 32W lamp CFT32/2-L CFM32W Electronic 32 2 Compact Fluorescent, twin or multi, (2) 32W lamp CFT32/6-L CFM32W Electronic 32 6 Compact Fluorescent, twin or multi, (2) 32W lamp CFT36/1 CFT36W Mag-STD 36 1 Compact Fluorescent, long twin, (1) 36W lamp CFT40/1 CFT40W Mag-STD 40 1 Compact Fluorescent, twin, (1) 40W lamp CFT40/1-L CFT40W Electronic 40 1 Compact Fluorescent, long twin, (1) 40W lamp CFT40/2 CFT40W Mag-STD 40 2 Compact Fluorescent, twin, (2) 40W lamp CFT40/2-L CFT40W Electronic 40 2 Compact Fluorescent, long twin, (2) 40W lamp CFT40/3 CFT40W Mag-STD 40 3 Compact Fluorescent, twin, (3) 40 W lamp CFT40/3-L CFT40W Electronic 40 3 Compact Fluorescent, long twin, (3) 40W lamp CFT5/1 CFT5W Mag-STD 5 1 Compact Fluorescent, twin, (1) 5W lamp CFT5/2 CFT5W Mag-STD 5 2 Compact Fluorescent, twin, (2) 5W lamp CFT7/1 CFT7W Mag-STD 7 1 Compact Fluorescent, twin, (1) 7W lamp CFT7/2 CFT7W Mag-STD 7 2 Compact Fluorescent, twin, (2) 7W lamp CFT9/1 CFT9W Mag-STD 9 1 Compact Fluorescent, twin, (1) 9W lamp CFT9/2 CFT9W Mag-STD 9 2 Compact Fluorescent, twin, (2) 9W lamp CFT9/3 CFT9W Mag-STD 9 3 Compact Fluorescent, twin, (3) 9 W lamp F32T8 Linear Fluorescent Fixtures 70 CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start F41ILL F32T8-STD Electronic 32 1 Ballast, NLO F41ILL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO kw/ FIXT February 25, 2010 B - 3 Version 1.1

168 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F41ILL F32T8-PREM Elec-Prem 32 1 F41ILL/T2 F32T8-STD Electronic 32 1 F41ILL/T2 F32T8-PREM Electronic 32 1 F41ILL/T2-H F32T8-STD Electronic 32 1 F41ILL/T2-H F32T8-PREM Electronic 32 1 F41ILL/T2-R F32T8-STD Electronic 32 1 F41ILL/T2-R F32T8-PREM Electronic 32 1 F41ILL/T2-V F32T8-STD Electronic 32 1 F41ILL/T2-V F32T8-PREM Electronic 32 1 F41ILL/T3 F32T8-STD Electronic 32 1 F41ILL/T3 F32T8-PREM Electronic 32 1 F41ILL/T3-H F32T8-STD Electronic 32 1 F41ILL/T3-H F32T8-PREM Electronic 32 1 F41ILL/T3-R F32T8-STD Electronic 32 1 F41ILL/T3-R F32T8-PREM Electronic 32 1 F41ILL/T3-V F32T8-STD Electronic 32 1 F41ILL/T3-V F32T8-PREM Electronic 32 1 F41ILL/T4 F32T8-STD Electronic 32 1 kw/ DESCRIPTION FIXT 85 CRI, 24,000 Hr. RSR, Fluorescent, (1)48" T-8 lamp, Premium IS Ballast, NLO CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 2 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 2 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast February 25, 2010 B - 4 Version 1.1

169 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F41ILL/T4 F32T8-PREM Electronic 32 1 F41ILL/T4-R F32T8-STD Electronic 32 1 F41ILL/T4-R F32T8-PREM Electronic 32 1 F41ILL/T4-V F32T8-STD Electronic 32 1 DESCRIPTION kw/ FIXT 85 CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, IS Ballast, RLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 4 Lamp Ballast F41ILL/T4-V F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO, Tandem 4 Lamp Ballast F41ILL-H F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO F41ILL-H F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Instant Start Ballast, HLO F41ILL-R F32T8-PREM Elec-Prem-R CRI, 24,000 Hr. RSR, Fluorescent, (1)48" T-8 lamp, Premium IS Ballast, RLO F41ILL-V F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO F41ILL-V F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T8 lamp, Instant Start Ballast, VHLO F41LE F32T8-STD Mag-ES CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp F41LL F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO F41LL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO F41LL/T2 F32T8-STD Electronic 32 1 F41LL/T2 F32T8-PREM Electronic 32 1 F41LL/T2-H F32T8-STD Electronic 32 1 F41LL/T2-H F32T8-PREM Electronic 32 1 F41LL/T2-R F32T8-STD Electronic 32 1 F41LL/T2-R F32T8-PREM Electronic CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 2 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO, Tandem 2 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 2 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 2 Lamp Ballast February 25, 2010 B - 5 Version 1.1

170 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F41LL/T3 F32T8-STD Electronic 32 1 F41LL/T3 F32T8-PREM Electronic 32 1 F41LL/T3-H F32T8-STD Electronic 32 1 F41LL/T3-H F32T8-PREM Electronic 32 1 F41LL/T3-R F32T8-STD Electronic 32 1 F41LL/T3-R F32T8-PREM Electronic 32 1 F41LL/T4 F32T8-STD Electronic 32 1 F41LL/T4 F32T8-PREM Electronic 32 1 F41LL/T4-R F32T8-STD Electronic 32 1 F41LL/T4-R F32T8-PREM Electronic 32 1 F41LL-H F32T8-STD Electronic 32 1 F41LL-H F32T8-PREM Electronic 32 1 F41LL-R F32T8-STD Electronic 32 1 F41LL-R F32T8-PREM Electronic 32 1 F41WLL F32T8-PREM-ES Elec-Prem 30 1 F41WLL-R F32T8-PREM-ES Elec-Prem-R 30 1 F42ILL F32T8-STD Electronic 32 2 F42ILL F32T8-PREM Electronic 32 2 F42ILL F32T8-PREM Elec-Prem 32 2 DESCRIPTION kw/ FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 3 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 3 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, HLO CRI, 20,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (1) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 15,000 Hr. ISR, Fluorescent, (1)48" ES T-8 lamp, Premium IS Ballast, NLO CRI, 15,000 Hr. ISR, Fluorescent, (1)48" ES T-8 lamp, Premium IS Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (2)48" T-8 lamp, Premium IS Ballast, NLO February 25, 2010 B - 6 Version 1.1

171 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F42ILL/T4 F32T8-STD Electronic 32 2 F42ILL/T4 F32T8-PREM Electronic 32 2 F42ILL/T4-R F32T8-STD Electronic 32 2 DESCRIPTION kw/ FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast F42ILL/T4-R F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast F42ILL-H F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, HLO F42ILL-H F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, HLO F42ILL-R F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, RLO F42ILL-R F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, RLO F42ILL-R F32T8-PREM Elec-Prem-R CRI, 24,000 Hr. RSR, Fluorescent, (2)48" T-8 lamp, Premium IS Ballast, RLO F42ILL-V F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, VHLO F42ILL-V F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Instant Start Ballast, VHLO F42LE F32T8-STD Mag-ES CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp F42LL F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, NLO F42LL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, NLO F42LL/T4 F32T8-STD Electronic 32 2 F42LL/T4 F32T8-PREM Electronic 32 2 F42LL/T4-R F32T8-STD Electronic 32 2 F42LL/T4-R F32T8-PREM Electronic 32 2 F42LL-H F32T8-STD Electronic 32 2 F42LL-H F32T8-PREM Electronic CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 4 Lamp Ballast CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, RLO, Tandem 4 Lamp Ballast CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, HLO CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, HLO February 25, 2010 B - 7 Version 1.1

172 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F42LL-R F32T8-STD Electronic 32 2 F42LL-R F32T8-PREM Electronic 32 2 F42LL-V F32T8-STD Electronic 32 2 F42LL-V F32T8-PREM Electronic 32 2 F42WLL F32T8-PREM-ES Elec-Prem 30 2 F42WLL-R F32T8-PREM-ES Elec-Prem-R 30 2 F43ILL F32T8-STD Electronic 32 3 F43ILL F32T8-PREM Electronic 32 3 F43ILL F32T8-PREM Elec-Prem 32 3 F43ILL/2 F32T8-STD Electronic 32 3 kw/ DESCRIPTION FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, VHLO CRI, 24,000 Hr. RSR, Fluorescent, (2) 48", T-8 lamp, Rapid Start Ballast, VHLO CRI, 15,000 Hr. ISR, Fluorescent, (2)48" ES T-8 lamp, Premium IS Ballast, NLO CRI, 15,000 Hr. ISR, Fluorescent, (2)48" ES T-8 lamp, Premium IS Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (3)48" T-8 lamp, Premium IS Ballast, NLO CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, NLO, (2) ballast F43ILL/2 F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, NLO, (2) ballast F43ILL-H F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, HLO F43ILL-H F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, HLO F43ILL-R F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, RLO F43ILL-R F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, RLO F43ILL-R F32T8-PREM Elec-Prem-R CRI, 24,000 Hr. RSR, Fluorescent, (3)48" T-8 lamp, Premium IS Ballast, RLO F43ILL-V F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, VHLO F43ILL-V F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Instant Start Ballast, VHLO F43LE F32T8-STD Mag-ES CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp F43LL F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, NLO F43LL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, NLO February 25, 2010 B - 8 Version 1.1

173 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F43LL/2 F32T8-STD Electronic 32 3 F43LL/2 F32T8-PREM Electronic 32 3 F43LL-H F32T8-STD Electronic 32 3 F43LL-H F32T8-PREM Electronic 32 3 F43LL-R F32T8-STD Electronic 32 3 F43LL-R F32T8-PREM Electronic 32 3 F43WLL F32T8-PREM-ES Elec-Prem 30 3 F43WLL-R F32T8-PREM-ES Elec-Prem-R 30 3 F44ILL F32T8-STD Electronic 32 4 F44ILL F32T8-PREM Electronic 32 4 F44ILL F32T8-PREM Elec-Prem 32 4 F44ILL/2 F32T8-STD Electronic 32 4 F44ILL/2 F32T8-PREM Electronic 32 4 F44ILL/2-V F32T8-STD Electronic 32 4 F44ILL/2-V F32T8-PREM Electronic 32 4 F44ILL-R F32T8-STD Electronic 32 4 F44ILL-R F32T8-PREM Electronic 32 4 F44ILL-R F32T8-PREM Elec-Prem-R 32 4 F44ILL-V F32T8-STD Electronic 32 4 F44ILL-V F32T8-PREM Electronic 32 4 DESCRIPTION kw/ FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, NLO, (2) ballast CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, NLO, (2) ballast CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, HLO CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, HLO CRI, 20,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (3) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 15,000 Hr. ISR, Fluorescent, (3)48" ES T-8 lamp, Premium IS Ballast, NLO CRI, 15,000 Hr. ISR, Fluorescent, (3)48" ES T-8 lamp, Premium IS Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (4)48" T-8 lamp, Premium IS Ballast, NLO CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, NLO, (2) ballast CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, NLO, (2) ballast CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T8 lamp, (2) Instant Start Ballasts, VHLO CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T8 lamp, (2) Instant Start Ballasts, VHLO CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Instant Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (4)48" T-8 lamp, Premium IS Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T8 lamp, Instant Start Ballast, VHLO CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T8 lamp, Instant Start Ballast, VHLO February 25, 2010 B - 9 Version 1.1

174 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F44LE F32T8-STD Mag-ES CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp F44LL F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, NLO F44LL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, NLO F44LL/2 F32T8-STD Electronic 32 4 F44LL/2 F32T8-PREM Electronic 32 4 F44LL-R F32T8-STD Electronic 32 4 F44LL-R F32T8-PREM Electronic 32 4 F44WLL F32T8-PREM-ES Elec-Prem 30 4 F44WLL-R F32T8-PREM-ES Elec-Prem-R 30 4 F45ILL F32T8-STD Electronic 32 5 F45ILL F32T8-PREM Electronic 32 5 F45ILL/2-V F32T8-STD Electronic 32 5 F45ILL/2-V F32T8-PREM Electronic 32 5 F46ILL F32T8-STD Electronic 32 6 F46ILL F32T8-PREM Electronic 32 6 F46ILL/2 F32T8-PREM Elec-Prem 32 6 F46ILL/2-R F32T8-PREM Elec-Prem-R 32 6 F46ILL/2-V F32T8-STD Electronic 32 6 F46ILL/2-V F32T8-PREM Electronic 32 6 kw/ FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, NLO, (2) ballast CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, NLO, (2) ballast CRI, 20,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (4) 48", T-8 lamp, Rapid Start Ballast, RLO CRI, 15,000 Hr. ISR, Fluorescent, (4)48" ES T-8 lamp, Premium IS Ballast, NLO CRI, 15,000 Hr. ISR, Fluorescent, (4)48" ES T-8 lamp, Premium IS Ballast, RLO CRI, 20,000 Hr. RSR, Fluorescent, (5) 48", T-8 lamp, (1) 3-lamp IS ballast and (1) 2-lamp IS ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (5) 48", T-8 lamp, (1) 3-lamp IS ballast and (1) 2-lamp IS ballast, NLO CRI, 20,000 Hr. RSR, Fluorescent, (5) 48", T8 lamp, (2) Instant Start Ballasts, VHLO CRI, 24,000 Hr. RSR, Fluorescent, (5) 48", T8 lamp, (2) Instant Start Ballasts, VHLO CRI, 20,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T8 lamp, (2) Premium IS Ballasts, NLO CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T8 lamp, (2) Premium IS Ballasts, RLO CRI, 20,000 Hr. RSR, Fluorescent, (6) 48", T8 lamp, (2) Instant Start Ballasts, VHLO CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T8 lamp, (2) Instant Start Ballasts, VHLO February 25, 2010 B - 10 Version 1.1

175 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F46ILL-R F32T8-STD Electronic 32 6 kw/ DESCRIPTION FIXT 70 CRI, 20,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Instant Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Instant Start Ballast, RLO F46ILL-R F32T8-PREM Electronic 32 6 F46LL F32T8-STD Electronic CRI, 20,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Ballast, NLO F46LL F32T8-PREM Electronic CRI, 24,000 Hr. RSR, Fluorescent, (6) 48", T-8 lamp, Ballast, NLO F46WLL/2 F32T8-PREM-ES Elec-Prem 30 6 F46WLL/2-R F32T8-PREM-ES Elec-Prem-R 30 6 F48ILL F32T8-STD Electronic 32 8 F48ILL F32T8-PREM Electronic 32 8 F48ILL/2 F32T8-PREM Elec-Prem 32 8 F48ILL/2-R F32T8-PREM Elec-Prem-R 32 8 F48ILL-R F32T8-STD Electronic 32 8 F48ILL-R F32T8-PREM Electronic 32 8 F48WLL/2 F32T8-PREM-ES Elec-Prem 30 8 F48WLL/2-R F32T8-PREM-ES Elec-Prem-R CRI, 15,000 Hr. ISR, Fluorescent, (6) 48", ES T8 lamp, (2) Premium IS Ballasts, NLO CRI, 15,000 Hr. ISR, Fluorescent, (6) 48", ES T8 lamp, (2) Premium IS Ballasts, RLO CRI, 20,000 Hr. RSR, Fluorescent, (8) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (8) 48", T-8 lamp, Instant Start Ballast, NLO CRI, 24,000 Hr. RSR, Fluorescent, (8) 48", T8 lamp, (2) Premium IS Ballasts, NLO CRI, 24,000 Hr. RSR, Fluorescent, (8) 48", T8 lamp, (2) Premium IS Ballasts, RLO CRI, 20,000 Hr. RSR, Fluorescent, (8) 48", T-8 lamp, Instant Start Ballast, RLO CRI, 24,000 Hr. RSR, Fluorescent, (8) 48", T-8 lamp, Instant Start Ballast, RLO CRI, 15,000 Hr. ISR, Fluorescent, (8) 48", ES T8 lamp, (2) Premium IS Ballasts, NLO CRI, 15,000 Hr. ISR, Fluorescent, (8) 48", ES T8 lamp, (2) Premium IS Ballasts, RLO F28T8 Linear Fluorescent Systems 86 CRI, 20,000 HR, RSR, Fluorescent, (2) 48'' T-8 lamp, Premium PRS F42WLL F28T8-PREM-ES Elec-Prem 25 2 Ballast, NLO F42WLL F28T8-PREM-ES Elec-Prem CRI, 18,000 HR. RSR, Fluorescent, (2) 48'' T-8 lamp, Premium PRS Ballast, NLO F42WLL-R F28T8-PREM-ES Elec-Prem-R CRI, 18,000 HR. RSR, Fluorescent, (2) 48'' T-8 lamp, Premium PRS Ballast, RLO F42WLL-V F28T8-PREM-ES Elec-Prem CRI, 18,000 HR. RSR, Fluorescent, (2) 48'' T-8 lamp, Premium PRS Ballast, VHLO F43WLL F28T8-PREM-ES Elec-Prem CRI, 20,000 HR, RSR, Fluorescent, (3) 48'' T-8 lamp, Premium PRS Ballast, NLO F43WLL F28T8-PREM-ES Elec-Prem CRI, 18,000 HR. RSR, Fluorescent, (3) 48'' T-8 lamp, Premium PRS Ballast, NLO February 25, 2010 B - 11 Version 1.1

176 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT F43WLL-R F28T8-PREM-ES Elec-Prem-R 28 3 F43WLL-V F28T8-PREM-ES Elec-Prem 28 3 F44WLL F28T8-PREM-ES Elec-Prem 25 4 F44WLL F28T8-PREM-ES Elec-Prem 28 4 F44WLL-R F28T8-PREM-ES Elec-Prem-R 25 4 F44WLL-R F28T8-PREM-ES Elec-Prem-R 28 4 kw/ DESCRIPTION FIXT 82 CRI, 18,000 HR. RSR, Fluorescent, (3) 48'' T-8 lamp, Premium PRS Ballast, RLO CRI, 18,000 HR. RSR, Fluorescent, (3) 48'' T-8 lamp, Premium PRS Ballast, VHLO CRI, 20,000 HR, RSR, Fluorescent, (4) 48'' T-8 lamp, Premium PRS Ballast, NLO CRI, 18,000 HR. RSR, Fluorescent, (4) 48'' T-8 lamp, Premium PRS Ballast, NLO CRI, 20,000 HR, RSR, Fluorescent, (4) 48'' T-8 lamp, Premium PRS Ballast, RLO CRI, 18,000 HR. RSR, Fluorescent, (4) 48'' T-8 lamp, Premium PRS Ballast, RLO T5 and T5HO Linear Fluorescent Systems F21PHL F24T5/HO Electronic 24 1 Fluorescent, (1) 22", T5/HO lamp, Instant Start Ballast F21PL F14T5 Electronic 14 1 Fluorescent, (1) 22", T5 lamp, Instant Start Ballast F22PHL F24T5/HO Electronic 24 2 Fluorescent, (2) 22", T5/HO lamp, Instant Start Ballast F22PL F14T5 Electronic 14 2 Fluorescent, (2) 22", T5 lamp, Instant Start Ballast F23PHL/2 F24T5/HO Electronic 24 3 Fluorescent, (3) 22", T5/HO lamp, (2) Instant Start Ballasts F23PL/2 F14T5 Electronic 14 3 Fluorescent, (3) 22", T5 lamp, (2) Instant Start Ballasts F24PHL/2 F24T5/HO Electronic 24 4 Fluorescent, (4) 22", T5/HO lamp, (2) Instant Start Ballast F24PL/2 F14T5 Electronic 14 4 Fluorescent, (4) 22", T5 lamp, (2) Instant Start Ballasts F31PHL F39T5/HO Electronic 39 1 Fluorescent, (1) 34", T5/HO lamp, Instant Start Ballast F31PL F21T5 Electronic 21 1 Fluorescent, (1) 34", T5 lamp, Instant Start Ballast F32PHL F39T5/HO Electronic 39 2 Fluorescent, (2) 34", T5/HO lamp, Instant Start Ballast F32PL F21T5 Electronic 21 2 Fluorescent, (2) 34", T5 lamp, Instant Start Ballast F33PHL/2 F39T5/HO Electronic 39 3 Fluorescent, (3) 34", T5/HO lamp, (2) Instant Start Ballasts F33PL/2 F21T5 Electronic 21 3 Fluorescent, (3) 34", T5 lamp, (2) Instant Start Ballasts F34PHL/2 F39T5/HO Electronic 39 4 Fluorescent, (4) 34", T5/HO lamp, (2) Instant Start Ballast F34PL/2 F21T5 Electronic 21 4 Fluorescent, (4) 34", T5 lamp, (2) Instant Start Ballasts F36PHL/3 F39T5/HO Electronic 39 6 Fluorescent, (6) 34", T5/HO lamp, (3) Instant Start Ballast F38PHL/4 F39T5/HO Electronic 39 8 Fluorescent, (8) 34", T5/HO lamp, (4) Instant Start Ballast F41PHL F54T5/HO Electronic 54 1 Fluorescent, (1) 46", T5/HO lamp, Instant Start Ballast F41PHL/T2 F54T5/HO Electronic 54 1 Fluorescent, (1) 46", T5/HO lamp, Instant Start Ballast, Tandem 2 Lamp Ballast F41PL F28T5 Electronic 28 1 Fluorescent, (1) 46", T5 lamp, Instant Start Ballast F41PL/T2 F28T5 Electronic 28 1 Fluorescent, (1) 46", T5 lamp, Instant Start Ballast, Tandem 2 Lamp Ballast February 25, 2010 B - 12 Version 1.1

177 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F42PHL F54T5/HO Electronic 54 2 Fluorescent, (2) 46", T5/HO lamp, Instant Start Ballast F42PL F28T5 Electronic 28 2 Fluorescent, (2) 46", T5 lamp, Instant Start Ballast F43PHL/2 F54T5/HO Electronic 54 3 Fluorescent, (3) 46", T5/HO lamp, (2) Instant Start Ballasts F43PL/2 F28T5 Electronic 28 3 Fluorescent, (3) 46", T5 lamp, (2) Instant Start Ballasts F44PHL/2 F54T5/HO Electronic 54 4 Fluorescent, (4) 46", T5/HO lamp, (2) Instant Start Ballast F44PL/2 F28T5 Electronic 28 4 Fluorescent, (4) 46", T5 lamp, (2) Instant Start Ballasts F46PHL/3 F54T5/HO Electronic 54 6 Fluorescent, (6) 46", T5/HO lamp, (3) Instant Start Ballast F46PL/3 F28T5 Electronic 28 6 Fluorescent, (6) 46", T5 lamp, (3) Instant Start Ballasts F48PHL/4 F54T5/HO Electronic 54 8 Fluorescent, (8) 46", T5/HO lamp, (4) Instant Start Ballast F48PL/4 F28T5 Electronic 28 8 Fluorescent, (8) 46", T5 lamp, (4) Instant Start Ballasts F51PHL F80T5/HO Electronic 80 1 Fluorescent, (1) 58", T5/HO lamp, Instant Start Ballast F51PL F35T5 Electronic 35 1 Fluorescent, (1) 58", T5 lamp, Instant Start Ballast F52PL F35T5 Electronic 35 2 Fluorescent, (2) 58", T5 lamp, Instant Start Ballast F53PL/2 F35T5 Electronic 35 3 Fluorescent, (3) 58", T5 lamp, (2) Instant Start Ballasts F54PL/2 F35T5 Electronic 35 4 Fluorescent, (4) 58", T5 lamp, (2) Instant Start Ballasts F56PL/3 F35T5 Electronic 35 6 Fluorescent, (6) 58", T5 lamp, (3) Instant Start Ballasts F58PL/4 F35T5 Electronic 35 8 Fluorescent, (8) 58", T5 lamp, (4) Instant Start Ballasts Other Linear Fluorescent Fixtures F1.51LS F15T8 Mag-STD 15 1 Fluorescent, (1) 18" T8 lamp F1.51SS F15T12 Mag-STD 15 1 Fluorescent, (1) 18" T12 lamp F1.52LS F15T8 Mag-STD 15 2 Fluorescent, (2) 18" T8 lamp F1.52SS F15T12 Mag-STD 15 2 Fluorescent, (2) 18", T12 lamp F21HS F24T12/HO Mag-STD 35 1 Fluorescent, (1) 24", HO lamp F21ILL F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, NLO F21ILL/T2 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast F21ILL/T2-R F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, RLO, Tandem 2 Lamp Ballast F21ILL/T3 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, NLO, Tandem 3 Lamp Ballast F21ILL/T3-R F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, RLO, Tandem 3 Lamp Ballast F21ILL/T4 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast F21ILL/T4-R F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast kw/ FIXT February 25, 2010 B - 13 Version 1.1

178 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F21LL F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Rapid Start Ballast, NLO F21LL/T2 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Rapid Start Ballast, NLO, Tandem 2 Lamp Ballast F21LL/T3 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Rapid Start Ballast, NLO, Tandem 3 Lamp Ballast F21LL/T4 F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast F21LL-R F17T8 Electronic 17 1 Fluorescent, (1) 24", T-8 lamp, Rapid Start Ballast, RLO F21LS F17T8 Mag-STD 17 1 Fluorescent, (1) 24", T8 lamp, Standard Ballast F21SS F20T12 Mag-STD 20 1 Fluorescent, (1) 24", STD lamp F22HS F24T12/HO Mag-STD 35 2 Fluorescent, (2) 24", HO lamp F22ILL F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Instant Start Ballast, NLO F22ILL/T4 F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast F22ILL/T4-R F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast F22ILL-R F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Instant Start Ballast, RLO F22LL F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Rapid Start Ballast, NLO F22LL/T4 F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast F22LL-R F17T8 Electronic 17 2 Fluorescent, (2) 24", T-8 lamp, Rapid Start Ballast, RLO F22SS F20T12 Mag-STD 20 2 Fluorescent, (2) 24", STD lamp F23ILL F17T8 Electronic 17 3 Fluorescent, (3) 24", T-8 lamp, Instant Start Ballast, NLO F23ILL-H F17T8 Electronic 17 3 Fluorescent, (3) 24", T-8 lamp, Instant Start Ballast, HLO F23ILL-R F17T8 Electronic 17 3 Fluorescent, (3) 24", T-8 lamp, Instant Start Ballast, RLO F23LL F17T8 Electronic 17 3 Fluorescent, (3) 24", T-8 lamp, Rapid Start Ballast, NLO F23LL-R F17T8 Electronic 17 3 Fluorescent, (3) 24", T-8 lamp, Rapid Start Ballast, RLO F23SS F20T12 Mag-STD 20 3 Fluorescent, (3) 24", STD lamp F24ILL F17T8 Electronic 17 4 Fluorescent, (4) 24", T-8 lamp, Instant Start Ballast, NLO F24ILL-R F17T8 Electronic 17 4 Fluorescent, (4) 24", T-8 lamp, Instant Start Ballast, RLO F24LL F17T8 Electronic 17 4 Fluorescent, (4) 24", T-8 lamp, Rapid Start Ballast, NLO F24LL-R F17T8 Electronic 17 4 Fluorescent, (4) 24", T-8 lamp, Rapid Start Ballast, RLO F24SS F20T12 Mag-STD 20 4 Fluorescent, (4) 24", STD lamp F26SS F20T12 Mag-STD 20 6 Fluorescent, (6) 24", STD lamp F31EE/T2 F30T12/ES Mag-ES 25 1 Fluorescent, (1) 36", ES lamp, Tandem wired F31EL F30T12/ES Electronic 25 1 Fluorescent, (1) 36", ES lamp F31ES F30T12/ES Mag-STD 25 1 Fluorescent, (1) 36", ES lamp kw/ FIXT February 25, 2010 B - 14 Version 1.1

179 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F31ES/T2 F30T12/ES Mag-STD 25 1 Fluorescent, (1) 36", ES lamp, Tandem wired F31ILL F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, NLO F31ILL/T2 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast F31ILL/T2-H F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, HLO, Tandem 2 Lamp Ballast F31ILL/T2-R F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, RLO, Tandem 2 Lamp Ballast F31ILL/T3 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, NLO, Tandem 3 Lamp Ballast F31ILL/T3-R F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, RLO, Tandem 3 Lamp Ballast F31ILL/T4 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast F31ILL/T4-R F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast F31ILL-H F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, HLO F31ILL-R F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Instant Start Ballast, RLO F31LL F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, NLO F31LL/T2 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, NLO, Tandem 2 Lamp Ballast F31LL/T3 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, NLO, Tandem 3 Lamp Ballast F31LL/T4 F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast F31LL-H F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, HLO F31LL-R F25T8 Electronic 25 1 Fluorescent, (1) 36", T-8 lamp, Rapid Start Ballast, RLO F31SE/T2 F30T12 Mag-ES 30 1 Fluorescent, (1) 36", STD lamp, Tandem wired F31SHS F36T12/HO Mag-STD 50 1 Fluorescent, (1) 36", HO lamp F31SL F30T12 Electronic 30 1 Fluorescent, (1) 36", STD lamp F31SS F30T12 Mag-STD 30 1 Fluorescent, (1) 36", STD lamp F31SS/T2 F30T12 Mag-STD 30 1 Fluorescent, (1) 36", STD lamp, Tandem wired F32EE F30T12/ES Mag-ES 25 2 Fluorescent, (2) 36", ES lamp F32EL F30T12/ES Electronic 25 2 Fluorescent, (2) 36", ES lamp F32ES F30T12/ES Mag-STD 25 2 Fluorescent, (2) 36", ES lamp F32ILL F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Instant Start Ballast, NLO F32ILL/T4 F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast kw/ FIXT February 25, 2010 B - 15 Version 1.1

180 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT kw/ DESCRIPTION FIXT Fluorescent, (2) 36", T-8 lamp, Instant Start Ballast, RLO, Tandem 4 Lamp Ballast F32ILL/T4-R F25T8 Electronic 25 2 F32ILL-H F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Instant Start Ballast, HLO F32ILL-R F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Instant Start Ballast, RLO F32LL F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Rapid Start Ballast, NLO Fluorescent, (2) 36", T-8 lamp, Rapid Start Ballast, NLO, Tandem 4 Lamp Ballast F32LL/T4 F25T8 Electronic 25 2 F32LL-H F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Rapid Start Ballast, HLO F32LL-R F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Rapid Start Ballast, RLO F32LL-V F25T8 Electronic 25 2 Fluorescent, (2) 36", T-8 lamp, Rapid Start Ballast, VHLO F32SE F30T12 Mag-ES 30 2 Fluorescent, (2) 36", STD lamp F32SHS F36T12/HO Mag-STD 50 2 Fluorescent, (2) 36", HO, lamp F32SL F30T12 Electronic 30 2 Fluorescent, (2) 36", STD lamp F32SS F30T12 Mag-STD 30 2 Fluorescent, (2) 36", STD lamp F33ES F30T12/ES Mag-STD 25 3 Fluorescent, (3) 36", ES lamp F33ILL F25T8 Electronic 25 3 Fluorescent, (3) 36", T-8 lamp, Instant Start Ballast, NLO F33ILL-R F25T8 Electronic 25 3 Fluorescent, (3) 36", T-8 lamp, Instant Start Ballast, RLO F33LL F25T8 Electronic 25 3 Fluorescent, (3) 36", T-8 lamp, Rapid Start Ballast, NLO F33LL-R F25T8 Electronic 25 3 Fluorescent, (3) 36", T-8 lamp, Rapid Start Ballast, RLO F33SE F30T12 Mag-ES 30 3 Fluorescent, (3) 36", STD lamp, (1) STD ballast and (1) ES ballast F33SS F30T12 Mag-STD 30 3 Fluorescent, (3) 36", STD lamp F34ILL F25T8 Electronic 25 4 Fluorescent, (4) 36", T-8 lamp, Instant Start Ballast, NLO F34ILL-R F25T8 Electronic 25 4 Fluorescent, (4) 36", T-8 lamp, Instant Start Ballast, RLO F34LL F25T8 Electronic 25 4 Fluorescent, (4) 36", T-8 lamp, Rapid Start Ballast, NLO F34LL-R F25T8 Electronic 25 4 Fluorescent, (4) 36", T-8 lamp, Rapid Start Ballast, RLO F34SE F30T12 Mag-ES 30 4 Fluorescent, (4) 36", STD lamp F34SL F30T12 Electronic 30 4 Fluorescent, (4) 36", STD lamp F34SS F30T12 Mag-STD 30 4 Fluorescent, (4) 36", STD lamp F36EE F30T12/ES Mag-ES 25 6 Fluorescent, (2) 36", ES lamp F36ILL-R F25T8 Electronic 25 6 Fluorescent, (6) 36", T-8 lamp, Instant Start Ballast, RLO F36SE F30T12 Mag-ES 30 6 Fluorescent, (2) 36", STD lamp F40EE/D1 None Mag-ES 0 1 Fluorescent, (0) 48" lamp, Completely delamped fixture with (1) hot ballast F40EE/D2 None Mag-ES 0 1 Fluorescent, (0) 48" lamp, Completely delamped fixture with (2) hot ballast F41EE F40T12/ES Mag-ES 34 1 Fluorescent, (1) 48", ES lamp F41EE/D2 F40T12/ES Mag-ES 34 1 Fluorescent, (1) 48", ES lamp, 2 ballast F41EE/T2 F40T12/ES Mag-ES 34 1 Fluorescent, (1) 48", ES lamp, tandem wired, 2-lamp ballast February 25, 2010 B - 16 Version 1.1

181 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F41EHS F48T12/HO/ES Mag-STD 55 1 Fluorescent, (1) 48", ES HO lamp F41EIS F48T12/ES Mag-STD 30 1 Fluorescent, (1) 48" ES Instant Start lamp. Magnetic ballast F41EL F40T12/ES Electronic 34 1 Fluorescent, (1) 48", T12 ES lamp, Electronic Ballast F41IAL F25T12 Electronic 25 1 Fluorescent, (1) 48", F25T12 lamp, Instant Start Ballast F41IAL/T2-R F25T12 Electronic 25 1 Fluorescent, (1) 48", F25T12 lamp, Instant Start, Tandem 2-Lamp Ballast, RLO F41IAL/T3-R F25T12 Electronic 25 1 Fluorescent, (1) 48", F25T12 lamp, Instant Start, Tandem 3-Lamp Ballast, RLO F41SHS F48T12/HO Mag-STD 60 1 Fluorescent, (1) 48", STD HO lamp F41SIL F40T12 Electronic 39 1 Fluorescent, (1) 48", STD IS lamp, Electronic ballast F41SIL/T2 F40T12 Electronic 39 1 Fluorescent, (1) 48", STD IS lamp, Electronic ballast, tandem wired F41SIS F40T12 Mag-STD 39 1 Fluorescent, (1) 48", STD IS lamp F41SIS/T2 F40T12 Mag-STD 39 1 Fluorescent, (1) 48", STD IS lamp, tandem to 2-lamp ballast F41SVS F48T12/VHO Mag-STD Fluorescent, (1) 48", STD VHO lamp F41TS F40T10 Mag-STD 40 1 Fluorescent, (1) 48", T-10 lamp F42EE F40T12/ES Mag-ES 34 2 Fluorescent, (2) 48", ES lamp F42EE/D2 F40T12/ES Mag-ES 34 2 Fluorescent, (2) 48", ES lamp, 2 Ballasts (delamped) F3.52EHS F42T12/HO/ES Mag-STD 55 2 Fluorescent, (2) 42", HO lamp (3.5' lamp) F42EIS F48T12/ES Mag-STD 30 2 Fluorescent, (2) 48" ES Instant Start lamp. Magnetic ballast F42EL F40T12/ES Electronic 34 2 Fluorescent, (2) 48", T12 ES lamps, Electronic Ballast F42IAL/T4-R F25T12 Electronic 25 2 Fluorescent, (2) 48", F25T12 lamp, Instant Start, Tandem 4-Lamp Ballast, RLO F42IAL-R F25T12 Electronic 25 2 Fluorescent, (2) 48", F25T12 lamp, Instant Start Ballast, RLO F42SHS F48T12/HO Mag-STD 60 2 Fluorescent, (2) 48", STD HO lamp F42SIL F40T12 Electronic 39 2 Fluorescent, (2) 48", STD IS lamp, Electronic ballast F42SVS F48T12/VHO Mag-STD Fluorescent, (2) 48", STD VHO lamp F43EE F40T12/ES Mag-ES 34 3 Fluorescent, (3) 48", ES lamp F43EHS F42T12/HO/ES Mag-STD 55 3 Fluorescent, (3) 42", HO lamp (3.5' lamp) F43EIS F48T12/ES Mag-STD 30 3 Fluorescent, (3) 48" ES Instant Start lamp. Magnetic ballast F43EL F40T12/ES Electronic 34 3 Fluorescent, (3) 48", T12 ES lamps, Electronic Ballast F43IAL-R F25T12 Electronic 25 3 Fluorescent, (3) 48", F25T12 lamp, Instant Start Ballast, RLO F43SHS F48T12/HO Mag-STD 60 3 Fluorescent, (3) 48", STD HO lamp F43SIL F40T12 Electronic 39 3 Fluorescent, (3) 48", STD IS lamp, Electronic ballast F43SVS F48T12/VHO Mag-STD Fluorescent, (3) 48", STD VHO lamp F44EE F40T12/ES Mag-ES 34 4 Fluorescent, (4) 48", ES lamp F44EE/D4 F40T12/ES Mag-ES 34 4 Fluorescent, (4) 48", ES lamp, 4 Ballasts (delamped) kw/ FIXT February 25, 2010 B - 17 Version 1.1

182 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F44EHS F48T12/HO/ES Mag-STD 55 4 Fluorescent, (4) 48", ES HO lamp F44EIS F48T12/ES Mag-STD 30 4 Fluorescent, (4) 48" ES Instant Start lamp. Magnetic ballast F44EL F40T12/ES Electronic 34 4 Fluorescent, (4) 48", T12 ES lamps, Electronic Ballast F44EVS F48T12/VHO/ES Mag-STD 95 4 Fluorescent, (4) 48", VHO ES lamp F44IAL-R F25T12 Electronic 25 4 Fluorescent, (4) 48", F25T12 lamp, Instant Start Ballast, RLO F44SHS F48T12/HO Mag-STD 60 4 Fluorescent, (4) 48", STD HO lamp F44SIL F40T12 Electronic 39 4 Fluorescent, (4) 48", STD IS lamp, Electronic ballast F44SVS F48T12/VHO Mag-STD Fluorescent, (4) 48", STD VHO lamp F46EE F40T12/ES Mag-ES 34 6 Fluorescent, (6) 48", ES lamp F46EL F40T12/ES Electronic 34 6 Fluorescent, (6) 48", ES lamp F48EE F40T12/ES Mag-ES 34 8 Fluorescent, (8) 48", ES lamp F51ILL F40T8 Electronic 40 1 Fluorescent, (1) 60", T-8 lamp, Instant Start Ballast, NLO F51ILL/T2 F40T8 Electronic 40 1 Fluorescent, (1) 60", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast F51ILL/T3 F40T8 Electronic 40 1 Fluorescent, (1) 60", T-8 lamp, Instant Start Ballast, NLO, Tandem 3 Lamp Ballast F51ILL/T4 F40T8 Electronic 40 1 Fluorescent, (1) 60", T-8 lamp, Instant Start Ballast, NLO, Tandem 4 Lamp Ballast F51ILL-R F40T8 Electronic 40 1 Fluorescent, (1) 60", T-8 lamp, Instant Start Ballast, RLO F51SHE F60T12/HO Mag-ES 75 1 Fluorescent, (1) 60", STD HO lamp F51SHL F60T12/HO Electronic 75 1 Fluorescent, (1) 60", STD HO lamp F51SHS F60T12/HO Mag-STD 75 1 Fluorescent, (1) 60", STD HO lamp F51SL F60T12 Electronic 50 1 Fluorescent, (1) 60", STD lamp F51SS F60T12 Mag-STD 50 1 Fluorescent, (1) 60", STD lamp F51SVS F60T12/VHO Mag-STD Fluorescent, (1) 60", VHO ES lamp F52ILL F40T8 Electronic 40 2 Fluorescent, (2) 60", T-8 lamp, Instant Start Ballast, NLO F52ILL/T4 F40T8 Electronic 40 2 Fluorescent, (2) 60", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast F52ILL-H F40T8 Electronic 40 2 Fluorescent, (2) 60", T-8 lamp, Instant Start Ballast, HLO F52ILL-R F40T8 Electronic 40 2 Fluorescent, (2) 60", T-8 lamp, Instant Start Ballast, RLO F52SHE F60T12/HO Mag-ES 75 2 Fluorescent, (2) 60", STD HO lamp F52SHL F60T12/HO Electronic 75 2 Fluorescent, (2) 60", STD HO lamp F52SHS F60T12/HO Mag-STD 75 2 Fluorescent, (2) 60", STD HO lamp F52SL F60T12 Electronic 50 2 Fluorescent, (2) 60", STD lamp F52SS F60T12 Mag-STD 50 2 Fluorescent, (2) 60", STD lamp F52SVS F60T12/VHO Mag-STD Fluorescent, (2) 60", VHO ES lamp kw/ FIXT February 25, 2010 B - 18 Version 1.1

183 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F53ILL F40T8 Electronic 40 3 Fluorescent, (3) 60", T-8 lamp, Instant Start Ballast, NLO F53ILL-H F40T8 Electronic 40 3 Fluorescent, (3) 60", T-8 lamp, Instant Start Ballast, HLO F54ILL F40T8 Electronic 40 4 Fluorescent, (4) 60", T-8 lamp, Instant Start Ballast, NLO F54ILL-H F40T8 Electronic 40 4 Fluorescent, (4) 60", T-8 lamp, Instant Start Ballast, HLO F61ISL F72T12 Electronic 55 1 Fluorescent, (1) 72", STD lamp, IS electronic ballast F61SHS F72T12/HO Mag-STD 85 1 Fluorescent, (1) 72", STD HO lamp F61SS F72T12 Mag-STD 55 1 Fluorescent, (1) 72", STD lamp F61SVS F72T12/VHO Mag-STD Fluorescent, (1) 72", VHO lamp F62ISL F72T12 Electronic 55 2 Fluorescent, (2) 72", STD lamp, IS electronic ballast F62SE F72T12 Mag-ES 55 2 Fluorescent, (2) 72", STD lamp F62SHE F72T12/HO Mag-ES 85 2 Fluorescent, (2) 72", STD HO lamp F62SHS F72T12/HO Mag-STD 85 2 Fluorescent, (2) 72", STD HO lamp F62SL F72T12 Electronic 55 2 Fluorescent, (2) 72", STD lamp F62SS F72T12 Mag-STD 55 2 Fluorescent, (2) 72", STD lamp F62SVS F72T12/VHO Mag-STD Fluorescent, (2) 72", VHO lamp F63ISL F72T12 Electronic 55 3 Fluorescent, (3) 72", STD lamp, IS electronic ballast F63SS F72T12 Mag-STD 55 3 Fluorescent, (3) 72", STD lamp F64ISL F72T12 Electronic 55 4 Fluorescent, (4) 72", STD lamp, IS electronic ballast F64SE F72T12 Mag-ES 55 4 Fluorescent, (4) 72", STD lamp F64SHE F72T12/HO Mag-ES 85 4 Fluorescent, (4) 72", HO lamp F64SS F72T12 Mag-STD 56 4 Fluorescent, (4) 72", STD lamp F81EE/T2 F96T12/ES Mag-ES 60 1 Fluorescent, (1) 96", ES lamp, tandem to 2-lamp ballst F81EHL F96T12/HO/ES Electronic 95 1 Fluorescent, (1) 96", ES HO lamp F81EHS F96T12/HO/ES Mag-STD 95 1 Fluorescent, (1) 96", ES HO lamp F81EL F96T12/ES Electronic 60 1 Fluorescent, (1) 96", ES lamp F81ES F96T12/ES Mag-STD 60 1 Fluorescent, (1) 96", ES lamp F81ES/T2 F96T12/ES Mag-STD 60 1 Fluorescent, (1) 96", ES lamp, tandem to 2-lamp ballast F81EVS F96T12/VHO/ES Mag-STD Fluorescent, (1) 96", ES VHO lamp F81ILL F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, NLO F81ILL/T2 F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, NLO, Tandem 2 Lamp Ballast F81ILL/T2-R F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, RLO, Tandem 2 Lamp Ballast F81ILL-H F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, HLO F81ILL-R F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, RLO F81ILL-V F96T8 Electronic 59 1 Fluorescent, (1) 96", T-8 lamp, Instant Start Ballast, VHLO kw/ FIXT February 25, 2010 B - 19 Version 1.1

184 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION F81LHL/T2 F96T8/HO Electronic 86 1 Fluorescent, (1) 96", T8 HO lamp, tandem wired to 2-lamp ballast F82EE F96T12/ES Mag-ES 60 2 Fluorescent, (2) 96", ES lamp F82EHE F96T12/HO/ES Mag-ES 95 2 Fluorescent, (2) 96", ES HO lamp F82EHL F96T12/HO/ES Electronic 95 2 Fluorescent, (2) 96", ES HO lamp F82EHS F96T12/HO/ES Mag-STD 95 2 Fluorescent, (2) 96", ES HO lamp F82EL F96T12/ES Electronic 60 2 Fluorescent, (2) 96", ES lamp F82ES F96T12/ES Mag-STD 60 2 Fluorescent, (2) 96", ES lamp F82EVS F96T12/VHO/ES Mag-STD Fluorescent, (2) 96", ES VHO lamp F82ILL F96T8 Electronic 59 2 Fluorescent, (2) 96", T-8 lamp, Instant Start Ballast, NLO F82ILL-R F96T8 Electronic 59 2 Fluorescent, (2) 96", T-8 lamp, Instant Start Ballast, RLO F82LHL F96T8/HO Electronic 86 2 Fluorescent, (2) 96", T8 HO lamp F83EE F96T12/ES Mag-ES 60 3 Fluorescent, (3) 96", ES lamp F83EHE F96T12/HO/ES Mag- ES/STD 95 3 Fluorescent, (3) 96", ES HO lamp, (1) 2-lamp ES Ballast, (1) 1-lamp STD Ballast F83EHS F96T12/HO/ES Mag-STD 95 3 Fluorescent, (3) 96", ES HO lamp F83EL F96T12/ES Electronic 60 3 Fluorescent, (3) 96", ES lamp F83ES F96T12/ES Mag-STD 60 3 Fluorescent, (3) 96", ES lamp F83EVS F96T12/VHO/ES Mag-STD Fluorescent, (3) 96", ES VHO lamp F83ILL F96T8 Electronic 59 3 Fluorescent, (3) 96", T-8 lamp, Instant Start Ballast, NLO F84EE F96T12/ES Mag-ES 60 4 Fluorescent, (4) 96", ES lamp F84EHE F96T12/HO/ES Mag-ES 95 4 Fluorescent, (4) 96", ES HO lamp F84EHL F96T12/HO/ES Electronic 95 4 Fluorescent, (4) 96", ES HO lamp F84EHS F96T12/HO/ES Mag-STD 95 4 Fluorescent, (4) 96", ES HO lamp F84EL F96T12/ES Electronic 60 4 Fluorescent, (4) 96", ES lamp F84ES F96T12/ES Mag-STD 60 4 Fluorescent, (4) 96", ES lamp F84EVS F96T12/VHO/ES Mag-STD Fluorescent, (4) 96", ES VHO lamp F84ILL F96T8 Electronic 59 4 Fluorescent, (4) 96", T-8 lamp, Instant Start Ballast, NLO F84LHL F96T8/HO Electronic 86 4 Fluorescent, (4) 96", T8 HO lamp F86EHS F96T12/HO/ES Mag-STD 95 6 Fluorescent, (6) 96", ES HO lamp F86ILL F96T8 Electronic 59 6 Fluorescent, (6) 96", T-8 lamp, Instant Start Ballast, NLO Circline Fluorescent Fixtures FC12/1 FC12T9 Mag-STD 32 1 Fluorescent, (1) 12" circular lamp, RS ballast FC12/2 FC12T9 Mag-STD 32 2 Fluorescent, (2) 12" circular lamp, RS ballast FC16/1 FC16T9 Mag-STD 40 1 Fluorescent, (1) 16" circular lamp FC20 FC6T9 Mag-STD 20 1 Fluorescent, Circlite, (1) 20W lamp, Preheat ballast kw/ FIXT February 25, 2010 B - 20 Version 1.1

185 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION FC22 FC8T9 Mag-STD 22 1 Fluorescent, Circlite, (1) 22W lamp, preheat ballast FC32 FC12T9 Mag-STD 32 1 Fluorescent, Circline, (1) 32W lamp, preheat ballast FC40 FC16T9 Mag-STD 32 1 Fluorescent, Circline, (1) 32W lamp, preheat ballast FC6/1 FC6T9 Mag-STD 20 1 Fluorescent, (1) 6" circular lamp, RS ballast FC8/1 FC8T9 Mag-STD 22 1 Fluorescent, (1) 8" circular lamp, RS ballast FC8/2 FC8T9 Mag-STD 22 2 Fluorescent, (2) 8" circular lamp, RS ballast U-Tube Fluorescent Fixtures FU1EE FU40T12/ES Mag-ES 35 1 Fluorescent, (1) U-Tube, ES lamp FU1ILL FU31T8/6 Electronic 32 1 Fluorescent, (1) U-Tube, T-8 lamp, Instant Start ballast FU1LL FU31T8/6 Electronic 32 1 Fluorescent, (1) U-Tube, T-8 lamp FU1LL-R FU31T8/6 Electronic 31 1 Fluorescent, (1) U-Tube, T-8 lamp, RLO FU2EE FU40T12/ES Mag-ES 35 2 Fluorescent, (2) U-Tube, ES lamp FU2ILL FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Instand Start Ballast FU2ILL/T4 FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Instand Start Ballast, tandem wired FU2ILL/T4-R FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Instand Start Ballast, RLO, tandem wired FU2ILL-H FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Instand Start HLO Ballast FU2ILL-R FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Instand Start RLO Ballast FU2LL FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp FU2LL/T2 FU31T8/6 Electronic 32 2 Fluorescent, (2) U-Tube, T-8 lamp, Tandem 4 lamp ballast FU2LL-R FU31T8/6 Electronic 31 2 Fluorescent, (2) U-Tube, T-8 lamp, RLO FU3EE FU40T12/ES Mag-ES 35 3 Fluorescent, (3) U-Tube, ES lamp FU3ILL FU31T8/6 Electronic 32 3 Fluorescent, (3) U-Tube, T-8 lamp, Instand Start Ballast FU3ILL-R FU31T8/6 Electronic 32 3 Fluorescent, (3) U-Tube, T-8 lamp, Instand Start RLO Ballast Halogen Incandescent Fixtures H42/1 H Halogen Incandescent, (1) 42W lamp H45/1 H Halogen Incandescent, (1) 45W lamp H45/2 H Halogen Incandescent, (2) 45W lamp H50/1 H Halogen Incandescent, (1) 50W lamp HLV50/1 H50/LV 50 1 Halogen, (1) Low Voltage MR16 lamp H50/2 H Halogen Incandescent, (2) 50W lamp H52/1 H Halogen Incandescent, (1) 52W lamp H55/1 H Halogen Incandescent, (1) 55W lamp H55/2 H Halogen Incandescent, (2) 55W lamp kw/ FIXT February 25, 2010 B - 21 Version 1.1

186 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION H60/1 H Halogen Incandescent, (1) 60W lamp H72/1 H Halogen Incandescent, (1) 72W lamp H75/1 H Halogen Incandescent, (1) 75W lamp H75/2 H Halogen Incandescent, (2) 75W lamp H90/1 H Halogen Incandescent, (1) 90W lamp H90/2 H Halogen Incandescent, (2) 90W lamp H100/1 H Halogen Incandescent, (1) 100W lamp H150/1 H Halogen Incandescent, (1) 150W lamp H150/2 H Halogen Incandescent, (2) 150W lamp H300/1 H Halogen Incandescent, (1) 300W lamp H500/1 H Halogen Incandescent, (1) 500W lamp High Pressure Sodium Fixtures HPS35/1 HPS High Pressure Sodium, (1) 35W lamp HPS50/1 HPS High Pressure Sodium, (1) 50W lamp HPS70/1 HPS High Pressure Sodium, (1) 70W lamp HPS100/1 HPS High Pressure Sodium, (1) 100W lamp HPS150/1 HPS High Pressure Sodium, (1) 150W lamp HPS200/1 HPS High Pressure Sodium, (1) 200W lamp HPS250/1 HPS High Pressure Sodium, (1) 250W lamp HPS310/1 HPS High Pressure Sodium, (1) 310W lamp HPS360/1 HPS High Pressure Sodium, (1) 360W lamp HPS400/1 HPS High Pressure Sodium, (1) 400W lamp HPS1000/1 HPS High Pressure Sodium, (1) 1000W lamp Standard Incandescent Fixtures I7.5/1 I Tungsten exit light, (1) 7.5 W lamp, used in night light application I7.5/2 I Tungsten exit light, (2) 7.5 W lamp, used in night light application I15/1 I Incandescent, (1) 15W lamp I15/2 I Incandescent, (2) 15W lamp I20/1 I Incandescent, (1) 20W lamp I20/2 I Incandescent, (2) 20W lamp I25/1 I Incandescent, (1) 25W lamp I25/2 I Incandescent, (2) 25W lamp I25/4 I Incandescent, (4) 25W lamp I34/1 I Incandescent, (1) 34W lamp kw/ FIXT February 25, 2010 B - 22 Version 1.1

187 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION I40E/1 I40/ES 34 1 Incandescent, (1) 40W ES lamp I40EL/1 I40/ES/LL 34 1 Incandescent, (1) 40W ES/LL lamp I34/2 I Incandescent, (2) 34W lamp I36/1 I Incandescent, (1) 36W lamp I40/1 I Incandescent, (1) 40W lamp I40/2 I Incandescent, (2) 40W lamp I42/1 I Incandescent, (1) 42W lamp I45/1 I Incandescent, (1) 45W lamp I50/1 I Incandescent, (1) 50W lamp I50/2 I Incandescent, (2) 50W lamp I52/1 I Incandescent, (1) 52W lamp I60E/1 I60/ES 52 1 Incandescent, (1) 60W ES lamp I60EL/1 I60/ES/LL 52 1 Incandescent, (1) 60W ES/LL lamp I52/2 I Incandescent, (2) 52W lamp I54/1 I Incandescent, (1) 54W lamp I54/2 I Incandescent, (2) 54W lamp I55/1 I Incandescent, (1) 55W lamp I55/2 I Incandescent, (2) 55W lamp I60/1 I Incandescent, (1) 60W lamp I60/2 I Incandescent, (2) 60W lamp I60/3 I Incandescent, (3) 60W lamp I60/4 I Incandescent, (4) 60W lamp I60/5 I Incandescent, (5) 60W lamp I65/1 I Incandescent, (1) 65W lamp I65/1 I Incandescent, (1) 65W lamp I65/2 I Incandescent, (2) 65W lamp I67/1 I Incandescent, (1) 67W lamp I75E/1 I75/ES 67 1 Incandescent, (1) 75W ES lamp I75EL/1 I75/ES/LL 67 1 Incandescent, (1) 75W ES/LL lamp I67/2 I Incandescent, (2) 67W lamp I67/3 I Incandescent, (3) 67W lamp I69/1 I Incandescent, (1) 69W lamp I72/1 I Incandescent, (1) 72W lamp I75/1 I Incandescent, (1) 75W lamp I75/2 I Incandescent, (2) 75W lamp kw/ FIXT February 25, 2010 B - 23 Version 1.1

188 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION I75/3 I Incandescent, (3) 75W lamp I75/4 I Incandescent, (4) 75W lamp I80/1 I Incandescent, (1) 80W lamp I85/1 I Incandescent, (1) 85W lamp I100E/1 I100/ES 90 1 Incandescent, (1) 100W ES lamp I100EL/1 I100/ES/LL 90 1 Incandescent, (1) 100W ES/LL lamp I90/1 I Incandescent, (1) 90W lamp I90/2 I Incandescent, (2) 90W lamp I90/3 I Incandescent, (3) 90W lamp I93/1 I Incandescent, (1) 93W lamp I95/1 I Incandescent, (1) 95W lamp I95/2 I Incandescent, (2) 95W lamps I100/1 I Incandescent, (1) 100W lamp I100/2 I Incandescent, (2) 100W lamp I100/3 I Incandescent, (3) 100W lamp I100/4 I Incandescent, (4) 100W lamp I100/5 I Incandescent, (5) 100W lamp I120/1 I Incandescent, (1) 120W lamp I120/2 I Incandescent, (2) 120W lamp I125/1 I Incandescent, (1) 125W lamp I135/1 I Incandescent, (1) 135W lamp I150E/1 I150/ES Incandescent, (1) 150W ES lamp I150EL/1 I150/ES/LL Incandescent, (1) 150W ES/LL lamp I135/2 I Incandescent, (2) 135W lamp I150/1 I Incandescent, (1) 150W lamp I150/2 I Incandescent, (2) 150W lamp I170/1 I Incandescent, (1) 170W lamp I200/1 I Incandescent, (1) 200W lamp I200L/1 I200/LL Incandescent, (1) 200W LL lamp I200/2 I Incandescent, (2) 200W lamp I250/1 I Incandescent, (1) 250W lamp I300/1 I Incandescent, (1) 300W lamp I400/1 I Incandescent, (1) 400W lamp I448/1 I Incandescent, (1) 448W lamp I500/1 I Incandescent, (1) 500W lamp kw/ FIXT February 25, 2010 B - 24 Version 1.1

189 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION I750/1 I Incandescent, (1) 750W lamp I1000/1 I Incandescent, (1) 1000W lamp I1500/1 I Incandescent, (1) 1500W lamp I2000/1 I Incandescent, (1) 2000W lamp kw/ FIXT Pulse Start Metal Halide Fixtures MH175PS/1 MH175PS Mag-CWA Pulse Start Metal Halide, (1) 175W lamp, Pulse Start CWA Ballast MH200PS/1 MH200PS Mag-CWA Pulse Start Metal Halide, (1) 200W lamp, Pulse Start CWA Ballast MH250PS/1 MH250PS Mag-CWA Pulse Start Metal Halide, (1) 250W lamp, Pulse Start CWA Ballast MH320PS/1 MH320PS Mag-CWA Pulse Start Metal Halide, (1) 320W lamp, Pulse Start CWA Ballast MH350PS/1 MH350PS Mag-CWA Pulse Start Metal Halide, (1) 350W lamp, Pulse Start CWA Ballast MH400PS/1 MH400PS Mag-CWA Pulse Start Metal Halide, (1) 400W lamp, Pulse Start CWA Ballast MH450PS/1 MH450PS Mag-CWA Pulse Start Metal Halide, (1) 450W lamp, Pulse Start CWA Ballast MH750PS/1 MH750PS Mag-CWA Pulse Start Metal Halide, (1) 750W lamp, Pulse Start CWA Ballast MH1000PS/1 MH1000PS Mag-CWA Pulse Start Metal Halide, (1) 1000W lamp, Pulse Start CWA Ballast Metal Halide Fixtures MH32/1 MH Metal Halide, (1) 32W lamp MH50/1 MH Metal Halide, (1) 50W lamp MH70/1 MH Metal Halide, (1) 70W lamp MH100/1 MH Metal Halide, (1) 100W lamp MH150/1 MH Metal Halide, (1) 150W lamp MH175/1 MH Metal Halide, (1) 175W lamp MH250/1 MH Metal Halide, (1) 250W lamp MH400/1 MH Metal Halide, (1) 400W lamp MH400/2 MH Metal Halide, (2) 400W lamp MH750/1 MH Metal Halide, (1) 750W lamp MH1000/1 MH Metal Halide, (1) 1000W lamp MH1500/1 MH Metal Halide, (1) 1500W lamp Mercury Vapor Fixtures MV40/1 MV Mercury Vapor, (1) 40W lamp MV50/1 MV Mercury Vapor, (1) 50W lamp MV75/1 MV Mercury Vapor, (1) 75W lamp MV100/1 MV Mercury Vapor, (1) 100W lamp February 25, 2010 B - 25 Version 1.1

190 FIXTURE CODE LAMP CODE BALLAST TYPE NOM. W/LAMP LAMP/ FIXT DESCRIPTION MV175/1 MV Mercury Vapor, (1) 175W lamp MV250/1 MV Mercury Vapor, (1) 250W lamp MV400/1 MV Mercury Vapor, (1) 400W lamp MV400/2 MV Mercury Vapor, (2) 400W lamp MV700/1 MV Mercury Vapor, (1) 700W lamp MV1000/1 MV Mercury Vapor, (1) 1000W lamp EXIT Sign Fixtures ECF5/1 CFT5W Mag-STD 5 1 EXIT Compact Fluorescent, (1) 5W lamp ECF5/2 CFT5W Mag-STD 5 2 EXIT Compact Fluorescent, (2) 5W lamp ECF7/1 CFT7W Mag-STD 7 1 EXIT Compact Fluorescent, (1) 7W lamp ECF7/2 CFT7W Mag-STD 7 2 EXIT Compact Fluorescent, (2) 7W lamp ECF8/1 F8T5 Mag-STD 8 1 EXIT T5 Fluorescent, (1) 8W lamp ECF8/2 F8T5 Mag-STD 8 2 EXIT T5 Fluorescent, (2) 8W lamp ECF9/1 CFT9W Mag-STD 9 1 EXIT Compact Fluorescent, (1) 9W lamp ECF9/2 CFT9W Mag-STD 9 2 EXIT Compact Fluorescent, (2) 9W lamp EI10/2 I EXIT Incandescent, (2) 10W lamp EI15/1 I EXIT Incandescent, (1) 15W lamp EI15/2 I EXIT Incandescent, (2) 15W lamp EI20/1 I EXIT Incandescent, (1) 20W lamp EI20/2 I EXIT Incandescent, (2) 20W lamp EI25/1 I EXIT Incandescent, (1) 25W lamp EI25/2 I EXIT Incandescent, (2) 25W lamp EI34/1 I EXIT Incandescent, (1) 34W lamp EI34/2 I EXIT Incandescent, (2) 34W lamp EI40/1 I EXIT Incandescent, (1) 40W lamp EI40/2 I EXIT Incandescent, (2) 40W lamp EI5/1 I5 5 1 EXIT Incandescent, (1) 5W lamp EI5/2 I5 5 2 EXIT Incandescent, (2) 5W lamp EI50/2 I EXIT Incandescent, (2) 50W lamp EI7.5/1 I EXIT Tungsten, (1) 7.5 W lamp EI7.5/2 I EXIT Tungsten, (2) 7.5 W lamp ELED2/1 LED2W 2 1 EXIT Light Emmitting Diode, (1) 2W lamp, Single Sided ELED2/2 LED2W 2 2 EXIT Light Emmitting Diode, (2) 2W lamp, Dual Sided kw/ FIXT February 25, 2010 B - 26 Version 1.1

191 Fixture Code Legend Revised: 6/24/2002 Sample Linear Fluorescent Fixture Code: Sample of Other Fixture Code: NUMBER OF LAMPS FIXTURE TYPE Fluorescent CONFIGURATION [letter] Tandem Wired CONFIGURATION [number] 4 lamps on this ballast FIXTURE TYPE Compact Fluorescent, Quad tube NUMBER OF LAMPS 1 Lamp Fixture F 4 1 I L L / T 4 - R CFQ18/1-L LAMP LENGTH 4 feet LAMP TYPE Instant start, T8 BALLAST TYPE Electronic ballast BALLAST LIGHT OUTPUT Reduced light output NOMINAL LAMP WATTAGE 18 W BALLAST TYPE electronic ballast February 25, 2010 B - 27 Version 1.1

192 Fixture Type CF Compact Fluorescent CFD Compact Fluorescent, double-d shape CFM Compact Fluorescent, Multi tube CFT Compact Fluorescent, Twin tube (including Biaxial fixtures) CFQ Compact Fluorescent, Quad tube ECF Exit sign, Compact Fluorescent EI Exit sign, Incandescent ELED Exit sign, LED F Fluorescent, linear FC Fluorescent, Circline FU Fluorescent, U-tube H Halogen Incandescent HPS High Pressure Sodium I Incandescent MH Metal Halide MV Mercury Vapor Lamp Type for fluorescent fixtures A F25T12 type 25 watt, 4 ft, T12 lamp B T4, Instant Start IL T8, Instant start L T8, rapid start E T12, Energy efficient EH T12, Energy efficient, High output EV T12, Energy efficient, Very high output P T5, Instant Start PH T5HO, Instant Start S T12, Standard wattage SH T12, Standard, High output lamp SV T12, Standard, Very high output lamp T T10 lamp WL T8, Instant start, Energy saver Ballast Type for fluorescent fixtures L electronic S Standard magnetic E Energy efficient magnetic Configuration [letter] T Tandem wired fixture D Delamped fixture, i.e. some lamps Permanently removed but ballasts remain Configuration [number] for de-lamped fixtures Number signifies the total number of ballasts in the fixture: e.g. An F42EE/D2 is an F44EE with two lamps removed so that there is one extraneous ballast. for tandem wired ballasts Number signifies the total number of lamps being run by the ballast: e.g. An F42LL/T4 would indicate that a four-lamp ballast is wired to run two two-lamp fixtures. with no preceding letter Number indicates the number of ballasts in an ambiguous multiple ballast fixture: e.g. An F43ILL/2 indicates a three-lamp fixture with two ballasts (as is often the case if there is A/B switching). Ballast Light Output R Reduced light output H High light output V Very high light output February 25, 2010 B - 28 Version 1.1

193 Other Abbreviations BF = Ballast Factor RLO = Reduced Light Output Ballast (<.85 Ballast Factor) NLO = Normal Light Output Ballast (.85 to.95 Ballast Factor) HLO = High Light Output Ballast (.96 to 1.1 Ballast Factor) VHLO = Very High Light Output Ballast (> 1.1 Ballast Factor) Mag-ES = Magnetic, Energy Saving Ballast Elec-Prem = Premium Electronic Ballast. Characterized by reduced input wattage compared to standard mod with no reduction in light output. Also known as 3rd Generation. Elec-Prem-R = Same as Elec-Prem but with RLO Ballast Factor. CRI = Color Rendering Index ISR = Instant Start Rating at 3 Hours per Start RSR = Rapid Start Rating at 3 Hours per Start F32T8-STD = 70 to 84 CRI, 20,000 Hour RSR Lamp F32T8-PREM = 85 or Greater CRI, 24,000 Hour RSR Lamp F32T8-PREM-ES = Energy Saving T8 Lamp, 30 Watt Nominal, 82 or Greater CRI, 15,000 Hour ISR Lamp PS=Pulse Start Metal Halide kw = kilowatts W = Watts (G1) = 1st Generation T8 Lighting, as Defined in R , ALJ Thomas Draft Decision of 2/19/02 (G2) = 2nd Generation T8 Lighting, as Defined in R , ALJ Thomas Draft Decision of 2/19/02 (G3) = 3rd Generation T8 Lighting, as Defined in R , ALJ Thomas Draft Decision of 2/19/02 Note: 1) The column labeled kw/fixt in the data table includes ballast loads. 2) The kw/fixt values represent an average value, rounded to the nearest whole watt. 3) The nominal watts per lamp are for reference only. February 25, 2010 B - 29 Version 1.1

194 Appendix B: Sample Lighting Table February 25, 2010 B - 30 Version 1.1

195 Appendix C Minimum Equipment Efficiency Standards

196 Appendix C: Minimum Equipment Efficiency Standards This Appendix is an overview of building and equipment standards in the State of California that have an effect on the baselines used in calculating savings and determining the eligibility of proposed equipment for the Statewide Customized Offering. It contains the minimum equipment efficiency standards that a Project Sponsor must use to establish baseline system models and estimate energy savings for projects that involve the replacement of motors, air compressors, gas furnaces, gas boilers, and cooling equipment. It also describes the minimum standards for T-8 and T-5 linear fluorescent retrofit equipment. The equipment baselines are based on multiple industry and governmental standards. These include California s Title 24 minimum equipment efficiency standards, NEMA standards, EPACT regulations, DOE s Motor Challenge (Motor Master), and DOE s Air Compressor Challenge (AirMaster+). Some applicable tables have been reproduced or summarized in this section for convenience. Please note that the most current standards take precedence. Savings from equipment not covered by the standards mentioned above shall be calculated by using the existing equipment as a baseline. The document 2005 Title 24, Part 6, California s Energy Efficiency Standards for Residential and Non-residential Buildings can be downloaded from the following Internet address: Information concerning the Motor Challenge and Air Compressor Challenge can be found at the following Internet address: February 25, 2010 C - 1 Version 1.1

197 C.1 Electrical Motors The efficiencies of permanently wired, poly-phase motors that are at least one horsepower in size and that are used for fan, pumping, and conveyance applications, are defined in Table C.1, which is based on California s Title 24 and the National Electric Manufacturers Association s (NEMA) Table The efficiency values given in Table C.1 should be used to determine the baseline motor energy consumption. Motors installed under the Statewide Customized Offering must be more efficient than the standards shown in order to be eligible for Offering incentives. Table 1: Minimum Nominal Full-Load Motor Efficiency for Single Speed Poly-Phase Motors Number of Poles Synchronous Speed Motor HP Open Motors Enclosed February 25, 2010 C - 2 Version 1.1

198 C.2 Cooling, Heating and Air Conditioning Equipment For the following types of equipment, baseline efficiency ratings are provided in Tables 1 through Table 3 below. Air- cooled unitary air conditioners Water-cooled and evaporative-cooled unitary air conditioners Unitary air-cooled heat pumps Air-cooled and water-cooled condensing units Water-cooled and air-cooled water chilling packages Gas furnaces and boilers The tables are based on California s Title 24 minimum equipment efficiency standards. Choose the appropriate baseline cooling equipment model for each Project Site. The efficiency standards in these tables should be used to determine the equipment baseline. All heating and cooling equipment that will be installed under the Statewide Customized Offering must be more efficient than the standard in order to be eligible for Offering incentives. Please note the efficiency standards in Table C2 below are expressed in terms of Energy Efficiency Ratio (EER) or Coefficient of Performance (COP). However, manufacturer efficiency ratings are sometimes expressed as Seasonal Efficiency Ratio (SEER) or kw/ton Ratio. Some useful conversion factors are: 1 ton = 12,000 Btu/hr; COP = EER / 3.412; COP = / (kw/ton); Please consult manufacturer for SEER to EER conversion. For water-source, ground-water source, and ground source heat pumps, as well as all other equipment not specifically mentioned in the tables below, please check the standards in 2005 Title 24, Part 6, California s Energy Efficiency Standards for Residential and Non-residential Buildings found at: February 25, 2010 C - 3 Version 1.1

199 Table C1 ELECTRICALLY OPERTED UNITARY AIR CONDITIONERS AND CONDENSING UNITS MINIMUM EFFICIENCY REQUIREMENTS (TABLE 112-A) Table C2 UNITARY AND APPLIED HEAT PUMPS, MINIMUM EFFICIENCY REQUIREMENTS (TABLE 112-B) February 25, 2010 C - 4 Version 1.1

200 Table C3 AIR-COOLED GAS-ENGINE HEAT PUMPS (TABLE 112-C) Table C-4 WATER CHILLING PACKAGES MINIMUM EFFICIENCY REQUIREMENTS (TABLE 112-D) February 25, 2010 C - 5 Version 1.1

201 Table C-5 PACKAGED TERMINAL AIR CONDITIONERS AND PACKAGED TERMINAL HEAT PUMPS MINIMUM EFFICIENCY REQUIREMENTS (TABLE 112-E) February 25, 2010 C - 6 Version 1.1

202 Table C-6 Standards for Gas- and Oil-Fired Central Boilers and Electric Residential Boilers February 25, 2010 C - 7 Version 1.1

203 Table C-7 PERFORMANCE REQUIREMENTS FOR HEAT REJECTION EQUIPMENT (TABLE 112-G) February 25, 2010 C - 8 Version 1.1

204 Table C-8 COPS FOR NON-STANDARD CENTRIFUGAL CHILLERS < 150 TONS (TABLE 112-H) February 25, 2010 C - 9 Version 1.1

205 Table C-9 COPS FOR NON-STANDARD CENTRIFUGAL CHILLERS > 150 TONS, 300 TONS (TABLE 112-I) February 25, 2010 C - 10 Version 1.1

206 Table C-10 COPS FOR NON-STANDARD CENTRIFUGAL CHILLERS > 300 TONS (TABLE 112-J) February 25, 2010 C - 11 Version 1.1

207 Table C-11 IPLV/NPLV FOR NON-STANDARD CENTRIFUGAL CHILLERS < 150 TONS (TABLE 112-K) February 25, 2010 C - 12 Version 1.1

208 Table C-12 IPLV/NPLV FOR NON-STANDARD CENTRIFUGAL CHILLERS > 150 TONS, < 300 TONS (TABLE 112-L) February 25, 2010 C - 13 Version 1.1

209 Table C-13 IPLV/NPLV FOR NON-STANDARD CENTRIFUGAL CHILLERS > 300 TONS (TABLE 112-M) February 25, 2010 C - 14 Version 1.1

210 C.3 Chiller Performance Curves and Characteristics Chiller performance as a function of load, condenser water temperature and flow are legitimate design parameters for which the standard should provide both credit and penalty. Owners, manufacturer s sales representatives and design professionals spend significant time, money and effort to match a machine s performance to the characteristics of a specific plant. This is as legitimate a trade-off as any presently provided in the Performance Method. California Energy Commission published a new set of seven default curves representing four compressor types and two condenser conditions. These curves were developed under the scrutiny of the public review process and with the cooperation of both ARI and the major manufacturers. These curves are based on recent technology (circa 1993). These curves have been adopted for use in modeling baseline chiller operation for the Statewide Customized Offering. Table 1: Default Capacity Coefficients - Electric Air-Cooled Chillers Coefficient Scroll Recip Screw Centrifugal a N/A b N/A c N/A d N/A e N/A f N/A Table 2: Default Capacity Coefficients - Electric Water-Cooled Chillers Coefficient Scroll Recip Screw Centrifugal a b c d e f Table 3: Default Efficiency EIR-FT Coefficients - Air-Cooled Chillers Coefficient Scroll Reciprocating Screw Centrifugal a N/A b N/A c N/A d N/A e N/A f N/A February 25, 2010 C - 15 Version 1.1

211 Table 4: Default Efficiency EIR-FT Coefficients - Water-Cooled Chillers Coefficient Scroll Reciprocating Screw Centrifugal a b c d e f Table 5: Default Efficiency EIR-FPLR Coefficients - Air-Cooled Chillers Coefficient Scroll Recip Screw Centrifugal a N/A b N/A c N/A Table 6: Default Efficiency EIR-FPLR Coefficients - Water-Cooled Chillers Coefficient Scroll Recip Screw Centrifugal a b c Table 7: Minimum Unloading Ratios for Electric Chillers Chiller Type Default Unloading Ratio Reciprocating 25% Screw 15% Centrifugal 10% Scroll 25% February 25, 2010 C - 16 Version 1.1

212 C.4 Air Compressor Equipment AirMaster+ is an industry standard tool, developed out of the DOE s Compressed Air Challenge effort, designed to assist the end user in improving the performance of compressed air systems. As a part of the AirMaster+ development, industry data was gathered to create generic or typical air compressor units. The Statewide Customized Offering uses these generic energy profiles to specify the allowable baseline energy usage for individual compressors. Rated pressure is psig, rated capacity is acfm, and package power is kw/100 cfm. Table 2: Minimum Efficiency Ratings for Rotary Screw and Reciprocating Air Compressor Units. Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 5 Inlet modulation w/ unloading single stage lub-injected rotary screw 5 Inlet modulation w/ unloading single stage lub-injected rotary screw 5 Inlet modulation w/ unloading single stage lub-injected rotary screw 5 Inlet modulation w/o unloading single stage lub-injected rotary screw 5 Inlet modulation w/o unloading single stage lub-injected rotary screw 5 Inlet modulation w/o unloading single stage lub-injected rotary screw 5 Load/unload single stage lub-injected rotary screw 5 Load/unload single stage lub-injected rotary screw 5 Load/unload single stage lub-injected rotary screw 5 Variable displacement single stage lub-injected rotary screw 5 Variable displacement single stage lub-injected rotary screw 5 Variable displacement single stage lub-injected rotary screw 7.5 Inlet modulation w/ unloading single stage lub-injected rotary screw 7.5 Inlet modulation w/ unloading single stage lub-injected rotary screw 7.5 Inlet modulation w/ unloading single stage lub-injected rotary screw 7.5 Inlet modulation w/o unloading single stage lub-injected rotary screw 7.5 Inlet modulation w/o unloading single stage lub-injected rotary screw 7.5 Inlet modulation w/o unloading single stage lub-injected rotary screw 7.5 Load/unload single stage lub-injected rotary screw 7.5 Load/unload single stage lub-injected rotary screw 7.5 Load/unload single stage lub-injected rotary screw 7.5 Variable displacement single stage lub-injected rotary screw 7.5 Variable displacement single stage lub-injected rotary screw 7.5 Variable displacement single stage lub-injected rotary screw 10 Inlet modulation w/ unloading single stage lub-injected rotary screw 10 Inlet modulation w/ unloading single stage lub-injected rotary screw 10 Inlet modulation w/ unloading February 25, 2010 C - 17 Version 1.1

213 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 10 Inlet modulation w/ unloading single stage lub-injected rotary screw 10 Inlet modulation w/o unloading single stage lub-injected rotary screw 10 Inlet modulation w/o unloading single stage lub-injected rotary screw 10 Inlet modulation w/o unloading single stage lub-injected rotary screw 10 Inlet modulation w/o unloading single stage lub-injected rotary screw 10 Load/unload single stage lub-injected rotary screw 10 Load/unload single stage lub-injected rotary screw 10 Load/unload single stage lub-injected rotary screw 10 Load/unload single stage lub-injected rotary screw 10 Variable displacement single stage lub-injected rotary screw 10 Variable displacement single stage lub-injected rotary screw 10 Variable displacement single stage lub-injected rotary screw 10 Variable displacement single stage lub-injected rotary screw 15 Inlet modulation w/ unloading single stage lub-injected rotary screw 15 Inlet modulation w/ unloading single stage lub-injected rotary screw 15 Inlet modulation w/ unloading single stage lub-injected rotary screw 15 Inlet modulation w/ unloading single stage lub-injected rotary screw 15 Inlet modulation w/o unloading single stage lub-injected rotary screw 15 Inlet modulation w/o unloading single stage lub-injected rotary screw 15 Inlet modulation w/o unloading single stage lub-injected rotary screw 15 Inlet modulation w/o unloading single stage lub-injected rotary screw 15 Load/unload single stage lub-injected rotary screw 15 Load/unload single stage lub-injected rotary screw 15 Load/unload single stage lub-injected rotary screw 15 Load/unload single stage lub-injected rotary screw 15 Variable displacement single stage lub-injected rotary screw 15 Variable displacement single stage lub-injected rotary screw 15 Variable displacement single stage lub-injected rotary screw 15 Variable displacement single stage lub-injected rotary screw 20 Inlet modulation w/ unloading single stage lub-injected rotary screw 20 Inlet modulation w/ unloading single stage lub-injected rotary screw 20 Inlet modulation w/ unloading single stage lub-injected rotary screw 20 Inlet modulation w/ unloading single stage lub-injected rotary screw 20 Inlet modulation w/o unloading single stage lub-injected rotary screw 20 Inlet modulation w/o unloading single stage lub-injected rotary screw 20 Inlet modulation w/o unloading February 25, 2010 C - 18 Version 1.1

214 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 20 Inlet modulation w/o unloading single stage lub-injected rotary screw 20 Load/unload single stage lub-injected rotary screw 20 Load/unload single stage lub-injected rotary screw 20 Load/unload single stage lub-injected rotary screw 20 Load/unload single stage lub-injected rotary screw 20 Variable displacement single stage lub-injected rotary screw 20 Variable displacement single stage lub-injected rotary screw 20 Variable displacement single stage lub-injected rotary screw 20 Variable displacement single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/ unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Inlet modulation w/o unloading single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Load/unload single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 25 Variable displacement February 25, 2010 C - 19 Version 1.1

215 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 25 Variable displacement single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/ unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Inlet modulation w/o unloading single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Load/unload single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 30 Variable displacement single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading single stage lub-injected rotary screw 40 Inlet modulation w/ unloading February 25, 2010 C - 20 Version 1.1

216 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Inlet modulation w/o unloading single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Load/unload single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 40 Variable displacement single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/ unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Inlet modulation w/o unloading February 25, 2010 C - 21 Version 1.1

217 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 50 Inlet modulation w/o unloading single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Load/unload single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 50 Variable displacement single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/ unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Inlet modulation w/o unloading single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Load/unload single stage lub-injected rotary screw 60 Variable displacement February 25, 2010 C - 22 Version 1.1

218 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 60 Variable displacement single stage lub-injected rotary screw 60 Variable displacement single stage lub-injected rotary screw 60 Variable displacement single stage lub-injected rotary screw 60 Variable displacement single stage lub-injected rotary screw 60 Variable displacement single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/ unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Inlet modulation w/o unloading single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Load/unload single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 75 Variable displacement February 25, 2010 C - 23 Version 1.1

219 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 75 Variable displacement single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/ unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Inlet modulation w/o unloading single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Load/unload single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 100 Variable displacement single stage lub-injected rotary screw 125 Inlet modulation w/ unloading February 25, 2010 C - 24 Version 1.1

220 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/ unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Inlet modulation w/o unloading single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Load/unload single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 125 Variable displacement single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading February 25, 2010 C - 25 Version 1.1

221 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/ unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Inlet modulation w/o unloading single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Load/unload single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 150 Variable displacement single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading February 25, 2010 C - 26 Version 1.1

222 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/ unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Inlet modulation w/o unloading single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Load/unload single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 200 Variable displacement single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/ unloading February 25, 2010 C - 27 Version 1.1

223 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 250 Inlet modulation w/ unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Inlet modulation w/o unloading single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Load/unload single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 250 Variable displacement single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/ unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading February 25, 2010 C - 28 Version 1.1

224 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Inlet modulation w/o unloading single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Load/unload single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 300 Variable displacement single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/ unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Inlet modulation w/o unloading single stage lub-injected rotary screw 350 Load/unload single stage lub-injected rotary screw 350 Load/unload single stage lub-injected rotary screw 350 Load/unload single stage lub-injected rotary screw 350 Load/unload February 25, 2010 C - 29 Version 1.1

225 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 350 Load/unload single stage lub-injected rotary screw 350 Load/unload single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 350 Variable displacement single stage lub-injected rotary screw 400 Inlet modulation w/ unloading single stage lub-injected rotary screw 400 Inlet modulation w/ unloading single stage lub-injected rotary screw 400 Inlet modulation w/ unloading single stage lub-injected rotary screw 400 Inlet modulation w/ unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Inlet modulation w/o unloading single stage lub-injected rotary screw 400 Load/unload single stage lub-injected rotary screw 400 Load/unload single stage lub-injected rotary screw 400 Load/unload single stage lub-injected rotary screw 400 Load/unload single stage lub-injected rotary screw 400 Variable displacement single stage lub-injected rotary screw 400 Variable displacement single stage lub-injected rotary screw 400 Variable displacement single stage lub-injected rotary screw 400 Variable displacement single stage lub-injected rotary screw 450 Inlet modulation w/ unloading single stage lub-injected rotary screw 450 Inlet modulation w/ unloading single stage lub-injected rotary screw 450 Inlet modulation w/ unloading single stage lub-injected rotary screw 450 Inlet modulation w/ unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading February 25, 2010 C - 30 Version 1.1

226 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Inlet modulation w/o unloading single stage lub-injected rotary screw 450 Load/unload single stage lub-injected rotary screw 450 Load/unload single stage lub-injected rotary screw 450 Load/unload single stage lub-injected rotary screw 450 Load/unload single stage lub-injected rotary screw 450 Variable displacement single stage lub-injected rotary screw 450 Variable displacement single stage lub-injected rotary screw 450 Variable displacement single stage lub-injected rotary screw 450 Variable displacement single stage lub-injected rotary screw 500 Inlet modulation w/ unloading single stage lub-injected rotary screw 500 Inlet modulation w/ unloading single stage lub-injected rotary screw 500 Inlet modulation w/ unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Inlet modulation w/o unloading single stage lub-injected rotary screw 500 Load/unload single stage lub-injected rotary screw 500 Load/unload single stage lub-injected rotary screw 500 Load/unload single stage lub-injected rotary screw 500 Variable displacement single stage lub-injected rotary screw 500 Variable displacement single stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/ unloading February 25, 2010 C - 31 Version 1.1

227 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 100 Inlet modulation w/ unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Inlet modulation w/o unloading two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Load/unload two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 100 Variable displacement two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/ unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading February 25, 2010 C - 32 Version 1.1

228 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Inlet modulation w/o unloading two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Load/unload two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 125 Variable displacement two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/ unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Inlet modulation w/o unloading February 25, 2010 C - 33 Version 1.1

229 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 150 Inlet modulation w/o unloading two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Load/unload two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 150 Variable displacement two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/ unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Inlet modulation w/o unloading two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload February 25, 2010 C - 34 Version 1.1

230 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Load/unload two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 200 Variable displacement two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/ unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Inlet modulation w/o unloading two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload two stage lub-injected rotary screw 250 Load/unload February 25, 2010 C - 35 Version 1.1

231 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 250 Variable displacement two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/ unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Inlet modulation w/o unloading two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Load/unload two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement February 25, 2010 C - 36 Version 1.1

232 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 300 Variable displacement two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/ unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Inlet modulation w/o unloading two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Load/unload two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 350 Variable displacement two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading February 25, 2010 C - 37 Version 1.1

233 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/ unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Inlet modulation w/o unloading two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Load/unload two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 400 Variable displacement two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/ unloading February 25, 2010 C - 38 Version 1.1

234 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 450 Inlet modulation w/ unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Inlet modulation w/o unloading two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Load/unload two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 450 Variable displacement two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/ unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading February 25, 2010 C - 39 Version 1.1

235 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Inlet modulation w/o unloading two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Load/unload two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 500 Variable displacement two stage lub-injected rotary screw 600 Inlet modulation w/ unloading two stage lub-injected rotary screw 600 Inlet modulation w/o unloading two stage lub-injected rotary screw 600 Load/unload two stage lub-injected rotary screw 600 Variable displacement two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 50 Load/unload two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 60 Load/unload February 25, 2010 C - 40 Version 1.1

236 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-free rotary screw 60 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 75 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 100 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 125 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 150 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload two stage lub-free rotary screw 200 Load/unload February 25, 2010 C - 41 Version 1.1

237 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 250 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 300 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 350 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 400 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 450 Load/unload two stage lub-free rotary screw 500 Load/unload two stage lub-free rotary screw 500 Load/unload February 25, 2010 C - 42 Version 1.1

238 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage lub-free rotary screw 500 Load/unload two stage lub-free rotary screw 500 Load/unload two stage lub-free rotary screw 500 Load/unload two stage lub-free rotary screw 500 Load/unload two stage lub-free rotary screw 500 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 7.5 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 10 Load/unload February 25, 2010 C - 43 Version 1.1

239 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage recip 10 Load/unload single stage recip 10 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 15 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 20 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 25 Load/unload single stage recip 30 Load/unload February 25, 2010 C - 44 Version 1.1

240 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 30 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 40 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 50 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload February 25, 2010 C - 45 Version 1.1

241 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 60 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 75 Load/unload single stage recip 100 Load/unload single stage recip 100 Load/unload single stage recip 100 Load/unload single stage recip 100 Load/unload single stage recip 125 Load/unload single stage recip 125 Load/unload single stage recip 125 Load/unload single stage recip 150 Load/unload single stage recip 150 Load/unload single stage recip 150 Load/unload single stage recip 200 Load/unload single stage recip 200 Load/unload single stage recip 200 Load/unload single stage recip 200 Load/unload single stage recip 250 Load/unload single stage recip 250 Load/unload single stage recip 250 Load/unload single stage recip 250 Load/unload February 25, 2010 C - 46 Version 1.1

242 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) single stage recip 300 Load/unload single stage recip 300 Load/unload single stage recip 300 Load/unload single stage recip 300 Load/unload single stage recip 350 Load/unload single stage recip 350 Load/unload single stage recip 350 Load/unload single stage recip 350 Load/unload two stage recip 5 Load/unload two stage recip 5 Load/unload two stage recip 5 Load/unload two stage recip 5 Load/unload two stage recip 5 Load/unload two stage recip 5 Load/unload two stage recip 7.5 Load/unload two stage recip 7.5 Load/unload two stage recip 7.5 Load/unload two stage recip 7.5 Load/unload two stage recip 7.5 Load/unload two stage recip 7.5 Load/unload two stage recip 10 Load/unload two stage recip 10 Load/unload two stage recip 10 Load/unload two stage recip 10 Load/unload two stage recip 10 Load/unload two stage recip 10 Load/unload two stage recip 15 Load/unload two stage recip 15 Load/unload two stage recip 15 Load/unload two stage recip 15 Load/unload two stage recip 15 Load/unload two stage recip 15 Load/unload two stage recip 20 Load/unload two stage recip 20 Load/unload two stage recip 20 Load/unload two stage recip 20 Load/unload February 25, 2010 C - 47 Version 1.1

243 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage recip 20 Load/unload two stage recip 20 Load/unload two stage recip 25 Load/unload two stage recip 25 Load/unload two stage recip 25 Load/unload two stage recip 25 Load/unload two stage recip 25 Load/unload two stage recip 25 Load/unload two stage recip 30 Load/unload two stage recip 30 Load/unload two stage recip 30 Load/unload two stage recip 30 Load/unload two stage recip 30 Load/unload two stage recip 30 Load/unload two stage recip 40 Load/unload two stage recip 40 Load/unload two stage recip 40 Load/unload two stage recip 40 Load/unload two stage recip 40 Load/unload two stage recip 40 Load/unload two stage recip 50 Load/unload two stage recip 50 Load/unload two stage recip 50 Load/unload two stage recip 50 Load/unload two stage recip 50 Load/unload two stage recip 50 Load/unload two stage recip 60 Load/unload two stage recip 60 Load/unload two stage recip 60 Load/unload two stage recip 60 Load/unload two stage recip 60 Load/unload two stage recip 60 Load/unload two stage recip 75 Load/unload two stage recip 75 Load/unload two stage recip 75 Load/unload two stage recip 75 Load/unload February 25, 2010 C - 48 Version 1.1

244 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage recip 75 Load/unload two stage recip 75 Load/unload two stage recip 75 Load/unload two stage recip 75 Load/unload two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 75 Multi-step unloading two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Load/unload two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 100 Multi-step unloading two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload two stage recip 125 Load/unload February 25, 2010 C - 49 Version 1.1

245 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 125 Multi-step unloading two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Load/unload two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 150 Multi-step unloading two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Load/unload two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading February 25, 2010 C - 50 Version 1.1

246 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading two stage recip 200 Multi-step unloading two stage recip 250 Load/unload two stage recip 250 Load/unload two stage recip 250 Load/unload two stage recip 250 Load/unload two stage recip 250 Load/unload two stage recip 250 Multi-step unloading two stage recip 250 Multi-step unloading two stage recip 250 Multi-step unloading two stage recip 250 Multi-step unloading two stage recip 250 Multi-step unloading two stage recip 300 Load/unload two stage recip 300 Load/unload two stage recip 300 Load/unload two stage recip 300 Load/unload two stage recip 300 Load/unload two stage recip 300 Multi-step unloading two stage recip 300 Multi-step unloading two stage recip 300 Multi-step unloading two stage recip 300 Multi-step unloading two stage recip 300 Multi-step unloading two stage recip 350 Load/unload two stage recip 350 Load/unload two stage recip 350 Load/unload two stage recip 350 Load/unload two stage recip 350 Load/unload two stage recip 350 Multi-step unloading two stage recip 350 Multi-step unloading two stage recip 350 Multi-step unloading two stage recip 350 Multi-step unloading two stage recip 350 Multi-step unloading two stage recip 400 Load/unload two stage recip 400 Load/unload February 25, 2010 C - 51 Version 1.1

247 Compressor Type HP Control Type Rated Pressure (psig) Rated Capacity (acfm) Package Power (kw/ 100acfm) two stage recip 400 Load/unload two stage recip 400 Load/unload two stage recip 400 Load/unload two stage recip 400 Multi-step unloading two stage recip 400 Multi-step unloading two stage recip 400 Multi-step unloading two stage recip 400 Multi-step unloading two stage recip 400 Multi-step unloading February 25, 2010 C - 52 Version 1.1

248 C.5 Linear T8 Fluorescent Generational Definition T8 and T5 Fluorescent Lamps must meet the Color Rendering Index and Rated Lamp Life standards listed in Table 1 below: Table 1: Eligible Fluorescent Lamp Characteristics Lamp Type & Size Ballast Type CRI Minimum Rated Lamp Life (3 hrs/start) T8 2-ft, 3-ft, 4-ft Offeringmed Start/ Offeringmed Rapid-start >= 80 24,000 hours T8 All Sizes Instant Start >= 80 18,000 hours T5 All Sizes Offeringmed Start/ Offeringmed Rapid-start >= 82 20,000 hours February 25, 2010 C - 53 Version 1.1

249 Appendix D Building Descriptions and Climate Zones

250 APPENDIX D: Building Descriptions The purpose of the Building Descriptions is to assist the user in selecting an appropriate type of building when using the Air Conditioning estimating tools. The selected building type should be the one that most closely matches the actual project. These summaries provide the user with the inputs for the typical buildings. Minor variations from these inputs will occur based on differences in building vintage and climate zone. The Building Descriptions are referenced from the Database for Energy Efficiency Resources (DEER) Update Study. It should be noted that the user is required to provide certain inputs for the user s specific building (e.g. actual conditioned area, city, operating hours, economy cycle, new AC system and new AC system efficiency). The remaining inputs are approximations of the building and are deemed acceptable to the user. If none of the typical building models are determined to be a fair approximation then the user has the option to use the Custom Building approach. The Custom Building option instructs the user how to initiate the Engage Software. The Engage Software is a stand-alone, DOE2 based modeling program. February 25, 2009 D-1 Version 1.1

251 Prototype Source Activity Area Type Area % Area Simulation Model Notes 1. Assembly DEER Auditorium 33, Thermal Zoning: One zone per activity area. Office Total 34,000 Model Configuration: Matches 1994 DEER prototype 2. Education - Primary School 3. Education - Secondary School HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. DEER Classroom/Lecture 31, Thermal Zoning: One zone per activity area. Dining Area 7, Exercising Centers and 7, Model Configuration: 1994 DEER model consisted of Gymnasium one building. Current model consists of two identical models, each rotated 90 degrees to achieve reasonable distribution of solar gains. Kitchen and Food Preparation 3, Total 50,000 HVAC Systems: The prototype uses Rooftop DX systems. The system is changed to Rooftop HP for the heat pump efficiency measures. DEER Classroom/Lecture 88, Thermal Zoning: One zone per activity area. Computer Room 3, (Instructional/PC Lab) Model Configuration: 1994 DEER model consisted of Dining Area 22, one building. Current model consists of four identical models that comprise that include the classroom, Exercising Centers and 22, computer room, kitchen, dining and office areas, each Gymnasium rotated 90 degrees to achieve reasonable distribution of solar gains. A fifth building represents the gym. Kitchen and Food Preparation 10, Office (General) 3, Total 150,000 HVAC Systems: The prototype uses Rooftop DX systems. The system is changed to Rooftop HP for the heat pump efficiency measures. For built-up system measures applicable to this prototype, the system is VAV, except for the kitchen areas, which are served by Rooftop DX systems that are changed to Rooftop HP. February 25, 2010 D-2 Version 1.1

252 Prototype Source Activity Area Type Area % Area Simulation Model Notes 4. Education - Community College 5. Education - University DEER Classroom/Lecture 150, Thermal Zoning: One zone per activity area. Computer Room 9, (Instructional/PC Lab) Model Configuration: 1994 DEER model consisted of Dining Area 26, one building. Current model consists of two identical models that comprise that include the classroom, Kitchen and Food Preparation 5, computer room, kitchen, dining and office areas, each Office (General) 70, rotated 90 degrees to achieve reasonable distribution of Total 300,000 solar gains. HVAC Systems: The prototype uses VAV systems, except for the kitchen areas use Rooftop DX systems that are changed to Rooftop HP systems for the heat pump efficiency measures. DEER Classroom/Lecture 431, Thermal Zoning: Main instructional buildings use Comm/Ind Work (General Low 80, generic thermal zones with all activity area Bay) characteristics averaged across the entire zone. The Computer Room 27, dormitory buildings are zoned by individual activity area. (Instructional/PC Lab) Model Configuration: 1994 DEER model consisted of Corridor (Dormitory) 30, two buildings: one instructional building and one Dining Area 24, dormitory. Current model consists of four identical Hotel/Motel Guest Room 170, instructional buildings each rotated 90 degrees to (Dormitory) achieve reasonable distribution of solar gains. There are also two identical buildings representing dormitories, each rotated 90 degrees. Kitchen and Food Preparation 10, Office (General) 226, Total 1,000,000 HVAC Systems: The prototype uses VAV systems, except for the kitchen areas use Rooftop DX systems that are changed to Rooftop HP systems for the heat pump efficiency measures. February 25, 2010 D-3 Version 1.1

253 Prototype Source Activity Area Type Area % Area Simulation Model Notes 27. Education - Relocatable Classroom 6. Grocery DEER/ Vacom 7. Health/Medical - Hospital HPCBS Classroom/Lecture 1, Thermal Zoning: One zone per activity area. Model Configuration: Matches HPCBS prototype. HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. Comm/Ind Work (Loading 2, Dock) Thermal Zoning: One zone per activity area. Office (General) 3, Model Configuration: Vacom developed the prototype Refrigerated (Food 1, based on their experience in providing energy efficiency Preparation) services to grocery stores. Refrigerated (Walk-in Cooler) 1, HVAC Systems: The prototype uses Rooftop DX Refrigerated (Walk-in Freezer) systems for the non-refrigerated spaces. These are Retail Sales Grocery 40, switched to Rooftop DX systems for heat pump Total 50,000 efficiency measures. The refrigerated spaces use detailed refrigeration systems developed using the equest refrigeration version. A complete description of grocery refrigeration systems is included in Section 7.3 Grocery Refrigeration Measures. DEER Dining Area 4, Thermal Zoning: One zone per activity area. Kitchen and Food Preparation 1, Laboratory Medical 57, Model Configuration: Matches 1994 DEER prototype. Medical and Clinical Care 95, HVAC Systems: The prototype uses FPFC systems for Office (General) 90, the patient rooms. The kitchen uses a Rooftop DX Total 250,000 system, which is changed to a Rooftop HP system for the heat pump efficiency measures. Except for the oldest vintage, VAV systems are used for all other spaces. The oldest vintage uses a CV Reheat system. February 25, 2010 D-4 Version 1.1

254 Prototype Source Activity Area Type Area % Area Simulation Model Notes 8. Health/Medical - Nursing Home 9. Lodging - Hotel DEER Corridor 3, Thermal Zoning: One zone per activity area. Dining Area 6, Hotel/Motel Guest Room (incl. 26, Model Configuration: Matches 1994 DEER prototype toilets) (Patient Rooms) HVAC Systems: The prototype uses FPFC systems for Kitchen and Food Preparation 2, all spaces except the kitchen. The kitchen uses a Office (General) 21, Rooftop DX system, which is changed to a Rooftop HP Total 60,000 system for the heat pump efficiency measures. FPFC systems are changed to a VAV system for any applicable measures for built-up systems. DEER/ NCC Bar Cocktail Lounge Thermal Zoning: One zone per activity area. Corridor 20, Dining Area 1, Model Configuration: The building envelope and occupancy matches 1994 DEER Prototype. Guestroom Hotel/Motel Guest Room (incl. 160, areas are divided into unoccupied rooms (40,171 toilets) ft 2 /20%) and occupied rooms (120,511 ft 2 /60%). HVAC systems are based on NCC. Kitchen and Food Preparation Laundry 4, Lobby (Hotel) 8, Office (General) 4, Total 200,00 HVAC Systems: The kitchen is served by a Rooftop DX system which is changed to a Rooftop HP system for the heat pump efficiency measures. The remaining public areas are served by a CV Reheat system for the oldest vintage, VAV systems for the second and third vintages and Rooftop VAV systems for the latest two vintages. Guestrooms are served by FPFC systems for the first three vintages and PTHP systems for the latest two vintages. February 25, 2010 D-5 Version 1.1

255 Prototype Source Activity Area Type Area % Area Simulation Model Notes 10. Lodging - Motel 11. Manufacturing - Bio/Tech 12. Manufacturing - Light Industrial DEER Corridor 3, Thermal Zoning: One zone per activity area. Hotel/Motel Guest Room (incl. 25, toilets) Model Configuration: Matches 1994 DEER Laundry configuration. Guestrooms are divided among 12 hour occupied (12,794 ft 2 /42.6%), 24-hour occupied (6,397 Office (General) ft 2 /21.3%) and unoccupied rooms (6,397 ft 2 /21.3%). Total 30,000 HVAC Systems: The oldest vintage uses PTAC systems with electric resistance heating. All other vintages use PTHP systems. NCC DEER Comm/Ind Work (High Tech 90, Thermal Zoning: The model uses generic thermal Bio Tech Lab) zones with all activity area characteristics averaged Computer Room 4, across the entire zone. (Mainframe/Server) Conference Room 4, Model Configuration: Matches NCC prototype. Corridor 40, HVAC Systems: The prototype uses Rooftop DX Dining Area 6, systems, which are changed to Rooftop HP systems for Kitchen and Food Preparation 2, the heat pump efficiency measures. Office (General) 53, Total 200,000 Comm/Ind Work (General 80, High Bay) Thermal Zoning: One zone per activity area. Storage (Unconditioned) 20, Model Configuration: Matches 1994 DEER prototype Total 100,000 HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. February 25, 2010 D-6 Version 1.1

256 Prototype Source Activity Area Type Area % Area Simulation Model Notes 13. Office - Large NCC Conference Room 7, Thermal Zoning: The model uses generic thermal Copy Room (photocopying 3, zones with all activity area characteristics averaged equipment) across the entire zone. Reception/Waiting) Corridor 17, Lobby(Office 8, Model Configuration: Matches NCC prototype. HVAC Systems: The oldest vintage uses CV Reheat Mechanical/Electrical Room 7, systems, and all other vintages use VAV systems. Office (Executive/Private) 43, Office (Open Plan) 78, Restrooms 8, Total 175, Office - Small NCC Conference Room Thermal Zoning: The model uses generic thermal Copy Room (photocopying zones with all activity area characteristics averaged equipment) across the entire zone. Reception/Waiting) Corridor 1, Lobby (Office Model Configuration: Matches NCC prototype. HVAC Systems: The prototype uses Rooftop DX Mechanical/Electrical Room systems, which are changed to Rooftop HP systems for Office (Executive/Private) 7, the heat pump efficiency measures. Restrooms Total 10, Restaurant - DEER Dining Area 2, Thermal Zoning: One zone per activity area. Sit-Down Kitchen and Food Preparation 1, Lobby (Main Entry and Model Configuration: Matches 1994 DEER prototype Assembly) Restrooms Total 4,000 HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. February 25, 2010 D-7 Version 1.1

257 Prototype Source Activity Area Type Area % Area Simulation Model Notes 16. Restaurant - Fast-Food 17. Retail - 3-Story Large DEER Dining Area 1, Thermal Zoning: One zone per activity area. Kitchen and Food Preparation Lobby (Main Entry and Model Configuration: Matches 1994 DEER prototype Assembly) HVAC Systems: The prototype uses Rooftop DX Restrooms systems, which are changed to Rooftop HP systems for Total 2,000 the heat pump efficiency measures. DEER Office (General) 6, Thermal Zoning: One zone per activity area. Retail Sales and Wholesale 96, Showroom Model Configuration: Matches 1994 DEER prototype Storage (Conditioned) 18, HVAC Systems: The oldest vintage uses a CV Reheat Total 120,000 systems and all other vintages us VAV systems. 18. Retail - Single- NCC Auto Repair Workshop 5, Thermal Zoning: One zone per activity area. Story Large Kitchen and Food Preparation 1, Model Configuration: Matches NCC prototype. Office (General) 4, Retail Sales and Wholesale 107, HVAC Systems: The prototype uses Rooftop DX Showroom systems, which are changed to Rooftop HP systems for Storage (Conditioned) 11, the heat pump efficiency measures. Total 130, Retail - Small DEER Retail Sales and Wholesale 6, Showroom Thermal Zoning: One zone per activity area. Storage (Conditioned) 1, Model Configuration: Matches 1994 DEER prototype Total 8,000 HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. February 25, 2010 D-8 Version 1.1

258 Prototype Source Activity Area Type Area % Area Simulation Model Notes 20. Storage - Conditioned 21. Storage - Unconditioned 22. Storage - Refrigerated Warehouse NCC Storage (Conditioned) 500, Thermal Zoning: The model uses generic thermal zones with all activity area characteristics averaged across the entire zone. Model Configuration: Matches NCC prototype. HVAC Systems: The prototype uses Rooftop DX systems, which are changed to Rooftop HP systems for the heat pump efficiency measures. NCC Storage (Unconditioned) 500, Thermal Zoning: The model uses generic thermal zones with all activity area characteristics averaged across the entire zone. Vacom Model Configuration: Matches NCC prototype. HVAC Systems: The prototype uses UH systems only for freeze protection. Comm/Ind Work (Loading 8, Dock) Thermal Zoning: One zone per activity area. Office (Executive/Private) 2, Model Configuration: Vacom developed the prototype Refrigerated (Cooled Storage) 49, based on their experience in providing energy efficiency services to refrigerated warehouses. Refrigerated (Food 40, Preparation) Total 100,000 HVAC Systems: The prototype uses Rooftop DX systems for the non-refrigerated spaces. These are switched to Rooftop DX systems for heat pump efficiency measures. The refrigerated spaces use detailed refrigeration systems developed using the equest refrigeration version. A complete description of grocery refrigeration systems is included in Section 7.4 Refrigerated Warehouse Measures. February 25, 2010 D-9 Version 1.1

259 APPENDIX D: Climate Zones The purpose of the Climate Zones section is to assist the user in selecting an appropriate California Climate Zone weather data set for weather related measures. The Climate Zone list is from the California Energy Commissions (CEC) website: The following pages are a listing of the climate zones associated with several thousand specific California cities, towns and other locations. This information represents an abridged version of the CEC publication California Climate Zone Descriptions, which contains detailed survey definitions of the sixteen climate zones. February 25, 2010 D-10 Version 1.1

260 February 25, 2010 D-11 Version 1.1

261 3 Abbotts Lagoon, Marin 13 Academy, Fresno 12 Acampo, San Joaquin 15 Acolita, Imperial 14 Actis, Kern 14 Acton, Los Angeles 4 Adelaida, San Luis Obispo 14 Adelanto, San Bernardino 16 Adin, Modoc 13 Adobe, Kern 14 Afton, San Bernardino 16 Ager, Siskiyou 9 Agoura Hills, Los Angeles 5 Agua Caliente Canyon, Santa Barbara 15 Agua Caliente Springs, San Diego 9 Agua Duice, Los Angeles 15 Aguanga, Riverside 13 Ahwahnee, Madera 14 Airport Lake, Inyo 3 Alameda, Alameda 3/12 Alameda County 12 Alamo, Contra Costa 15 Alamo River, Imperial 3 Albany, Alameda 10 Alberhill, Riverside 1 Albion, Mendocino 2 Alderpoint, Humboldt 9 Alhambra, Los Angeles 3 Alisal, Monterey 3 Alisal Slough, Monterey 16 Aliso Canyon, Los Angeles 8 Aliso Viejo, Orange 16 Alleghany, Sierra 12 Allendale, Solano 13 Allensworth, Tulare 4 Almaden A.F.S., Santa Clara 16 Almanor, Plumas 8 Alondra Park, Los Angeles 13 Alpaugh, Tulare 16 Alpine County 10 Alpine, San Diego 16 Alta, Placer 10 Alta Loma, San Bernardino 16 Alta Sierra, Kern 9 Altadena, Los Angeles 12 Altamont, Alameda 12 Altaville, Calaveras 1 Alton, Humboldt 16 Alturas, Modoc 4 Alviso, Santa Clara 12 Amador, Amador 12/16 Amador County 14 Amargosa Range, Inyo 14 Amargosa River, Inyo 15 Amboy, San Bernardino 16 Ambrose, Modoc 2 American Canyon, Napa 12 American River, Sacramento 16 American River (Silver Fork), El Dorado 15 Amos, Imperial A 6 Anacapa Island, Ventura 8 Anaheim, Orange 1 Anchor Bay, Mendocino 11 Anderson, Shasta 4 Anderson Lake, Santa Clara 15 Andrade, Imperial 3 Angel Island, Marin 12 Angels Camp, Calaveras 13 Angiola, Tulare 2 Angwin, Napa 1 Annapolis, Sonoma 12 Antelope, Sacramento 14 Antelope Center, Los Angeles 16 Antelope Lake, Plumas 13 Antelope Plain, Kern 14 Antelope Valley, Los Angeles 12 Antioch, Contra Costa 16 Anza, Riverside 16 Apache Canyon, Ventura 14 Apple Valley, San Bernardino 11 Applegate, Placer 3 Aptos, Santa Curz 15 Araz Wash, Imperial 11 Arbuckle, Colusa 9 Arcadia, Los Angeles 1 Arcata, Humboldt 1 Arcata Bay, Humboldt 12 Arden Town, Sacramento 14 Argus, San Bernardino 16 Argus Peak, Inyo 16 Argus Range, Inyo 10 Arlington, Riverside 13 Armona, Kings 16 Arnold, Calaveras 2 Arnold, Mendocino 3/4 Aromas, Monterey 14 Arrowhead Junction, San Bernardino 4 Arroyo Dos Picachos, San Benito 5 Arroyo Grande, San Luis Obispo 13 Arroyo Hondo, Fresno 4 Arroyo Hondo, Santa Clara 15 Arroyo Salada, Imperial 3/4 Arroyo Seco, Monterey 8 Artesia, Los Angeles 11 Artois, Glenn 13 Arvin, Kern 13 Ash Mountain, Tulare 3 Ashland, Alameda 16 Aspen Valley, Tuolumne 2 Asti, Sonoma 4 Atascadero, San Luis Obispo 3 Atherton, San Mateo 12 Athlone, Merced 14 Atolia, San Bernardino 12 Atwater, Merced 13/16 Auberry, Fresno 11 Auburn, Placer 11 Auburn Ravine, Sutter 12 Aukum, El Dorado 6 Avalon, Los Angeles 14 Avawatz Mountains, San Bernardino 13 Avenal, Kings February 25, 2010 D-12 Version 1.1

262 5 Avila Beach, San Luis Obispo 9 Avocado Heights, Los Angeles 9 Azusa, Los Angeles 13 Badger, Tulare 12 Bagby, Mariposa 15 Bagdad, San Bernardino 14 Baker, San Bernardino 13 Bakersfield, Kern 14 Balch, San Bernardino 16 Bald Eagle Mountain, Plumas 9 Baldwin Park, Los Angeles 14 Ballarat, Inyo 12 Ballico, Merced 11 Bangor, Butte 15 Banning, Riverside 12 Banta, San Joaquinn 15 Bard, Imperial 9 Bardsdale, Ventura 2 Barkerville, Lake 16 Barkley Mountain, Tehama 10 Barona, San Diego 10 Barrett Dam, San Diego 10 Barrett Junction, San Diego 14 Barstow, San Bernardino 16 Bartle, Siskiyou 16 Bartlett, Inyo 2 Bartlett Springs, Lake 16 Bass Lake, Madera 9 Bassett, Los Angeles 16 Baxter, Placer 16 Bayley, Modoc 11 Bayliss, Glenn 1 Bayside, Humboldt 5 Baywood Park, San Luis Obispo 11 Beale Air Force Base, Yuba 2 Bear Buttes, Humboldt 16 Bear River, Amador 1 Bear River, Humboldt 11 Bear River, Sutter/Yuba 12 Bear Valley, Mariposa 16 Beardsley Lake, Tuolumne 10 Beaumont, Riverside 16 Beckwourth, Plumas 16 Beckwourth Pass, Lassen/Plumas 11 Beegum, Shasta 16 Belden, Plumas 8 Bell, Los Angeles 8 Bell Gardens, Los Angeles 14 Bell Mountain, San Bernardino 14 Bell Mountain Wash, San Bernardino 2 Bell Springs, Mendocino 4 Bell Station, Santa Clara 11 Bella Vista, Shasta 8 Bellflower, Los Angeles 12 Bellota, San Joaquin 3 Belmont, San Mateo 3 Belvedere, Marin 12 Ben Hur, Mariposa 3 Ben Lomond, Santa Cruz B 2 Benbow, Humboldt 11 Bend, Tehama 12 Benicia, Solano 14 Bennetts Well, Inyo 16 Benton, Mono 16 Benton Hot Springs, Mono 13 Berenda, Madera 3 Berkeley, Alameda 11 Berry Creek, Butte 4 Berryessa, Santa Clara 2 Berryessa Lake, Napa 2/3 Berryessa Peak, Napa/Yolo 16 Beswick, Siskiyou 12 Bethany, San Joaquin 12 Bethel Island, Contra Costa 5 Betteravia, Santa Barbara 9 Beverly Hills, Los Angeles 16 Bieber, Lassen 16 Big Bar, Trinity 3 Big Basin, Santa Cruz 16 Big Bear City, San Bernardino 16 Big Bear Lake, San Bernardino 16 Big Bend, Butte 16 Big Bend, Shasta 2 Big Bend, Sonoma 16 Big Creek, Fresno 1 Big Lagoon, Humboldt 16 Big Lake, Shasta 15 Big Maria Mountains, Riverside 2 Big Mountains, Sonoma 12 Big Oak Flat, Tuolumne 16 Big Pine, Inyo 16 Big Pines, Los Angeles 14 Big Rock Wash, Los Angeles 16 Big Sage Reservoir, Modoc 16 Big Springs, Siskiyou 3 Big Sur, Monterey 3 Big Sur River (North Fork), Monterey 16 Big Tujungs Canyon, Los Angeles 16 Big Valley Mountains, Lassen/Modoc 11 Biggs, Butte 16 Bijou, El Dorado 13 Biola, Fresno 12 Birds Landing, Solano 16 Bishop, Inyo 14 Bissell, Kern 4 Bitterwater, San Benito 16 Black Bear, Siskiyou 16 Black Butte, Glenn 11 Black Butte Reservoir, Glenn/Tehama 2/16 Black Butte River, Mendocino 14 Black Canyon Wash, San Bernardino 15 Black Meadow Landing, San Bernardino 13 Black Mountain, Fresno 2 Black Point, Marin 12 Blackhawk, Contra Costa 13 Blackwells Corner, Kern 16 Blairsden, Plumas 2 Blocksburg, Humboldt 2 Bloomfield, Sonoma 10 Bloomington, San Bernardino 11 Blossom, Tehama February 25, 2010 D-13 Version 1.1

263 16 Blue Canyon, Placer 1 Blue Lake, Humboldt 11 Blunt, Tehama 15 Blythe, Riverside 16 Boca, Nevada 16 Boca Reservoir, Nevada 1 Bodega, Sonoma 3 Bodega Bay, Marin 1 Bodega Bay, Sonoma 1 Bodega Head, Sonoma 16 Bodfish, Kern 16 Bodie, Mono 16 Bolam, Siskiyou 3 Bolinas, Marin 16 Bollibokka Mountain, Shasta 3 Bolsa Knolls, Monterey 15 Bombay Beach, Imperial 13 Bonadella Ranchos Madera Rancho, Fresno 16 Bonanza King, Trinity 15 Bonds Corner, Imperial 13 Bonita, Madera 3 Bonny Doon, Santa Cruz 10 Bonsall, San Diego 2 Boonville, Mendocino 12 Bootjack, Mariposa 14 Boron, Kern 15 Borrego, San Diego 15 Borrego Springs, San Diego 10 Bostonia, San Diego 3 Boulder Creek, Santa Cruz 14 Boulevard, San Diego 13 Bowles, Fresno 11 Bowman, Placer 15 Box Canyon, Riverside 2 Boyes Hot Springs, Sonoma 9 Bradbury, Los Angeles 4 Bradley, Monterey 12 Brannan Island, Sacramento 1 Branscomb, Mendocino 14 Brant, San Bernardino 15 Brawley, Imperial 16 Bray, Siskiyou 8 Brea, Orange 16 Breckenridge Mountain, Kern 12 Brentwood, Contra Costa 12 Briceburg, Mariposa 2 Briceland, Humboldt 12 Bridge House, Sacramento 16 Bridgeport, Mono 16 Bridgeport Reservoir, Mono 2 Bridgeville, Humboldt 12 Briones Reservoir, Contra Costa 3 Brisbane, San Mateo 15 Bristol Lake, San Bernardino 14 Bristol Mountains, San Bernardino 12 Broderick, Yolo 3 Brookdale, Santa Cruz 12 Brooks Ranch, Yolo 14 Brown, Kern 11 Browns Valley, Yuba 11 Brownsville, Yuba 1 Bruhel Point, Mendocino 16 Brush Creek, Butte 14 Bryman, San Bernardino 4 Bryson, Monterey 12 Bryte, Yolo 16 Buck Meadows, Mariposa 11 Buckeye, Shasta 14 Buckhorn Lake, Kern 16 Bucks Lake, Plumas 14 Budweiser Wash, San Bernardino 5 Buellton, Santa Barbara 8 Buena Park, Orange 12 Buena Vista, Amador 13 Buena Vista Lake Bed, Kern 1 Bull Creek, Humboldt 14 Bull Spring Wash, San Bernardino 14 Bullion Mountains, San Bernardino 16 Buntingville, Lassen 9 Burbank, Los Angeles 2 Burbeck, Mendocino 2 Burdell, Marin 3 Burlingame, San Mateo 16 Burney, Shasta 16 Burney Mountain, Shasta 16 Burnt Ranch, Trinity 13 Burrelield, Fresno 12 Burson, Calaveras 1 Butler Valley, Humboldt 11 Butte City, Glenn 11/16 Butte County 16 Butte Meadows, Butte 16 Butte Valley, Siskiyou 13 Buttonwillow, Kern 12 Byron, Contra Costa 15 Cabazon, Riverside 7 Cabrillo National Monument, San Diego 5 Cachuma Lake, Santa Barbara 15 Cadiz, San Bernardino 15 Cadiz Lake, San Bernardino 15 Cadiz Valley, San Bernardino 14 Cady Mountains, San Bernardino 2 Cahto Peak, Mendocino 16 Cahuilla, Riverside 16 Cajon Junction, San Bernardino 16 Cajon Summit, San Bernardino 9 Calabasas, Los Angeles 14 Calada, San Bernardino 12/16 Calaveras County 12/4 Calaveras Reservoir, Alameda/Santa Clara 12 Calaveras River, San Joaquin 12 Calaveritas, Calaveras 13 Calders Corner, Kern 15 Calexico, Imperial 13 Calflax, Fresno 16 Caliente, Kern 4 Caliente Range, San Luis Obispo 14 California City, Kern 16 California Hot Springs, Tulare 4 California Valley, San Luis Obispo 10 Calimesa, Riverside C February 25, 2010 D-14 Version 1.1

264 15 Calipatria, Imperial 2 Calistoga, Napa 16 Callahan, Siskiyou 16 Calneva, Lassen 2 Calpella, Medocino 16 Calpine, Sierra 13 Calwa, Fresno 12 Camanche Reservoir, Amador/Calaveras 6 Camarillo, Ventura 5 Cambria, San Luis Obispo 12 Cameron Park, El Dorado 12 Camino, El Dorado 14 Camino, San Bernardino 16 Camp Angelus, San Bernardino 11 Camp Far West Reservoir, Yuba 2 Camp Meeker, Sonoma 13 Camp Nelson, Tulare 12 Camp Pardee, Calaveras 7 Camp Pendleton, San Diego 4 Camp Roberts, Monterey 16 Camp Richardson, El Dorado 4 Campbell, Santa Clara 14 Campo, San Diego 12 Campo Seco, Calaveras 16 Camptonville, Yuba 16 Canby, Modoc 9 Canoga Park, Los Angeles 14 Cantil, Kern 10 Canyon Lake, Riverside 16 Canyondam, Plumas 12 Capay, Yolo 1 Cape Mendocino, Humboldt 3 Cape San Martin, Monterey 1 Capetown, Humboldt 6 Capistrano Beach, Orange 6 Capitan, Santa Barbara 3 Capitola, Santa Cruz 16 Caples Lake, Alpine 12 Carbona, San Joaquin 12 Carbondale, Amador 7 Cardiff-by-the-Sea, San Diego 16 Caribou, Plumas 1 Carlotta, Humboldt 7 Carlsbad, San Diego 3 Carmel-by-the-Sea, Monterey 3 Carmel Highlands, Monterey 3 Carmel Valley, Monterey 12 Carmichael, Sacramento 16 Carnelian Bay, Placer 6 Carpinteria, Santa Barbara 16 Carr Butte, Modoc 4 Carrizo Plain, San Luis Obispo 15 Carrizo Wash, Imperial 16 Carrville, Trinity 6 Carson, Los Angeles 16 Carson River (East Fork), Alpine 16 Carson River (West Fork), Alpine 16 Cartago, Inyo 13 Caruthers, Fresno 10 Casa de Oro Mount Helix, San Diego 16 Cascade Range, Siskiyou 9 Casitas Springs, Ventura 5 Casmalia, Santa Barbara 1 Caspar, Mendocino 16 Cassel, Shasta 9 Castaic, Los Angeles 16 Castella, Shasta 12 Castle Air Force Base, Merced 3 Castro Valley, Alameda 3 Castroville, Monterey 16 Caswell, Los Angeles 15 Cathedral City, Riverside 12 Catheys Valley, Mariposa 11 Catlett, Sutter 16 Cayton, Shasta 5 Cayucos, San Luis Obispo 1 Cazadero, Sonoma 16 Cecilville, Siskiyou 16 Cedar Grove, Fresno 11 Cedar Ridge, Nevada 14 Cedar Wash, San Bernardino 16 Cedarville, Modoc 13 Centerville, Fresno 1 Centerville, Humboldt 11 Centerville, Shasta 11 Centerville Power House, Butte 11 Central Valley, Shasta 12 Ceres, Stanislaus 8 Cerritos, Los Angeles 4 Cerro Alto, San Luis Obispo 16 Cerro Gordo Peak, Inyo 16 Chalfant, Mono 16 Challenge, Yuba 15 Chambless, San Bernardino 16 Chanchelulla Peak, Trinity 9 Charter Oak, Los Angeles 9 Chatsworth, Los Angeles 12 Chemurgic, Stanislaus 11 Cherokee, Butte 16 Cherry Lake, Tuolumne 10 Cherry Valley, Riverside 3 Cherryland, Alameda 16 Chester, Plumas 11 Chicago Park, Nevada 11 Chico, Butte 16 Chidago Canyon, Mono 16 Chilcoot, Plumas 14 China Lake, San Bernardino 14 China Lake, Kern 16 China Peak, Trinity 12 Chinese Camp, Tuolumne 10 Chino, San Bernardino 10 Chino Hills, San Bernardino 14 Chiriaco Summit, Riverside 16 Chloride City, Inyo 4 Cholame, San Luis Obispo 4 Cholame Hills, Monterey 13 Chowchilla, Madera 13 Chowchilla Canal, Madera 11 Chrome, Glenn 3 Chualar, Monterey 15 Chubbuck, San Bernardino 14 Chuckwalla Mountains, Riverside 15 Chuckwalla Valley, Riverside February 25, 2010 D-15 Version 1.1

265 7 Chula Vista, San Diego 14 Cima, San Bernardino 16 Cisco, Placer 12 Citrus Heights, Sacramento 9 City Terrace, Los Angeles 16 Clair Engle Lake, Trinity 16 Claraville, Kern 9 Claremont, Los Angeles 14 Clark Mountain, San Bernardino 12 Clarksburg, Yolo 12 Clarksville, El Dorado 16 Clavey River, Tuolumne 12 Clay, Sacramento 12 Clayton, Contra Costa 16 Clear Creek, Lassen 16 Clear Lake Reservoir, Modoc 2 Clearlake, Lake 2 Clearlake Highlands, Lake 2 Clearlake Oaks, Lake 2 Clearlake Park, Lake 12 Clements, San Joaquin 1 Cleone, Mendocino 16 Clio, Plumas 11 Clipper Gap, Placer 16 Clipper Mills, Butte 11 Cloverdale, Shasta 2 Cloverdale, Sonoma 13 Clovis, Fresno 15 Clyde, Imperial 15 Coachella, Riverside 15 Coachella Valley, Riverside 13 Coalinga, Fresno 13 Coarsegold, Madera 2 Cobb, Lake 4 Coburn, Monterey 11 Codora, Glenn 11 Cohasset, Butte 16 Cold Springs, Tuolumne 16 Coleville, Mono 11 Colfax, Placer 11 College City, Colusa 12 Collegeville, San Joaquin 12 Collierville, San Joaquin 12 Collinsville, Solano 3 Colma, San Mateo 12 Coloma, El Dorado 15 Colorado River, San Bernardino 10 Colton, San Bernardino 12 Columbia, Tuolumne 11 Colusa, Colusa 12 Colusa Basin Drainage Canal, Yolo 11 Colusa County 11 Colusa Trough, Colusa 8/9 Commerce, Los Angeles 1 Comptche, Mendocino 8 Compton, Los Angeles 6 Concepcion, Santa Barbara 12 Concord, Contra Costa 16 Condrey Mountain, Siskiyou 13 Conejo, Fresno 13 Conner, Kern 16 Constantia, Lassen 3/12 Contra Costa County 16 Cooks Station, Amador 12 Cool, El Dorado 16 Copco, Siskiyou 12 Copperopolis, Calaveras 13 Corcoran, Kings 13 Corcoran Reservoir, Kings 12 Cordelia, Solano 9 Cornell, Los Angeles 16 Cornell, Modoc 11 Corning, Tehama 11 Corning Canal, Tehama 10 Corona, Riverside 6 Corona Del Mar, Orange 7 Coronado, San Diego 12 Corral Hollow, Alameda San Joaquin 3 Corralitos, Santa Cruz 2/3 Corte Madera, Marin 16 Coso Hot Springs, Inyo 16 Coso Junction, Inyo 16 Coso Peak, Inyo 16 Coso Range, Inyo 6 Costa Mesa, Orange 12 Cosumnes River, Sacramento 2 Cotati, Sonoma 8 Coto De Caza, Orange 16 Cottage Grove, Siskiyou 11 Cottonwood, Shasta 14/16 Cottonwood Canyon, Inyo 16 Cottonwood Mountains, Inyo 14 Cottonwood Wash, San Bernardino 16 Cougar, Siskiyou 12 Coulterville, Mariposa 12 Country Club, San Joaquin 12 Courtland, Sacramento 16 Courtright Reservoir, Fresno 2 Covelo, Mendocino 9 Covina, Los Angeles 16 Covington Mill, Trinity 16 Cow Head Lake, Modoc 16 Cowtrack Mountain, Mono 4 Coyote, Santa Clara 14 Coyote Lake, San Bernardino 15 Coyote Wash, Imperial 11 Cranmore, Sutter 1 Crannell, Humboldt 16 Crater Mountain, Lassen 1 Crescent City, Del Norte 16 Crescent Mills, Plumas 12 Cressey, Merced 16 Crestline, San Bernardino 4 Creston, San Luis Obispo 16 Crestview, Mono 12/3 Crockett, Contra Costa 16 Cromberg, Plumas 15 Cross Roads, San Bernardino 12 Crows Landing, Stanislaus 14 Crucero, San Bernardino 12 Crystal Springs Reservoir, San Mateo 10 Cucamonga, San Bernardino 8 Cudahy, Los Angeles 14 Cuddeback Lake, San Bernardino February 25, 2010 D-16 Version 1.1

266 16 Cuddy Canyon, Kern/Ventura 4 Cuesta Pass, San Luis Obispo 8 Culver City, Los Angeles 2 Cummings, Mendocino 2 Cunningham, Sonoma 4 Cupertino, Santa Clara 16 Curtis, Siskiyou 13 Cutler, Tulare 1 Cutten, Humboldt 4 Cuyama, Santa Barbara 4 Cuyama Valley, San Luis Obispo/Santa Barbara 7 Cuyamaca, San Diego 14 Cuyamaca Peak, San Diego 8 Cypress, Orange 14 Daggett, San Bernardino 13 Dairyland, Madera 11 Dairyville, Tehama 14 Dale Lake, San Bernardino 11 Dales, Tehama 16 Dalton, Modoc 3 Daly City, San Mateo 16 Dana, Shasta 6 Dana Point, Orange 14 Danby, San Bernardino 15 Danby Lake, San Bernardino 12 Danville, Contra Costa 16 Dardanelle, Tuolumne 12 Darrah, Mariposa 16 Darwin, Inyo 16 Darwin Wash, Inyo 13 Daulton, Madera 3 Davenport, Santa Cruz 12 Davis, Yolo 16 Davis Creek, Modoc 14 Dawes, San Bernardino 16 Day, Modoc 11 Dayton, Butte 10 De Luz, San Diego 11 De Sabla, Butte 16 Deadwood, Trinity 14 Death Valley, Inyo 14 Death Valley Junction, Inyo 14 Death Valley Wash, Inyo 16 Dedrick, Trinity 15 Deep Canyon, Riverside 16 Deep Springs, Inyo 16 Deep Springs Lake, Inyo 12 Deep Water Ship Channel, Solano/Yolo 16 Deer Creek Power House, Nevada 16 Deetz, Siskiyou 6 Del Aire, Los Angeles 10 Del Dios, San Diego 16 Del Loma, Trinity 7 Del Mar, San Diego 1/16 Del Norte County 12 Del Paso Heights, Sacramento 13 Del Rey, Fresno 3 Del Rey Oaks, Monterey 10 Del Rosa, San Bernardino D 13 Delano, Kern 11 Delevan, Colusa 12 Delhi, Merced 16 Delleker, Plumas 11 Delta, Shasta 12 Denair, Stanislaus 16 Denny, Trinity 12 Denverton, Solano 13 Derby Acres, Kern 14 Descanso, San Diego 14 Desert, San Bernardino 15 Desert Beach, Riverside 15 Desert Center, Riverside 15 Desert Hot Springs, Riverside 15 Desert Shores, Imperial 14 Desert View Highland, Los Angeles 16 Devils Canyon, Los Angeles 13 Devils Den, Kern 14 Devils Playground, San Bernardino 14 Devils Playground Wash, San Bernardino 10 Devore, San Bernardino 13 Di Giorgio, Kern 12 Diablo, Contra Costa 4 Diablo Range, Santa Clara 9 Diamond Bar, Los Angeles 16 Diamond Mountains, Lassen/Plumas 12 Diamond Springs, El Dorado 3 Dillon Beach, Marin 16 Dinkey Creek, Fresno 2 Dinsmores, Humboldt 13 Dinuba, Tulare 12 Discovery Bay, Contra Costa 16 Dixie Mountain, Plumas 15 Dixieland, Imperial 12 Dixon, Solano 11 Dobbins, Yuba 16 Dolomite, Inyo 6 Dominguez, Los Angeles 16 Donner Pass, Nevada/Placer 16 Dorrington, Calaveras 16 Dorris, Siskiyou 15 Dos Cabezas, San Diego 12 Dos Palos, Merced 2 Dos Rios, Mendocino 16 Douglas City, Trinity 8 Downey, Los Angeles 16 Downie River, Sierra 16 Downieville, Sierra 16 Doyle, Lassen 12 Dozler, Solano 6 Drake, Santa Barbara 3 Drakes Bay, Marin 3 Drakes Estero, Marin 16 Drakesbad, Plumas 16 Dry Canyon, Ventura 12 Drytown, Amador 9 Duarte, Los Angeles 12 Dublin, Alameda 13 Ducor, Tulare 12 Dudleys, Mariposa 15 Duguynos Canyon, San Diego 10 Dulzura, San Diego February 25, 2010 D-17 Version 1.1

267 16 Duncan Canyon, Placer 1 Duncans Mills, Sonoma 13 Dunlap, Fresno 16 Dunmovin, Inyo 12 Dunnigan, Yolo 16 Dunsmuir, Siskiyou 11 Durham, Butte 15 Durmid, Riverside 16 Dutch Flat, Placer 2 Duttons Landing, Napa 16 Dwinnell Reservoir, Siskiyou 14 Eagle Crags, San Bernardino 16 Eagle Lake, Lassen 16 Eagle Lake Resort, Lassen 14 Eagle Mountain, Riverside 14 Eagle Mountains, Riverside 16 Eagle Peak, Modoc 16 Eagleville, Modoc 13 Earlimart, Tulare 15 Earp, San Bernardino 11 East Biggs, Butte 8 East Compton, Los Angeles 10 East Hemet, Riverside 10 East Highlands, San Bernardino 8 East Irvine, Orange 9 East La Mirada, Los Angeles 9 East Los Angeles, Los Angeles 15 East Mesa, Imperial 11 East Nicolaus, Sutter 3 East Palo Alto, San Mateo 11 East Park Reservoir, Colusa 9 East Pasadena, Los Angeles 13 East Porterville, Tulare 16 East Quincy, Plumas 9 East San Gabriel 16 East Walker River, Mono 9 East Whittier, Los Angeles 13 Easton, Fresno 16 Ebbetts Pass, Alpine 2 Echo, Mendocino 14 Echo Canyon, Inyo 16 Echo Lake, El Dorado 16 Echo Summit, El Dorado 16 Eder, Placer 10 Edgemont, Riverside 16 Edgewood, Siskiyou 13 Edison, Kern 5 Edna, San Luis Obispo 14 Edwards Air Force Base, Kern 2 Eel Rock, Humboldt 10 El Cajon, San Diego 14 El Capitan Reservoir, San Diego 15 El Centro, Imperial 3 El Cerrito, Contra Costa 12 El Dorado, El Dorado 12/16 El Dorado County 12 El Dorado Hills, El Dorado 3 El Granada, San Mateo 14 El Mirage, San Bernardino E 14 El Mirage Lake, San Bernardino 9 El Monte, Los Angeles 12 El Nido, Merced 4 El Paso de Robles, San Luis Obispo 14 El Paso Mountains, Kern 16 El Portal, Mariposa 6 El Rio, Ventura 6 El Segundo, Los Angeles 3 El Sobrante, Contra Costa 8 El Toro, Orange 2 El Verano, Sonoma 11 Elders Corner, Placer 13 Elderwood, Tulare 12 Electra Power House, Amador 16 Elizabeth Lake Canyon, Los Angeles 1 Elk, Mendocino 13 Elk Bayou, Tulare 11 Elk Creek, Glenn 12 Elk Grove, Sacramento 1 Elk River, Humboldt 1 Elk River (North Fork), Humboldt 1 Elk River (South Fork), Humboldt 16 Elk Valley, Del Norte 3 Elkhorn Slough, Monterey 12 Elmira, Solano 10 Elsinore, Riverside 12 Elverta, Sacramento 6 Emerald Bay, Orange 14 Emerson Lake, San Bernardino 3 Emeryville, Alameda 16 Emigrant Canyon, Inyo 16 Emigrant Gap, Placer 12 Empire, Stanislaus 10 Encanto, San Diego 7 Encinitas, San Diego 9 Encino, Los Angeles 11 Enterprise, Shasta 16 Erickson, Siskiyou 12 Escalon, San Joaquin 10 Escondido, San Diego 12 Esparto, Yolo 14 Essex, San Bernardino 5 Estero Bay, San Luis Obispo 4 Estrella, San Luis Obispo 4 Estrella River, San Luis Obispo 10 Etiwanda, San Bernardino 16 Etna, Siskiyou 16 Etsel Ridge, Mendocino 1 Ettersburg, Humboldt 12 Eugene, Stanislaus 1 Eureka, Humboldt 16 Eureka Valley, Inyo 13 Exeter, Tulare 12 Fair Oaks, Sacramento 2 Fairfax, Marin 12 Fairfield, Solano 13 Fairmead, Madera 14 Fairmont, Los Angeles 16 Fairview, Tulare F February 25, 2010 D-18 Version 1.1

268 2 Fairville, Sonoma 16 Fales Hot Springs, Mono 1 Falk, Humboldt 16 Fall River, Shasta 16 Fall River Mills, Shasta 10 Fallbrook, San Diego 16 Fallen Leaf Lake, El Dorado 3 Fallon, Marin 13 Famoso, Kern 16 Fandango Pass, Modoc 1 Farallon Island, San Francisco 13 Farmersville, Tulare 12 Farmington, San Joaquin 16 Fawnskin, San Bernardino 16 Feather Falls, Butte 11 Feather River, Sutter 16 Feather River (Middle Fork), Butte 16 Feather River (North Fork), Butte 13 Fellows, Kern 3 Felton, Santa Cruz 14 Fenner, San Bernardino 14 Fenner Valley, San Bernardino 15 Ferguson Lake, Imperial 11 Fern, Shasta 1 Fernbridge, Humboldt 10 Fernbrook, San Diego 1 Ferndale, Humboldt 12 Fiddletown, Amador 1 Fieldbrook, Humboldt 1 Fields Landing, Humboldt 13 Figarden, Fresno 9 Fillmore, Ventura 2 Finley, Lake 13 Firebaugh, Fresno 16 Fish Camp, Mariposa 16 Fish Springs, Inyo 13 Five Points, Fresno 16 Fleming Fish & Game, Lassen 16 Fletcher, Modoc 8 Florence, Los Angeles 16 Florence Lake, Fresno 16 Florence Peak, Tulare 12 Florin, Sacramento 16 Floriston, Nevada 11 Flournoy, Tehama 14 Flynn, San Bernardino 12 Folsom, Sacramento 10 Fontana, San Bernardino 12 Foothill Farms, Sacramento 16 Forbestown, Butte 13 Ford City, Kern 15 Ford Dry Lake, Riverside 16 Forest, Sierra 16 Forest Falls, San Bernardino 16 Forest Glen, Trinity 16 Forest Hill Divide, Placer 3 Forest Knolls, Marin 16 Forest Ranch, Tehama 16 Foresthill, Placer 2 Forestville, Sonoma 16 Forks of Salmon, Siskiyou 3 Fort Baker, Marin 16 Fort Bidwill, Modoc 1 Fort Bragg, Mendocino 1 Fort Dick, Del Norte 16 Fort Goff, Siskiyou 16 Fort Jones, Siskiyou 7 Fort MacArthur, San Diego 3 Fort Ord, Monterey 1 Fort Ross, Sonoma 2 Fort Seward, Humboldt 1 Fortuna, Humboldt 14 Fossil Canyon, San Bernardino 3 Foster City, San Mateo 13 Fountain Springs, Tulare 13 Fountain Springs Gulch, Tulare 6 Fountain Valley, Orange 12 Fourth Crossing, Calaveras 11 Fouts Springs, Colusa 13 Fowler, Fresno 5 Foxen Canyon, Santa Barbara 12 Franklin, Sacramento 14 Franklin Well, Inyo 16 Frazier Mountain, Ventura 16 Frazier Park, Kern 16 Fredonyer Peak, Lassen 3 Freedom, Santa Cruz 16 Freel Peak, Alpine/El Dorado 14 Freeman Junction, Kern 12 Freeport, Sacramento 2 Freestone, Sonoma 3 Fremont, Alameda 14 Fremont Peak, San Bernardino 14 Fremont Valley, Kern 14 Fremont Wash, San Bernardino 12 French Camp, San Joaquin 11 French Corral, Nevada 11 French Gulch, Shasta 16 Frenchman Lake, Plumas 1 Freshwater, Humboldt 13 Fresno, Fresno 13/16 Fresno County 13 Fresno Slough, Fresno 13 Friant, Fresno 13 Friant Dam, Madera 14 Fried Liver Wash, Riverside 15 Frink, Imperial 11 Fruto, Glenn 8 Fullerton, Orange 2 Fulton, Sonoma 14 Funeral Park, Inyo 14 Furnace Creek Wash, Inyo 12 Galt, Sacramento 16 Ganns, Calaveras 2 Garberville, Humboldt 12 Garden Acres, San Joaquin 8 Garden Grove, Orange 12 Garden Valley, El Dorado 8 Gardena, Los Angeles 5 Garey, Santa Barbara 14 Garlock, Kern G February 25, 2010 D-19 Version 1.1

269 11 Gas Point, Shasta 16 Gasquet, Del Norte 6 Gaviota, Santa Barbara 6 Gaviota Pass, Santa Barbara 16 Gazelle, Siskiyou 16 Genesee, Plumas 14 George A.F.B., San Bernardino 12 Georgetown, El Dorado 11 Gerber, Tehama 2 Geyserville, Sonoma 16 Giant Forest, Tulare 16 Gibson Peak, Trinity 16 Gibsonville, Sierra 12 Gillespie Field, Solano 10 Gillman Hot Springs, Riverside 4 Gilroy, Santa Clara 11 Girvan, Shasta 16 Glacier, Inyo 15 Glamis, Imperial 14 Glasgow, San Bernardino 16 Glass Mountain, Mono 10 Glen Avon, Riverside 2 Glen Ellen, Sonoma 16 Glenburg, Shasta 12 Glencoe, Calaveras 9 Glendale, Los Angeles 9 Glendora, Los Angeles 2 Glenhaven, Lake 11 Glenn, Glenn 11 Glenn Colusa Canal, Colusa 16/11 Glenn County 16 Glennville, Kern 14 Goffs, San Bernardino 16 Gold Canyon, Kern 15 Gold Rock Rch, Imperial 16 Gold Run, Placer 3 Golden Gate, San Francisco Marin 16 Golden Hills, Kern 14 Goldstone, San Bernardino 14 Goldstone Lake, San Bernardino 6 Goleta, Santa Barbara 3 Gonzales, Monterey 16 Goodyears Bar, Sierra 16 Goose Lake, Modoc 16 Goosenest, Siskiyou 3 Gorda, Monterey 16 Gordon Mountain, Del Norte 15 Gordons Well, Imperial 16 Gorman, Los Angeles 13 Goshen, Tulare 16 Goumaz, Lassen 9 Granada Hills, Los Angeles 10 Grand Terrace, San Bernardino 13 Grangeville, Kings 11 Granite Bay, Placer 16 Granite Chief, Placer 14 Granite Mountains, San Bernardino 11 Graniteville, Nevada 16 Grant Grove, Tulare 16 Grant Lake, Mono 13 Grapevine, Kern 16 Grass Lake, Siskiyou 11 Grass Valley, Nevada 2 Graton, Sonoma 12 Grayson, Stanislaus 16 Green Valley, Los Angeles 16 Green Valley Lake, San Bernardino 13 Greenacres, Kern 13 Greenfield, Kern 4 Greenfield, Monterey 16 Greenhorn Mountains, Kern/Tulare 16 Greenview, Siskiyou 16 Greenville, Plumas 14 Greenwater Range, Inyo 12 Greenwood, El Dorado 11 Greenwood, Glenn 16 Grenada, Siskiyou 11 Gridley, Butte 11 Grimes, Colusa 12 Grizzly Bay, Solano 16 Grizzly Flat, El Dorado 15 Grommet, San Bernardino 7 Grossmont, San Diego 16 Grouse Mountain, Modoc 12 Groveland, Tuolumne 5 Grover Beach, San Luis Obispo 5 Grover City, San Luis Obispo 16 Grover Hot Springs, Alpine 5 Guadalupe, Santa Barbara 1 Gualala, Mendocino 1 Gualala River (South Fork), Mendocino 14 Guatay, San Diego 2 Guerneville, Sonoma 13 Guernsey, Kings 12 Guinda, Yolo 3 Gulf of the Farallones, Marin/San Francisco 12 Gustine, Merced 2 Hacienda, Sonoma 9 Hacienda Heights, Los Angeles 16 Hackamore, Modoc 16 Haiwee Reservoir, Inyo 1 Hales Grove, Mendocino 16 Half Dome, Mariposa 3 Half Moon Bay, San Mateo 14 Halloran Springs, San Bernardino 16 Halls Flat, Lassen 16 Hambone, Siskiyou 16 Hamburg, Siskiyou 2 Hamilton A.F.B., Marin 11 Hamilton City, Glenn 11 Hammonton, Yuba 13 Hanford, Kings 16 Happy Camp, Siskiyou 10 Harbinson Canyon, San Diego 6 Harbor City, Los Angeles 16 Harden Flat, Tuolumne 13 Hardwick, Kings 5 Harmony, San Luis Obispo 14 Harper Lake, San Bernardino 2 Harris, Humboldt 14 Hart, San Bernardino H February 25, 2010 D-20 Version 1.1

270 16 Hat Creek, Shasta 16 Hathaway Pines, Calaveras 15 Havasu Lake, San Bernardino 16 Havilah, Kern 8 Hawaiian Gardens, Los Angeles 14 Hawes, San Bernardino 16 Hawkinsville, Siskiyou 8 Hawthorne, Los Angeles 16 Hayden Hill, Lassen 14 Hayfield, Riverside 14 Hayfield Lake, Riverside 16 Hayfork, Trinity 16 Hayfork Bally, Trinity 3 Hayward, Alameda 2 Healdsburg, Sonoma 2 Hearst, Mendocino 15 Heber, Imperial 14 Hector, San Bernardino 16 Helena, Trinity 14 Helendale, San Bernardino 13 Helm, Fresno 10 Hemet, Riverside 2 Henderson Village, San Joaquin 11 Henleyville, Tehama 10 Henshaw Dam, San Diego 12 Herald, Sacramento 3 Hercules, Contra Costa 16 Herlong, Lassen 6 Hermosa Beach, Los Angeles 13 Herndon, Fresno 14 Hesperia, San Bernardino 12 Hetch Hetchy Junction, Tuolumne 16 Hetch Hetchy Reservoir, Tuolumne 14 Hi Vista, Los Angeles 12 Hickman, Stanislaus 9 Hidden Hills, Los Angeles 16 Hidden Springs, Los Angeles 11 Hidden Valley, Placer 11 Higgins Corner, Nevada 11 High Peak, Glenn 10 Highgrove, Riverside 10 Highland, San Bernardino 9 Highland Park, Los Angeles 16 Highland Peak, Alpine 13 Highway City, Fresno 16 Hillcrest Center, Kern 12 Hills Ferry, Stanislaus 3 Hillsborough, San Mateo 12 Hilmar, Merced 16 Hilt, Siskiyou 14 Hinkley, San Bernardino 1 Hiouchi, Del Norte 16 Hobart Mills, Nevada 2 Hobergs, Lake 14 Hodge, San Bernardino 4 Hog Canyon, San Luis Obispo 16 Hollenbeck, Modoc 4 Hollister, San Benito 9 Hollywood, Los Angeles 6 Hollywood-by-the-Sea, Ventura 1 Holmes, Humboldt 12 Holt, San Joaquin 15 Holtville, Imperial 10 Home Gardens, Riverside 10 Homeland, Riverside 14 Homer, San Bernardino 14 Homer Wash, San Bernardino 16 Homewood, Placer 11 Honcut, Butte 5 Honda, Santa Barbara 16 Honey Lake, Lassen 1 Honeydew, Humboldt 12 Honker Bay, Solano 12 Hood, Sacramento 11 Hooker, Tehama 2 Hoopa, Humboldt 12 Hopeton, Merced 2 Hopland, Mendocino 16 Hornbrook, Siskiyou 12 Hornitos, Mariposa 16 Horse Creek, Siskiyou 16 Horse Flat, Del Norte 16 Horse Lake, Lassen 16 Hotlum, Siskiyou 5 Huasna, San Luis Obispo 5 Huasna River, San Luis Obispo 12 Hughson, Stanislaus 1 Humboldt Bay, Humboldt 1/2/16 Humboldt County 16 Hume, Fresno 13 Humphreys Station, Fresno 6 Huntington Beach, Orange 16 Huntington Lake, Fresno 8 Huntington Park, Los Angeles 1 Hupa Mountain, Humboldt 13 Huron, Fresno 16 Hyampom, Trinity 1 Hydesville, Humboldt 1 Idlewild, Del Norte 4 Idria, San Benito 16 Idyllwild, Riverside 11 Igo, Shasta 15 Imperial, Imperial 7 Imperial Beach, San Diego 14/15 Imperial County 15 Imperial Dam, Imperial 15 Imperial Reservoir, Imperial 15 Imperial Valley, Imperial 15 Inca, Riverside 16 Independence, Inyo 15 Indian Wells, Riverside 14 Indian Wells Valley, Kern 15 Indio, Riverside 9 Industry, Los Angeles 1 Inglenook, Mendocino 8 Inglewood, Los Angeles 12 Ingomar, Merced 11 Ingot, Shasta 16 Inskip, Butte 11 Inskip Hill, Tehama 3 Inverness, Marin I February 25, 2010 D-21 Version 1.1

271 11 Inwood, Shasta 14/16 Inyo County 16 Inyo Mountains, Inyo 14 Inyokern, Kern 12 Ione, Amador 16 Iowa Hill, Placer 15 Iris, Imperial 5 Irish Hills, San Luis Obispo 11 Iron Mountain, Shasta 8 Irvine, Orange 12 Irwin, Merced 9 Irwindale, Los Angeles 16 Isabella Reservoir, Kern 6 Isla Vista, Santa Barbara 2 Island Mountain, Trinity 12 Isleton, Sacramento 13 Ivanhoe, Tulare 14 Ivanpah, San Bernardino 14 Ivanpah Lake, San Bernardino 14 Ivanpah Valley, San Bernardino 13 Ivesta, Fresno 12 Jackson, Amador 16 Jackson Meadows Reservoir, Nevada/Sierra 12 Jacksonville, Tuolumne 14 Jacumba, San Diego 15 Jacumba Mountains, San Diego 5 Jalama, Santa Barbara 13 Jamesan, Fresno 4 Jamesburg, Monterey 12 Jamestown, Tuolumne 10 Jamul, San Diego 16 Janesville, Lassen 13 Jasmin, Kern 15 Java, San Bernardino 16 Jellico, Lassen 1 Jenner, Sonoma 12 Jenny Lind, Calaveras 16 Jerome, Siskiyou 16 Jess Valley, Modoc 2 Jimtown, Sonoma 14 Johannesburg, Kern 16 Johnsondale, Tulare 1 Johnsons, Humboldt 16 Johnstonville, Lassen 16 Johnsville, Plumas 6 John Wayne AP, Orange 4 Jolon, Monterey 16 Jonesville, Butte 11 Josephine, Sutter 14 Joshua Tree, San Bernardino 14 Julian, San Diego 16 Junction City, Trinity 16 June Lake, Mono 14 Juniper Hills, Los Angeles 4 Junipero Serra Peak, Monterey 16 Kalser Peak, Fresno J K 16 Kandra, Modoc 16 Karlo, Lassen 13 Kaweah, Tulare 14 Kaweah River (Middle Fork), Tulare 16 Kearsarge, Inyo 13 Kecks Corner, Kern 16 Keddie, Plumas 16 Keddie Ridge, Plumas 16 Keeler, Inyo 16 Keene, Kern 2 Kekawaka, Trinity 12 Kelsey, El Dorado 2 Kelseyville, Lake 14 Kelso, San Bernardino 14 Kelso Wash, San Bernardino 2 Kentfield, Marin 2 Kenwood, Sonoma 16 Keough Hot Springs, Inyo 16 Kephart, Modoc 13 Kerman, Fresno 13/14/16 Kern County 13 Kern River (South Fork), Kern 13 Kern River Channel, Kings 16 Kernville, Kern 11 Keswick, Shasta 2 Kettenpom, Trinity 13 Kettleman City, Kings 13 Kettleman Hills, Kings 12 Keyes, Stanislaus 4 King City, Monterey 1 King Range, Humboldt 16 Kings Beach, Placer 13 Kings County 13 Kings River, Fresno/Kings 16 Kings River (Middle Fork), Fresno 16 Kings River (North Fork), Fresno 16 Kings River (South Fork), Fresno 13 Kingsburg, Fresno 14 Kingston Peak, San Bernardino 14 Kingston Wash, San Bernardino 16 Kinyon, Siskiyou 11 Kirkville, Sutter 11 Kirkwood, Sutter 13 Kismet, Madera 1 Klamath, Del Norte 1 Klamath Glen, Del Norte 16 Klamath Mountains, Siskiyou 16 Klamath River, Siskiyou 16 Klamathon, Siskiyou 14 Klondike, San Bernardino 1 Kneeland, Humboldt 12 Knights Ferry, Stanislaus 12 Knights Landing, Yolo 12 Knightsen, Contra Costa 16 Knob, Shasta 13 Knowles, Madera 2 Knoxville, Napa 14 Koehn Lake, Kern 1 Korbel, Humboldt 14 Kramer Junction, San Bernardino 16 Kyburz, El Dorado February 25, 2010 D-22 Version 1.1

272 16 L.L. Anderson Reservoir, Placer 11 La Barr, Nevada 9 La Canada Flintridge, Los Angeles 9 La Crescenta, Los Angeles 12 La Grange, Stanislaus 8 La Habra, Orange 8 La Habra Heights, Los Angeles 3 La Honda, San Mateo 7 La Jolla, San Diego 7 La Mesa, San Diego 9 La Mirada, Los Angeles 8 La Palma, Orange 4 La Panza Range, San Luis Obispo 16 La Porte, Plumas 9 La Puente, Los Angeles 15 La Quinta, Riverside 12 La Riviera, Sacramento 3 La Selva Beach, Santa Cruz 9 La Verne, Los Angeles 13 La Vina, Madera 9 Ladera Heights, Los Angeles 12 Lafayette, Contra Costa 6 Laguna Beach, Orange 15 Laguna Dam, Imperial 6/8 Laguna Hills, Orange 6 Laguna Niguel, Orange 16 Lake Almanor, Plumas 16 Lake Alpine, Alpine 16 Lake Arrowhead, San Bernardino 2 Lake Berryessa, Napa 16 Lake Britton, Shasta 5 Lake Cachuma, Santa Barbara 9 Lake Casitas, Ventura 16 Lake City, Modoc 2 Lake County 16 Lake Crowley, Mono 16 Lake Davis, Plumas 12 Lake Del Valley, Alameda 1 Lake Earl, Del Norte 16 Lake Eleanor, Tuolumne 10 Lake Elsinore, Riverside 8 Lake Forest, Orange 15 Lake Havasu, San Bernardino 2 Lake Henessey, Napa 14 Lake Henshaw, San Diego 16 Lake Isabella, Kern 13 Lake Kaweah, Tulare 14 Lake Los Angeles, Los Angeles 10 Lake Mathews, Riverside 12 Lake McClure, Mariposa 2 Lake Mendocino, Mendocino 16 Lake Mountain, Siskiyou 11 Lake Oroville, Butte 10 Lake Perris, Riverside 2 Lake Pillsbury, Lake 16 Lake Spaulding, Nevada 13 Lake Success, Tulare 16 Lake Tahoe, El Dorado/Placer 11 Lake Wyandotte, Butte 16 Lakehead, Shasta L 10 Lakeland Village, Riverside 2 Lakeport, Lake 16 Lakeshore, Fresno 10 Lakeside, San Diego 13 Lakeview, Kern 10 Lakeview, Riverside 2 Lakeville, Sonoma 8 Lakewood, Los Angeles 11 Lamoine, Shasta 13 Lamont, Kern 13 Lanare, Fresno 14 Lancaster, Los Angeles 14 Landers, San Bernardino 14 Lane Mountain, San Bernardino 14 Lanfair Valley, San Bernardino 2 Larksfield-Wikiup, Sonoma 2 Larkspur, Marin 5 Las Cruces, Santa Barbara 7 Las Flores, San Diego 11 Las Plumas, Butte 16 Lassen County 16 Lassen Peak, Shasta 14 Last Chance Canyon, Kern 16 Last Chance Range, Inyo 12 Lathrop, San Joaquin 13 Laton, Fresno 12 Latrobe, El Dorado 16 Lava Beds, Modoc 14 Lavic, San Bernardino 14 Lavic Lake, San Bernardino 8 Lawndale, Los Angeles 16 Laws, Inyo 12 Le Grand, Merced 14 Leach Lake, San Bernardino 16 Leavitt, Lassen 16 Leavitt Peak, Mono/Tuolumne 16 Lebec, Kern 16 Lee Vining, Mono 16 Lee Wash, Inyo 16 Leech Lake Mountain, Mendocino 11 Leesville, Colusa 1 Leggett, Mendocino 7 Lemon Grove, San Diego 13 Lemoncove, Tulare 13 Lemoore, Kings 8 Lennox, Los Angeles 14 Lenwood, San Bernardino 14 Leona Valley, Los Angeles 7 Leucadia, San Diego 16 Lewiston, Trinity 16 Lewiston Lake, Trinity 12 Liberty Farms, Solano 12 Libfarm, Solano 16 Likely, Modoc 11 Lincoln, Placer 12 Lincoln Village, San Joaquin 11 Linda, Yuba 7 Linda Vista, San Diego 13 Lindcove, Tulare 12 Linden, San Joaquin 13 Lindsay, Tulare 16 Litchfield, Lassen February 25, 2010 D-23 Version 1.1

273 14 Little Dixie Wash, Kern 16 Little Grass Valley Reservoir, Plumas 16 Little Kern River, Tulare 16 Little Lake, Inyo 13 Little Panoche, Fresno 1 Little River, Humboldt 1 Little River, Mendocino 14 Little Rock Wash, Los Angeles 16 Little Shasta, Siskiyou 16 Little Shasta River, Siskiyou 16 Little Truckee River, Sierra 16 Little Valley, Lassen 16 Little Walker River, Mono 14 Littlerock, Los Angeles 3 Live Oak, Santa Cruz 11 Live Oak, Sutter 14 Live Oak Springs, San Diego 12 Livermore, Alameda 12 Livingston, Merced 4 Llanada, San Benito 14 Llano, Los Angeles 12 Lockeford, San Joaquin 14 Lockhart, San Bernardino 4 Lockwood, Monterey 16 Loco, Inyo 16 Lodgepole, Lassen 12 Lodi, San Joaquin 11 Lodoga, Colusa 10 Loert Otay Reservoir, San Diego 11 Logandale, Glenn 1 Loleta, Humboldt 10 Loma Linda, San Bernardino 3 Loma Mar, San Mateo 4 Loma Prieta, Santa Clara 11 Loma Rica, Yuba 6 Lomita, Los Angeles 16 Lomo, Butte 11 Lomo, Sutter 5 Lompoc, Santa Barbara 16 Lone Pine, Inyo 16 Lone Tree Canyon, Kern 16 Long Barn, Tuolumne 6/8 Long Beach, Los Angeles 2 Longvale, Mendocino 4 Lonoak, Monterey 16 Lookout, Modoc 16 Lookout Junction, Modoc 11 Loomis, Placer 16 Loon Lake Reservoir, El Dorado 5 Lopez Lake, San Luis Obispo 16 Loraine, Kern 8 Los Alamitos, Orange 5 Los Alamos, Santa Barbara 4 Los Altos, Santa Clara 4 Los Altos Hills, Santa Clara 8/9 Los Angeles, Los Angeles 6/8/9/14/16 Los Angeles County 12 Los Banos, Merced 12 Los Banos Reservoir, Merced 5 Los Berros Canyon, San Luis Obispo 4 Los Gatos, Santa Clara 11 Los Molinoss, Tehama 9 Los Nietos, Los Angeles 5 Los Olivos, Santa Barbara 5 Los Osos, San Luis Obispo 10 Los Serranos, San Bernardino 13 Lost Hills, Kern 16 Lost River, Modoc 16 Lostman Spring, Inyo 12 Lotus, El Dorado 16 Lower Bear River Reservoir, San Diego 16 Lower Klamath Lake, Siskiyou 2 Lower Lake, Lake 16 Lower Lake, Modoc 11 Lowrey, Tehama 16 Loyalton, Sierra 2 Lucas Vly-Marinwood, Sonoma 2 Lucerne, Lake 14 Lucerne Lake, San Bernardino 14 Lucerne Valley, San Bernardino 3 Lucia, Monterey 14 Ludlow, San Bernardino 8 Lynwood, Los Angeles 16 Lyonsville, Tehama 16 Lytle Creek, San Bernardino 2 Lytton, Sonoma 16 Macdoel, Siskiyou 16 Madeline, Lassen 16 Madeline Plains, Lassen 13 Madera, Madera 13 Madera Acres, Madera 13 Madera Canal, Madera 13/16 Madera County 12 Madison, Yolo 11 Magalia, Butte 2 Mail Ridge, Humboldt 13 Malaga, Fresno 6 Malibu, Los Angeles 16 Mammoth, Modoc 16 Mammoth Lakes, Mono 16 Mammoth Pool Reservoir, Fresno/Madera 15 Mammoth Wash, Imperial 1 Manchester, Mendocino 6 Manhattan Beach, Los Angeles 14 Manix, San Bernardino 16 Manley Peak, Inyo 12 Manteca, San Joaquin 16 Manton, Tehama 16 Manzanita Lake, Shasta 1 Maple Creek, Humboldt 16 Marble Canyon, Inyo 10 March A.F.B., Riverside 3 Mare Island Naval Facility, Solano 10 Margarita Peak, San Diego 13 Maricopa, Kern 3 Marin City, Marin 2/3 Marin County 3 Marina, Monterey 9 Marina del Rey, Los Angeles 12 Mariposa, Mariposa 12/16 Mariposa County M February 25, 2010 D-24 Version 1.1

274 16 Markleeville, Alpine 2 Markley Cove, Napa 1 Marshall, Marin 12 Martell, Amador 12 Martinez, Contra Costa 15 Martinez Canyon, Riverside 11 Marysville, Yuba 16 Mason Station, Lassen 16 Massack, Plumas 16 Mather, Tuolumne 12 Mather Air Force Base, Sacramento 11 Matheson, Shasta 16 Matterhorn Peak, Mono/Tuolumne 1 Mattole River, Humboldt 1 Mattole River (North Fork), Humboldt 1 Mattole River (South Fork), Humboldt 11 Maxwell, Colusa 16 May, Siskiyou 2 Mayacmas Mountains, Lake/Mendocino 8 Maywood, Los Angeles 16 McArthur, Modoc 16 McArthur, Shasta 2 McCann, Humboldt 12 McClellan Air Force Base, Sacramento 16 McCloud, Siskiyou 16 McCloud River, Shasta 15 McCoy Wash, Riverside 16 McDonald Peak, Lassen 13 McFarland, Kern 16 McGee Canyon, Mono 1 McKinleyville, Humboldt 13 McKittrick, Kern 4 McMillan Canyon, San Luis Obispo 16 Meadow Lakes, Fresno 16 Meadow Valley, Plumas 11 Meadow Vista, Placer 16 Meares, Modoc 15 Mecca, Riverside 16 Meeks Bay, El Dorado 9/16 Meiners Oaks, Ventura 16 Meiss Lake, Siskiyou 12 Melones Reservoir, Calaveras/Tuolumne 1 Mendocino, Mendocino 1/2/16 Mendocino County 13 Mendota, Fresno 3 Menlo Park, San Mateo 10 Mentone, San Bernardino 12 Merced, Merced 12 Merced County 12 Merced Falls, Merced 12 Merced River, Merced 16 Merced River (South Fork), Mariposa 11 Meridian, Sutter 11 Merle Collins Reservoir, Yuba 14 Mesa Grande, San Diego 15 Mesaville, Riverside 14 Mesquite Lake, San Bernardino 13 Mettler, Kern 4 Metz, Monterey 16 Meyers, El Dorado 16 Michigan Bluff, Placer 16 Middle Alkali Lake, Modoc 12 Middle River, San Joaquin 12 Middle River Town, San Joaquin 16 Middle Tuolumne River, Tuolumne 11 Middle Yuba River, Nevada/Yuba 2 Middletown, Lake 15 Midland, Riverside 16 Midpines, Mariposa 12 Midway, Alameda 14 Midway, San Bernardino 14 Midway Well, Inyo 16 Milford, Lassen 16 Mill Creek, Tehama 3 Mill Valley, Marin 3 Millbrae, San Mateo 14 Miller Spring, Inyo 13 Millerton Lake, Fresno/Madera 15 Milligan, San Bernardino 11 Millville, Shasta 13 Milo, Tulare 4 Milpitas, Santa Clara 12 Milton, Calaveras 2 Mina, Mendocino 16 Mineral, Tehama 16 Mineral King, Tulare 14 Minneola, San Bernardino 9 Mira Canyon, Los Angeles 10 Mira Loma, Riverside 16 Miracle Hot Springs, Kern 3 Miramar, San Mateo 7 Miramar Naval Air Station, San Diego 13 Miramonte, Fresno 2 Miranda, Humboldt 7 Mission Bay, San Diego 8 Mission Viejo, Orange 14 Mitchell Caverns, San Bernardino 12 Mi-Wuk Village, Tuolumne 16 Moccasin, Plumas 12 Moccasin, Tuolumne 12 Modesto, Stanislaus 12 Modesto Reservoir, Stanislaus 8 Modjeska, Orange 16 Modoc County 4 Moffett Field Naval Air Station, Santa Clara 14 Mojave, Kern 14 Mojave River, San Bernardino 14 Mojave River Forks Reservoir, San Bernardino 12 Mokelumne Hill, Calaveras 12 Mokelumne River, San Joaquin 13 Monmouth, Fresno 16 Mono County 16 Mono Hot Springs, Fresno 16 Mono Lake, Mono 16 Monolith, Kern 9 Monrovia, Los Angeles 13 Monson, Tulare 4 Monta Vista, Santa Clara 16 Montague, Siskiyou 6 Montalvo, Ventura 3 Montara, San Mateo 10 Montclair, San Bernardino 6 Monte Nido, Los Angeles 2 Monte Rio, Sonoma February 25, 2010 D-25 Version 1.1

275 4 Monte Sereno, Santa Clara 9 Montebello, Los Angeles 6 Montecito, Santa Barbara 3 Monterey, Monterey 3 Monterey Bay, Monterey/Santa Cruz 3/4 Monterey County 9 Monterey Park, Los Angeles 12 Montezuma, Solano 12 Montezuma Slough, Solano 16 Montgomery Creek, Shasta 2 Monticello Dam, Solano 12 Montpelier, Stanislaus 9 Montrose, Los Angeles 14 Monument Peak, San Diego 16 Moon Lake, Lassen 9 Moorpark, Ventura 12 Morada, San Joaquin 12 Moraga, Contra Costa 4 Morales Canyon, San Luis Obispo 14 Morena VIllage, San Diego 10 Moreno Valley, Riverside 4 Morgan Hill, Santa Clara 12 Mormon Bar, Mariposa 12 Mormon Slough, San Joaquin 14 Morongo Valley, San Bernardino 11 Morrison Slough, Sutter 5 Morro Bay, San Luis Obispo 3 Moss Beach, San Mateo 3 Moss Landing, Monterey 16 Mount Baldy, San Bernardino 12 Mount Bullion, Mariposa 3 Mount Carmel, Monterey 16 Mount Center, Riverside 16 Mount Darwin, Fresno/Inyo 12 Mount Diablo, Contra Costa 16 Mount Eddy, Siskiyou/Trinity 3 Mount Eden, Alameda 4 Mount Hamilton, Santa Clara 16 Mount Hebron, Siskyou 3 Mount Hermon, Santa Clara 16 Mount Hoffman, Siskiyou 2 Mount Konocti, Lake 14 Mount Laguna, San Diego 2 Mount Lassic, Humboldt 16 Mount Lyell, Madera/Mono 16 Mount Morgan, Inyo 16 Mount Patterson, Mono 16 Mount Pinchot, Fresno 16 Mount Pinos, Ventura 2 Mount Saint Helena, Napa/Sonoma 16 Mount San Antonio, Los Angeles/ San Bernardino 16 Mount San Jacinto, Riverside 16 Mount Shasta, Siskiyou 15 Mount Signal, Imperial 16 Mount Vida, Modoc 16 Mount Whitney, Inyo/Tulare 16 Mount Wilson, Los Angeles 11 Mountain Gate, Shasta 16 Mountain Meadows Reservoir, Lassen 14 Mountain Pass, San Bernardino 12 Mountain Ranch, Calaveras 15 Mountain Spring, Imperial 4 Mountain View, Santa Clara 16 Mugginsville, Siskiyou 12 Murphys, Calaveras 10 Murrieta, Riverside 10 Muscoy, San Bernardino 2 Myers Flat, Humboldt 4 Nacimiento Reservoir, San Luis Obispo 4 Nacimiento River, San Luis Obispo 2 Napa, Napa 2 Napa County 2 Napa Junction, Napa 6 Naples, Santa Barbara 2 Nashmead, Mendocino 7 National City, San Diego 2 Navarro, Mendocino 13 Navelencia, Fresno 15 Needles, San Bernardino 11 Nelson, Butte 14 Neuralia, Kern 11 Nevada City, Nevada 11/16 Nevada County 4 New Almaden, Santa Clara 13 New Auberry, Fresno 16 New Bullards Bar Reservoir, Yuba 4 New Cuyama, Santa Barbara 12 New Don Pedro Reservoir, Tuolumne 12 New Exchequer Dam, Mariposa 12 New Hogan Reservoir, Calaveras 13 New London, Tulare 16 New River, Trinity 3 Newark, Alameda 14 Newberry Springs, San Bernardino 9 Newbury Park, Ventura 11 Newcastle, Placer 16 Newell, Modoc 9 Newhall, Los Angeles 12 Newman, Stanislaus 6 Newport Bay, Orange 6 Newport Beach, Orange 11 Newville, Glenn 2 Nicasio, Marin 2 Nice, Lake 15 Nicholls Warm Springs, Riverside 11 Nicolaus, Sutter 16 Nightingale, Riverside 15 Niland, Imperial 12 Nimbus, Sacramento 5 Nipomo, San Luis Obispo 13 Nippinnawasee, Madera 14 Nipton, San Bernardino 14 Nopah Range, Inyo 10 Norco, Riverside 11 Nord, Butte 16 Norden, Nevada 11 North Auburn, Placer 16 North Bloomfield, Nevada 11 North Columbia, Nevada 14 North Edwards, Kern 16 North Fork, Madera N February 25, 2010 D-26 Version 1.1

276 12 North Highlands, Sacramento 9 North Hollywood, Los Angeles 15 North Palm Springs, Riverside 12 North Sacramento, Sacramento 11 North San Juan, Nevada 16 North Yolla Bolly Mountains, Tehama 11 North Yuba River, Yuba 9 Northridge, Los Angeles 2 Northspur, Mendocino 10 Norton AFB, San Bernardino 16 Norvell, Lassen 8 Norwalk, Los Angeles 3 Notleys Landing, Monterey 2 Novato, Marin 16 Nubieber, Lassen 10 Nuevo, Riverside 14 Oak Grove, San Diego 9 Oak Ridge, Ventura 11 Oak Run, Shasta 9 Oak View, Ventura 12 Oakdale, Stanislaus 13 Oakhurst, Madera 3 Oakland AP, Alameda 12 Oakley, Contra Costa 2 Oakville, Napa 16 Oasis, Mono 15 Oasis, Riverside 16 Obie, Shasta 11 O'Brien, Shasta 16 Observation Peak, Lassen 2 Occidental, Sonoma 7 Ocean Beach, San Diego 6 Ocean View, Sonoma 5 Oceano, San Luis Obispo 7 Oceanside, San Diego 15 Ocotillo, Imperial 15 Ocotillo Wells, San Diego 15 Ogilby, Imperial 13 Oildale, Kern 13 Oilfields, Fresno 9 Ojai, Ventura 16 Olancha, Inyo 16 Olancha Peak, Inyo/Tulare 14 Old Dale, San Bernardino 13/16 Old River, Contra Costa/San Joaquin 13 Old River, Kern 16 Old Station, Shasta 3 Olema, Marin 11 Olinda, Shasta 11 Olivehurst, Yuba 16 Omo Ranch, El Dorado 13 O'Neals, Madera 12 O'Neill Forebay, Merced 11 Ono, Shasta 10 Ontario, San Bernardino 16 Onyx, Kern 3 Opal Cliffs, Santa Cruz 8 Orange, Orange 6/8 Orange County O 13 Orange Cove, Fresno 12 Orangevale, Sacramento 13 Orchard Peak, Kern 5 Orcutt, Santa Barbara 14 Ord Mountain, San Bernardino 11 Ordbend, Glenn 11 Oregon House, Yuba 16 Oregon Peak, Yuba 12 Orestimba Peak, Stanislaus 1 Orick, Humboldt 12 Orinda, Contra Costa 15 Orita, Imperial 11 Orland, Glenn 2 Orleans, Humboldt 16 Oro Fino, Siskiyou 14 Oro Grande, San Bernardino 14 Oro Grande Wash, San Bernardino 13 Oro Loma, Fresno 13 Orosi, Tulare 11 Oroville, Butte 11 Oroville East, Butte 7 Otay, San Diego 12 Outingdale, El Dorado 16 Owens Lake, Inyo 16 Owens River, Inyo 16 Owens Valley, Inyo 16 Owenyo, Inyo 14 Owlshead Mountains, Inyo/San Bernardino 13 Oxalis, Fresno 12 Oxford, Solano 6 Oxnard, Ventura 6 Oxnard Beach, Ventura 12 Pacheco, Contra Costa 4 Pacheco Pass, Santa Clara 16 Pacific, El Dorado 7 Pacific Beach, San Diego 3 Pacific Grove, Monterey 6 Pacific Palisades, Los Angeles 3 Pacifica, San Mateo 9 Pacoima, Los Angeles 16 Pacoima Canyon, Los Angeles 14 Pahrump Valley, Inyo 4 Paicines, San Benito 16 Paiute Canyon, Inyo 10 Pala, San Diego 15 Palen Lake, Riverside 15 Palen Mountains, Riverside 11 Palermo, Butte 15 Palm Canyon, Riverside 7 Palm City, San Diego 15 Palm Desert, Riverside 15 Palm Desert Country, Riverside 15 Palm Springs, Riverside 15 Palm Wash, Imperial 14 Palm Wells, San Bernardino 14 Palmdale AP, Los Angeles 4 Palo Alto, Santa Clara 11 Palo Cedro, Shasta 15 Palo Verde, Imperial P February 25, 2010 D-27 Version 1.1

277 15 Palo Verde Valley, Riverside 12 Paloma, Calaveras 14 Palomar Mountain, San Diego 6 Palos Verdes Estates, Los Angeles 16 Panamint, Inyo 14/16 Panamint Range, Inyo 16 Panamint Springs, Inyo 16 Panamint Valley, Inyo 4 Panoche, San Benito 9 Panorama City, Los Angeles 11 Paradise, Butte 4 Paraiso Springs, Monterey 8 Paramount, Los Angeles 12 Pardee Reservoir, Amador/ Calaveras 15 Parker Dam, San Bernardino 4 Parkfield, Monterey 12 Parkway-South Sacramento, Sacramento 13 Parlier, Fresno 9 Pasadena, Los Angeles 11 Paskenta, Tehama 4 Paso Robles AP, San Luis Obispo 16 Patrick Creek, Del Norte 1 Patricks Point, Humboldt 12 Patterson, Stanislaus 12 Paulsell, Stanislaus 10 Pauma Valley, San Diego 16 Paxton, Plumas 11 Paynes Creek, Tehama 16 Peanut, Trinity 14 Pearblossom, Los Angeles 14 Pearland, Los Angeles 3 Pebble Beach, Monterey 10 Pedley, Riverside 7 Pendleton M.C.B., San Diego 11 Penn Valley, Nevada 2 Penngrove, Sonoma 11 Pennington, Sutter 11 Penryn, Placer 11 Pentz, Butte 1 Pepperwood, Humboldt 16 Perez, Modoc 10 Perris, Riverside 3 Pescadero, San Mateo 2 Petaluma, Sonoma 2 Petaluma River, Marin/Sonoma 12 Peters, San Joaquin 1 Petrolia, Humboldt 14 Phelan, San Bernardino 2 Phillipsville, Humboldt 2 Philo, Mendocino 15 Picacho, Imperial 15 Picacho Wash, Imperial 9 Pico Rivera, Los Angeles 3 Piedmont, Alameda 13 Piedra PO, Fresno 16 Pierce, Siskiyou 2 Piercy, Mendocino 2 Pieta, Mendocino 3/4 Pigeon Point, San Mateo 3 Pillar Point, San Mateo 12 Pilot Hill, El Dorado 16 Pilot Peak, Mariposa/Tuolumne 11 Pilot Peak, Nevada 16 Pilot Peak, Plumas 13 Pine Canyon, Fresno 4 Pine Canyon, Monterey 4 Pine Canyon, San Luis Obispo 5 Pine Canyon, Santa Barbara 16 Pine Flat, Tulare 12 Pine Grove, Amador 4 Pine Mountain, San Luis Obispo 16 Pine Mountain, Ventura 16 Pine Ridge, Fresno 14 Pine Valley, San Diego 16 Pinecrest, Tuolumne 13 Pinedale, Fresno 13/16 Pinehurst, Fresno 15 Pinkham Wash, Riverside 14 Pinnacles NM, San Bernardino 3 Pinole, Contra Costa 14 Pinon Hills, San Bernardino 14 Pinto Mountains, Riverside 15 Pinto Wash, Imperial 15 Pinto Wash, Riverside 16 Pioneer, Amador 14 Pioneer Point, San Bernardino 14 Pioneertown, San Bernardino 14 Pipes Wash, San Bernardino 9 Piru, Ventura 5 Pismo Beach, San Luis Obispo 11 Pit River (North Fork), Modoc 11 Pit River (South Fork), Modoc 11 Pit River (town), Lassen 12 Pittsburg, Contra Costa 16 Pittville, Shasta 14 Piute Valley, San Bernardino 14/15 Piute Wash, San Bernardino 13 Pixley, Tulare 8 Placentia, Orange 11/16 Placer County 12 Placerville, El Dorado 12 Plainsburg, Merced 13 Plainview, Tulare 12 Planada, Merced 1 Plantation, Sonoma 16 Plasse, Amador 15 Plaster City, Imperial 11 Platina, Shasta 16 Pleasant Grove, Inyo 12 Pleasant Hill, Sutter 12 Pleasant Hill, Contra Costa 12 Pleasanton, Alameda 16 Plumas, Lassen 16 Plumas County 12 Plymouth, Amador 1 Point Arena, Mendocino 5 Point Arguello, Santa Barbara 3 Point Bonita, Marin 5 Point Buchon, San Luis Obispo 6 Point Conception, Santa Barbara 1 Point Delgada, Humboldt 6 Point Dume, Los Angeles 6 Point Fermin, Los Angeles 7 Point La Jolla, San Diego February 25, 2010 D-28 Version 1.1

278 3 Point Lobos, Monterey 7 Point Loma, San Diego 6 Point Mugu, Ventura 6 Point Mugu Naval Missile Center, Ventura 5 Point Piedras Blancas, San Luis Obispo 12 Point Pleasant, Sacramento 3 Point Reyes, Marin 3 Point Reyes Station, Marin 1 Point Saint George, Del Norte 5 Point Sal, Santa Barbara 3 Point Sur, Monterey 16 Pollock Pines, El Dorado 9 Pomona, Los Angeles 13 Pond, Kern 16 Pondosa, Siskiyou 2 Pope Valley, Napa 13 Poplar, Tulare 14 Porcupine Wash, Riverside 12 Port Chicago, Contra Costa 6 Port Hueneme, Ventura 13 Porterville, Tulare 16 Portola, Plumas 3 Portola Valley, San Mateo 13 Posey, Tulare 3 Posts, Monterey 14 Potrero, San Diego 2 Potter Valley, Mendocino 10 Poway Valley, San Diego 4 Powell Canyon, Monterey 4 Pozo, San Luis Obispo 10 Prado Flood Control Basin, Riverside/San Bernardino 13 Prather, Fresno 3 Presidio of San Francisco, San Francisco 16 Preston Peak, Siskiyou 4 Priest Valley, Monterey 11 Princeton, Colusa 11 Proberta, Tehama 11 Project City, Shasta 14 Providence Mountains, San Bernardino 3 Prunedale, Monterey 16 Pulga, Butte 16 Purdy, Sierra 5 Purisma Hills, Santa Barbara 12 Putah South Canal, Solano 16 Pyramid Lake, Los Angeles 10 Quail Valley, Riverside 14 Quartz Hill, Los Angeles 15 Quartz Peak, Imperial 16 Quatal Canyon, Ventura 13 Quedow Mountain, Tulare 16 Quincy, Plumas 11 Racherby, Yuba 13 Rag Gulch, Kern 12 Rail Road Flat, Calaveras 10 Railroad Canyon Reservoir, Riverside 10 Rainbow, San Diego Q R 13 Raisin City, Fresno 16 Raker & Thomas Reservoir, Modoc 10 Ramona, San Diego 1 Ranch, Mendocino 14 Ranchita, San Diego 10 Rancho Bernardo, San Diego 12 Rancho Cordova, Sacramento 10 Rancho Cucamonga, San Bernardino 15 Rancho Mirage, Riverside 6 Rancho Palos Verdes,Los Angeles 10 Rancho San Diego, San Diego 7 Rancho Santa Fe, San Diego 8 Rancho Santa Margarita, Orange 14 Randsburg, Kern 16 Ravendale, Lassen 13 Raymond, Madera 11 Red Bank, Tehama 11 Red Bluff, Tehama 16 Red Mountain, Del Norte 14 Red Mountain, San Bernardino 13 Red Top, Madera 16 Red Wall Canyon, Inyo 1 Redcrest, Humboldt 11 Redding, Shasta 10 Redlands, San Bernardino 14 Redman, Los Angeles 6 Redondo Beach, Los Angeles 2 Redway, Humboldt 3 Redwood City, San Mateo 4 Redwood Estates, Santa Clara 2 Redwood Valley, Mendocino 13 Reedley, Fresno 4 Reliz Canyon, Monterey 16 Renegade Canyon, Inyo 1 Requa, Del Norte 12 Rescue, El Dorado 9 Reseda, Los Angeles 3 Reynolds, Mendocino 14 Rhodes Wash, Inyo 10 Rialto, San Bernardino 15 Rice, San Bernardino 15 Rice Valley, Riverside 2 Richardson Grove, Humbolt 11 Richardson Springs, Butte 11 Richfield, Tehama 13 Richgrove, Tulare 3 Richmond, Contra Costa 11 Richvale, Butte 2 Ridge, Mendocino 14 Ridgecrest, Kern 14 Riggs Wash, San Bernardino 3 Rio Del Mar, Santa Cruz 1 Rio Dell, Humboldt 12 Rio Linda, Sacramento 2 Rio Nido, Sonoma 11 Rio Oso, Sutter 12 Rio Vista, Solano 15 Ripley, Riverside 12 Ripon, San Joaquin 13 Ripperdan, Madera 12 River Pines, Amador 16 River Springs Lakes, Mono February 25, 2010 D-29 Version 1.1

279 12 Riverbank, Stanislaus 12 Riverbank Army Depot, Stanislaus 13 Riverdale, Fresno 10 Riverside, Riverside 10/14/15/16 Riverside County 16 Roaring River, Fresno 11 Robbins, Sutter 12 Robla, Sacramento 11 Rocklin, Placer 1 Rockport, Mendocino 12 Rockville, Solano 3 Rodeo, Contra Costa 16 Rogers Lake, Kern 2 Rohnert Park, Sonoma 1 Rohnerville, Humboldt 13 Rolinda, Fresno 6 Rolling Hills, Los Angeles 6 Rolling Hills Estates, Los Angeles 10 Romoland, Riverside 14 Rosamond, Kern 14 Rosamond Lake, Kern/Los Angeles 2 Roseland, Sonoma 9 Rosemead, Los Angeles 12 Rosemont, Sacramento 11 Roseville, Placer 11 Rosewood, Tehama 2 Ross, Marin 8 Rossmoor, Orange 11 Rough and Ready, Nevada 16 Round Mountain, Shasta 16 Rovana, Inyo 9 Rowland Heights, Los Angeles 16 Rubicon River, El Dorado/Placer 10 Rubidoux, Riverside 12 Rumsey, Yolo 16 Running Springs, San Bernardino 16 Russian Peak, Siskiyou 2 Ruth, Trinity 2 Rutherford, Napa 14 Ryan, Inyo 12 Ryde, Sacramento 12 Sacramento AP, Sacramento 12 Sacramento Army Depot, Sacramento 12 Sacramento County 16 Saddle Mountain, El Dorado 10 Sage, Riverside 16 Sage Hen, Lassen 16 Saint Bernard, Tehama 2 Saint Helena, Napa 13 Saint Johns River, Tulare 12 Saint Mary's College, Contra Costa 12 Salida, Stanislaus 3 Salinas, Monterey 16 Saline Valley, Inyo 16 Salmon Mountain, Humboldt/Siskiyou 16 Salmon River, Siskiyou 16 Salmon River (East Fork), Siskiyou 16 Salmon River (North Fork), Siskiyou 16 Salmon River (South Fork), Siskiyou S 16 Salt Lake, Inyo 1 Salt River, Humboldt 16 Salt Springs Reservoir, Amador/Calavaras 12 Salt Springs Valley Reservoir, Calaveras 14 Saltdale, Kern 15 Saltmarsh, San Bernardino 15 Salton City, Imperial 15 Salton Sea, Imperial/Riverside 15 Saltus, San Bernardino 16 Salyer, Trinity 1 Samoa, Humboldt 12 San Andreas, Calaveras 3 San Andreas Lake, San Mateo 2 San Anselmo, Marin 16 San Antonio Canyon, Los Angeles 4 San Antonio Mission, Monterey 12 San Antonio Reservoir, Alameda 4 San Antonio Reservoir, Monterey 4 San Antonio River, Monterey 4 San Antonio River (North Fork), Monterey 4 San Ardo, Monterey 4 San Benito County 4 San Benito, San Benito 4 San Benito Mountain, San Benito 4 San Benito River, San Benito 10 San Bernardino, San Bernardino 10/14/15/16 San Bernardino County 16 San Bernardino Mountains, San Bernardino 3 San Bruno, San Mateo 6 San Buenaventura, Ventura 3 San Carlos, San Mateo 6 San Clemente, Orange 6 San Clemente Island, Los Angeles 7/10 San Diego, San Diego 7 San Diego Bay, San Diego 7/10/14/15 San Diego County 7 San Diego Naval Hospital, San Diego 7 San Diego Naval Station, San Diego 9 San Dimas, Los Angeles 14 San Felipe, San Diego 4 San Felipe, Santa Clara 9 San Fernando, Los Angeles 9 San Fernando Valley, Los Angeles 3 San Francisco, San Francisco 3 San Francisco Bay, San Francisco 3 San Francisco County 9 San Gabriel, Los Angeles 9 San Gabriel Mountains, Los Angeles 16 San Gabriel River (West Fork), Los Angeles 16 San Gorgonio Mountain, San Bernardino 15 San Gorgonio Pass, Riverside 15 San Gorgonio River, Riverside 3 San Gregorio, San Mateo 10 San Jacinto, Riverside 10 San Jacinto Mountains, Riverside 10 San Jacinto River, Riverside 13 San Joaquin, Fresno 12 San Joaquin County 16 San Joaquin River (East Fork), Madera 16 San Joaquin River (Middle Fork), Madera 16 San Joaquin River (North Fork), Madera 16 San Joaquin River (South Fork), Madera February 25, 2010 D-30 Version 1.1

280 16 San Joaquin River (West Fork), Madera 4 San Jose, Santa Clara 4 San Juan Bautista, San Benito 6 San Juan Capistrano, Orange 3 San Leandro, Alameda 3 San Lorenzo, Alameda 3 San Lorenzo River, Santa Cruz 4 San Lucas, Monterey 12 San Luis Holding Reservoir, Merced 5 San Luis Obispo, San Luis Obispo 5 San Luis Obispo Bay, San Luis Obispo 4/5 San Luis Obispo County 7 San Luis Rey, San Diego 7 San Luis Rey River (West Fork), San Diego 10 San Marcos, San Diego 9 San Marino, Los Angeles 4 San Martin, Santa Clara 3 San Mateo, San Mateo 10 San Mateo Canyon, San Diego 3 San Mateo County 4 San Miguel, San Luis Obispo 6 San Miguel Island, Santa Barbara 6 San Nicholas Island, Ventura 7 San Onofre, San Diego 10 San Onofre Canyon, San Diego 3 San Pablo, Contra Costa 10 San Pasqual, San Diego 6 San Pedro, Los Angeles 6 San Pedro Bay, Los Angeles 2 San Quentin, Marin 2 San Rafael, Marin 5 San Rafael Mountain, Santa Barbara 12 San Ramon, Contra Costa 5 San Simeon, San Luis Obispo 10 San Timoteo Canyon, Riverside 10 San Vicente Reservoir, San Diego 7 San Ysidro, San Diego 14 San Ysidro Mountains, San Diego 3 Sand City, Monterey 15 Sand Hills, Imperial 14 Sandberg, Los Angeles 15 Sandia, Imperial 14 Sands, San Bernardino 2 Sanel Mountain, Mendocino 13 Sanger, Fresno 2 Sanitarium, Napa 8 Santa Ana, Orange 6 Santa Barbara, Santa Barbara 4/5/6 Santa Barbara County 6 Santa Barbara Island, Santa Barbara 6 Santa Catalina Island, Los Angeles 4 Santa Clara, Santa Clara 4 Santa Clara County 6/9 Santa Clara River, Ventura 4 Santa Clara Valley, Santa Clara 9 Santa Clarita, Los Angeles 3 Santa Cruz, Santa Cruz 3 Santa Cruz County 6 Santa Cruz Island, Santa Barbara 3 Santa Cruz Mountains, Santa Cruz 9 Santa Fe Springs, Los Angeles 4 Santa Margarita, San Luis Obispo 4 Santa Margarita Lake, San Luis Obispo 5 Santa Maria, Santa Barbara 5 Santa Maria River, San Luis Obispo/Santa Barbara 5 Santa Maria Valley, Santa Barbara 6 Santa Monica, Los Angeles 6 Santa Monica Bay, Los Angeles 6 Santa Monica Mountains, Los Angeles 9 Santa Paula, Ventura 12 Santa Rita Park, Merced 2 Santa Rosa, Sonoma 6 Santa Rosa Islands, Santa Barbara 16 Santa Rosa Mountains, Riverside 9 Santa Susana, Ventura 2 Santa Venetia, Marin 5 Santa Ynez, Santa Barbara 5 Santa Ynez Mountains, Santa Barbara 5 Santa Ynez River, Santa Barbara 14 Santa Ysabel, San Diego 10 Santee, San Diego 8 Santiago Reservoir, Orange 4 Saratoga, Santa Clara 16 Sardine Peak, Sierra 4 Sargent, Santa Clara 4 Sargent Canyon, Monterey 6 Saticoy, Ventura 16 Sattley, Sierra 9 Saugus, Los Angeles 3 Sausalito, Marin 16 Sawtooth Peak, Inyo 16 Sawyers Bar, Siskiyou 16 Scarface, Modoc 16 Scheelite, Inyo 2 Schellville, Sonoma 1 Scotia, Humboldt 16 Scott Bar, Siskiyou 16 Scott Bar Mountains, Siskiyou 16 Scott Mountains, Trinity 16 Scott River, Siskiyou 16 Scott River (East Fork), Siskiyou 16 Scotts, Lassen 3 Scotts Valley, Santa Cruz 16 Scottys Castle, Inyo 6 Sea Cliff, Ventura 6 Seal Beach, Orange 14 Searles, Kern 14 Searles Lake, San Bernardino 3 Seaside, Monterey 2 Sebastopol, Sonoma 15 Seeley, Imperial 16 Seiad Valley, Siskiyou 13 Selma, Fresno 15 Senator Wash, Imperial 16 Seneca, Plumas 9 Sepulveda, Los Angeles 9 Sepulveda Dam, Los Angeles 2 Sequoia, Humboldt 9 Sespe, Ventura 16 Seven Oaks, San Bernardino 14 Shadow Valley, San Bernardino 13 Shafter, Kern 4 Shandon, San Luis Obispo 12 Sharpe Army Depot, San Joaquin February 25, 2010 D-31 Version 1.1

281 11 Shasta, Shasta 11 Shasta Bally, Shasta 11/16 Shasta County 16 Shasta Lake, Shasta 16 Shasta River, Siskiyou 16 Shasta Springs, Siskiyou 16 Shasta Valley, Siskiyou 16 Shaver Lake, Fresno 4 Shedd Canyon, San Luis Obispo 14 Sheep Canyon, Inyo 16 Sheep Mountain, Siskiyou 12 Sheep Ranch, Calaveras 12 Sheldon, Sacramento 1 Shelter Cove, Humboldt 11 Sheridan, Placer 9 Sherman Oaks, Los Angeles 13/16 Sherman Peak, Tulare 12 Shingle Springs, El Dorado 16 Shingletown, Shasta 1 Shively, Humboldt 14 Shoshone, Inyo 14 Sidewinder Mountain, San Bernardino 16 Sierra Army Depot, Lassen 16 Sierra Buttes, Sierra 16 Sierra City, Sierra 16 Sierra County 9 Sierra Madre, Los Angeles 16 Sierra Nevada, Madera 16 Sierra Valley, Plumas/Sierra 16 Sierraville, Sierra 6 Signal Hill, Los Angeles 16 Silver City, Tulare 16 Silver Creek, Fresno 16 Silver Lake, Amador 14 Silver Lake, San Bernardino 8 Silverado, Orange 16 Silverwood Lake, San Bernardino 9 Simi Valley, Ventura 4 Simmler, Simmler 16 Siskiyou County 16 Siskiyou Mountains, Del Norte/Siskiyou 5 Sisquoc, Santa Barbara 5 Sisquoc River, Santa Barbara 11 Sites, Colusa 2 Skaggs Springs, Sonoma 16 Skedaddle Mountains, Lassen 16 Skidoo, Inyo 14 Slate Range, Inyo/San Bernardino 16 Sleepy Valley, Los Angeles 16 Sloat, Plumas 12 Sloughhouse, Sacramento 11 Smartville, Yuba 1/16 Smith River (Middle Fork), Del Norte 1/16 Smith River (North Fork), Del Norte 1/16 Smith River (South Fork), Del Norte 1 Smith River, Del Norte 12 Smithflat, El Dorado 14 Smoke Tree Wash, Riverside 11 Snake River, Sutter 12 Snelling, Merced 16 Snowden, Siskiyou 14 Soda Lake, San Bernardino 4 Soda Lake, San Luis Obispo 14 Soda Mountains, San Bernardino 16 Soda Springs, Nevada 1 Soda Springs, Sonoma 7 Solana Beach, San Diego 3/12 Solano County 3 Soledad, Monterey 9 Solemint, Los Angeles 6 Solromar, Ventura 5 Solvang, Santa Barbara 12 Somerset, El Dorado 16 Somes Bar, Siskiyou 6 Somis, Ventura 2 Sonoma, Sonoma 1/2 Sonoma County 2 Sonoma Mountain, Sonoma 12 Sonora, Tuolumne 16 Sonora Pass, Mono/Tuolumne 3 Soquel, Santa Cruz 12 Soulsbyville, Tuolumne 16 Sourdough Spring, Inyo 12 South Dos Palos, Merced 9 South El Monte, Los Angeles 16 South Entry Yosemite, Tuolumne 1 South Fork, Humboldt 8 South Gate, Los Angeles 6 South Laguna, Orange 16 South Lake Tahoe, El Dorado 11 South Oroville, Butte 9 South Pasadena, Los Angeles 3 South San Francisco, San Mateo 9 South San Gabriel, Los Angeles 12 South Turlock, Stanislaus 9 South Whittier, Los Angeles 16 South Yolla Bolly Mountains, Tehama 11 South Yuba City, Sutter 14 Spangler, San Bernardino 16 Spanish Mountain, Fresno 16 Spanish Spring, Inyo 3 Spence, Monterey 3 Spreckels, Monterey 16 Spring Garden, Plumas 7 Spring Valley, San Diego 13 Springville, Tulare 2 Spyrock, Mendocino 13 Squaw Valley, Fresno 16 Squaw Valley (Olympic Valley), Placer 14 Squirrel Inn, San Bernardino 16 Stacy, Lassen 16 Stampede Reservoir, Sierra 12 Standard, Tuolumne 16 Standish, Lassen 4 Stanford, Santa Clara 12 Stanislaus, Calaveras 12 Stanislaus County 12 Stanislaus River (Middle Fork), Tuolumne 8 Stanton, Orange 12 Stent, Tuolumne 13 Stevens, Kern 12 Stevinson, Merced 1 Stewarts Point,Sonoma 3 Stinson Beach, Marin February 25, 2010 D-32 Version 1.1

282 16 Stirling City, Butte 12 Stockton, San Joaquin 11 Stony Gorge Reservoir, Glenn 11 Stonyford, Colusa 16 Storrie, Plumas 14 Stovepipe Wells, Inyo 13 Stratford, Kings 13 Strathmore, Tulare 16 Strawberry, Tuolumne 16 Strawberry Valley, Yuba 9 Studio City, Los Angeles 3 Suisun Bay, Contra Costa/Solano 12 Suisun City, Solano 9 Sulphur Springs, Ventura 13 Sultana, Tulare 6 Summerland, Santa Barbara 11 Summit City, Shasta 10 Sun City, Riverside 9 Sun Valley, Los Angeles 10 Suncrest, San Diego 9 Sunland, Los Angeles 10 Sunnymead, Riverside 4 Sunnyvale, Santa Clara 4 Sunnyvale Air Force Station, Santa Clara 12 Sunol, Alameda 6 Sunset Beach, Orange 16 Superior Lake, San Bernardino 15 Superstition Mountain, Imperial 5 Surf, Santa Barbara 6 Surfside, Orange 16 Surprise Valley, Modoc 16 Susan River, Lassen 16 Susanville, Lassen 11 Sutter, Sutter 11 Sutter Buttes, Sutter 11 Sutter Bypass, Sutter 11 Sutter County 12 Sutter Creek, Amador 4 Svedal, Santa Clara 3 Swanton, Santa Cruz 7 Sweetwater Reservoir, San Diego 11 Sycamore, Colusa 9 Sylmar, Los Angeles 13 Taft, Kern 13 Taft Heights, Kern 13 Tagus, Tulare 16 Tahoe City, Placer 16 Tahoe Pines, Placer 16 Tahoe Vista, Placer 16 Tahoma, Placer 6 Tajiguas, Santa Barbara 2 Talmage, Mendocino 3 Tamalpais-Homestead Valley, Marin 11 Tambo, Yuba 9 Tarzana, Los Angeles 12 Tassajara, Contra Costa 3 Tassajara Hot Springs, Monterey 2 Tatu, Mendocino 4 Taylor Canyon, San Luis Obispo T 1 Taylor Peak, Humboldt 16 Taylorsville, Plumas 14 Teagle Wash, San Bernardino 16 Teakettle Junction, Inyo 14 Tecate, San Diego 16 Tecnor, Siskiyou 14 Tecopa, Inyo 16 Tehachapi, Kern 16 Tehachapi Mountains, Kern 16 Tehachapi Pass, Kern 11 Tehama, Tehama 11/16 Tehama County 16 Tejon Pass, Los Angeles 16 Tejon Rancho, Los Angeles 16 Telescope Peak, Inyo 10 Temecula, Riverside 10 Temescal Wash, Riverside 9 Temple City, Los Angeles 4 Templeton, San Luis Obispo 16 Tennant, Siskiyou 5 Tepusquet Canyon, Santa Barbara 5 Tequspuet Peak, Santa Barbara 12 Terminous, San Joaquin 13 Terminus Dam, Tulare 16 Termo, Lassen 13 Terra Bella, Tulare 15 Thermal, Riverside 11 Thermalito, Butte 11 Thermalito Afterbay, Butte 11 Thermalito Forebay, Butte 16 Thomas A. Edison Lake, Fresno 16 Thomas Mountain, Riverside 4 Thompson Canyon, Monterey 12 Thornton, San Joaquin 9 Thousand Oaks, Ventura 15 Thousand Palms, Riverside 14 Three Points, Los Angeles 13 Three Rivers, Tulare 13 Three Rocks, Fresno 3 Tiburon, Marin 14 Tiefort Mountains, San Bernardino 14 Tierra del Sol, San Diego 12 Tiger Creek Power House, Amador 11 Tiger Creek Power House, Butte 7 Tijuana River, San Diego 16 Tinemaha Reservoir, Inyo 16 Tioga Pass, Mono/Tuolumne 16 Tionesta, Modoc 13 Tipton, Tulare 16 Titus Canyon, Inyo 16 Tobias Peak, Tulare 13 Tollhouse, Fresno 3 Tomales, Marin 3 Tomales Bay, Marin 16 Toms Place, Mono 6 Topanga, Los Angeles 6 Topanga Beach, Los Angeles 6 Topanga Canyon, Los Angeles 16 Topaz, Mono 16 Topaz Lake, Mono 6 Torrance, Los Angeles 8 Trabuco Canyon, Orange February 25, 2010 D-33 Version 1.1

283 12 Tracy Carbona, San Joaquin 13 Tranquillity, Fresno 13 Traver, Tulare 12 Travis A. F.B., Solano 3 Treasure Island Naval Station, San Francisco 12 Tremont, Solano 4 Tres Pinos, San Benito 13 Trigo, Madera 16 Trimmer, Fresno 1 Trinidad, Humboldt 1 Trinidad Head, Humboldt 16 Trinity Alps, Trinity 16 Trinity Center, Trinity 2/11/16 Trinity County 16 Trinity Dam, Trinity 16 Trinity Mountains, Shasta/Trinity 16 Trinity River (East Fork), Trinity 14 Trona, San Bernardino 11 Trowbridge, Sutter 16 Troy, Placer 16 Truckee, Nevada 16 Truckee River, Nevada 4 Tucker Canyon, San Luis Obispo 11 Tudor, Sutter 9 Tujunga, Los Angeles 13 Tulare, Tulare 13/16 Tulare County 13 Tulare Lake Bed, Kings 12 Tule Canal, Yolo 16 Tule Lake Sump, Siskiyou 16 Tule Mountain, Lassen 13 Tule River, Kings 15 Tule Wash, Imperial 16 Tulelake, Siskiyou 12 Tuolumne, Tuolumne 12/16 Tuolumne County 16 Tuolumne Meadows, Tuolumne 16 Tuolumne River (North Fork), Tuolumne 16 Tuolumne River (South Fork), Tuolumne 13 Tupman, Kern 13 Turk, Fresno 12 Turlock, Stanislaus 12 Turlock Lake, Stanislaus 12 Turner, San Joaquin 16 Turntable Creek, Plumas 11 Turntable Creek, Shasta 16 Turtle Mountains, San Bernardino 8 Tustin, Orange 8 Tustin Foothills, Orange 12 Tuttle, Merced 12 Tuttletown, Tuolumne 16 Twain, Plumas 12 Twain Harte, Tuolumne 14 Twentynine Palms, San Bernardino 16 Twin Bridges, El Dorado 12 Twin Cities, Sacramento 16 Twin Lakes, Mono 3 Twin Lakes, Santa Cruz 5 Twitchell Reservoir, San Luis Obispo/Santa Barbara 2 Two Rock, Sonoma U 9 UCLA, Los Angeles 2 Ukiah, Mendocino 3 Union City, Alameda 16 Union Valley Reservoir, El Dorado 8 U.S.M.C. Air Station El Toro/Santa Ana/Orange 7 U.S.M.C. Recruit Depot, San Diego, San Diego 15 U.S.N. Air Field, El Centro, Imperial 3 U.S.N. Air Station, Alameda, Alameda 7 U.S.N. Air Station, Imperial Beach, San Diego 13 U.S.N. Air Station, Lemoore, Kings 8 U.S.N. Air Station, Los Alamitos, Orange 7 U.S.N. Air Station, North Island, San Diego 12 U.S.N. Communication Station, Stockton, San Joaquin 6 U.S.N. Construction Battalion, Port Hueneme, Ventura 3 U.S.N. Facility, Point Sur, Monterey 3 U.S.N. Facility, San Bruno, San Mateo 6 U.S.N. Facility, San Clement Is., Los Angeles 6 U.S.N. Facility, San Nicolas Is., Ventura 4 U.S.N. Facility, Sunnyvale, Santa Clara 3 U.S.N. Facility, Vallejo, Solano 7 U.S.N. Reservation, Point Loma, San Diego 6 U.S.N. Shipyard, Long Beach, Los Angeles 3 U.S.N. Supply Center, Oakland, Alameda 12 U.S.N. Weapons Station, Concord, Contra Costa 6 U.S.N. Weapons Station, Seal Beach, Orange 7 U.S. Navy Training Center, San Diego 15 Unnamed Wash, Imperial 10 Upland, San Bernardino 2 Upper Lake, Lake 16 Upper Lake, Modoc 3 Upper San Leandro Reservoir, Alameda 13 Usona, Mariposa 12 Vacaville, Solano 16 Vade, El Dorado 9 Val Verde Park, Los Angeles 9 Valencia, Los Angeles 9 Valinda, Los Angeles 10 Valle Vista, Riverside 12 Vallecito, Calaveras 3 Vallejo, Solano 10 Valley Center, San Diego 2 Valley Ford, Sonoma 12 Valley Home, Stanislaus 12 Valley Springs, Calaveras 14 Valley Wells, Inyo 14 Valyermo, Los Angeles 9 Van Nuys, Los Angeles 5 Vandenberg Air Force Base, Santa Barbara 5 Vandenburg Village, Santa Barbara 6 Venice, Los Angeles 4 Ventucopa, Santa Barbara 6 Ventura, Ventura 6/9/16 Ventura County 9 Verdugo Mountains, Los Angeles 16 Vermilion Valley Dam, Fresno 12 Vernalis, San Joaquin 8 Vernon, Los Angeles 11 Verona, Sutter V February 25, 2010 D-34 Version 1.1

284 12 Victor, San Joaquin 14 Victorville, San Bernardino 15 Vidal, San Bernardino 15 Vidal Junction, San Bernardino 15 Vidal Valley, San Bernardino 15 Vidal Wash, San Bernardino 8 View Park, Los Angeles 16 Viewland, Lassen 8 Villa Park, Orange 11 Vina, Tehama 15 Vinagre Wash, Imperial 14 Vincent, Los Angeles 12 Vine Hill, Contra Costa 4 Vineyard Canyon, Monterey 16 Vinton, Plumas 16 Viola, Shasta 13 Visalia, Tulare 7 Vista, San Diego 12 Volcano, Amador 16 Volcanoville, El Dorado 12 Volta, Merced 12 Vorden, Sacramento W 1 Waddington, Humbodt 16 Walker Pass, Kern 12 Wallace, Calaveras 9 Walnut, Los Angeles 12 Walnut Creek, Contra Costa 12 Walnut Grove, Sacramento 8 Walnut Park, Los Angeles 16 Warner Mountains, Modoc 14 Warner Springs, San Diego 12 Warnersville, Stanislaus 13 Wasco, Kern 16 Washington, Nevada 12 Waterford, Stanislaus 12 Waterloo, San Joaquin 14 Watson Wash, San Bernardino 3 Watsonville, Santa Cruz 16 Waucoba Mountain, Inyo 16 Waucoba Wash, Inyo 13 Waukena, Tulare 16 Wawona, Mariposa 16 Weaverville, Trinity 16 Weed, Siskiyou 13 Weed Patch, Kern 11 Weimar, Placer 2 Weitchpec, Humboldt 16 Weldon, Kern 16 Wendel, Lassen 1 Weott, Humbodlt 8 West Athens, Los Angeles 6 West Carson, Los Angeles 8 West Compton, Los Angeles 9 West Covina, Los Angeles 9 West Hollywood, Los Angeles 15 West Mesa, Imperial 12 West Modesto, Stanislaus 12 West Pittsburg, Contra Costa 12 West Point, Calaveras 9 West Puente Valley, Los Angeles 12 West Sacramento, Yolo 16 West Walker River, Mono 9 West Whittier-Los Nietos, Los Angeles 14 Westend, San Bernardino 13 Westhaven, Fresno 1 Westhaven, Humboldt 9 Westlake Village, Los Angeles 12 Westley, Stanislaus 6 Westminster, Orange 6 Westmont, Los Angeles 15 Westmorland, Imperial 1 Westport, Mendocino 16 Westwood, Lassen 5 Whale Rock Reservoir, San Luis Obispo 11 Wheatland, Yuba 13 Wheeler Ridge, Kern 16 Wheeler Springs, Ventura 15 Whipple Mountains, San Bernardino 11 Whiskeytown, Shasta 11 Whiskeytown Lake, Shasta 16 White Horse, Modoc 16 White Mountain Peak, Mono 16 White Mountains, Inyo/Mono 13 White River (Town), Tulare 12 White Rock, Sacramento 15 White Water, Riverside 16 White Wolf, Tuolumne 1 Whitehorn, Humboldt 16 Whitehorse Flat Reservoir Modoc 16 Whitewater River (North Fork), San Bernardino 16 Whitewater River (South Fork), San Bernardino 4 Whitley Gardens, San Luis Obispo 11 Whitney, Placer 9 Whittier, Los Angeles 9 Whittier Narrows Dam, Los Angeles 15 Wiest, Imperial 11 Wilbur Springs, Colusa 10 Wildomar, Riverside 16 Wildrose RS, Inyo 11 Williams, Colusa 2 Williams Peak, Mendocino 2 Willits, Mendocino 8 Willow Brook, Los Angeles 2 Willlow Creek, Humboldt 16 Willow Creek Camp, Inyo 16 Willow Ranch, Modoc 14 Willow Springs, Kern 14 Willow Wash, San Bernardino 8 Willowbrook, Los Angeles 11 Willows, Glenn 12 Wilseyville, Calaveras 14 Wilsona Gardens, Los Angeles 16 Wilsonia, Tulare 12 Wilton, Sacramento 10 Winchester, Riverside 2 Windsor, Sonoma 14 Wingate Wash, Inyo 14 Winston Wash, San Bernardino 15 Winterhaven, Imperial 12 Winters, Yolo 12 Winton, Merced February 25, 2010 D-35 Version 1.1

285 16 Wishin, Madera 16 Wishon Reservoir, Fresno 15 Wister, Imperial 16 Wofford Heights, Kern 2 Woodacre, Marin 12 Woodbridge, San Joaquin 10 Woodcrest, Riverside 16 Woodfords, Alpine 13 Woodlake, Tulare 12 Woodland, Yolo 9 Woodland Hills, Los Angeles 16 Woodleaf, Yuba 2 Woodman, Mendocino 3 Woodside, San Mateo 13 Woodville, Tulare 13 Woody, Kern 16 Wrightwood, San Bernardino 4 Wunpost, Monterey 11 Wyandotte, Butte 14 Wynola, San Diego 16 Wyntoon, Siskiyou Y 14 Yermo, San Bernardino 13 Yettem, Tulare 12 Yolo, Yolo 12 Yolo Bypass, Solano/Yolo 12 Yolo County 8 Yorba Linda, Orange 2 Yorkville, Mendocino 16 Yosemite Valley, Mariposa 16 Yosemite Village, Mariposa 2 Yountville, Napa 16 Yreka, Siskiyou 11 Yuba City, Sutter 11/16 Yuba County 10 Yucaipa, San Bernardino 16 Yucca Mountain, Tulare 14 Yucca Valley, San Bernardino 15 Yuha Desert, Imperial 12 Zamora, Yolo 2 Zenia, Trinity 6 Zuma Canyon, Los Angeles Z February 25, 2010 D-36 Version 1.1

286 Appendix E Table of Pre-Qualified LED Fixtures / Luminaires and Qualification Process February 25, 2010 Version 1.1

287 Appendix E: Table of Approved LED Lighting The 2010 Table of Approved LED Lighting was generated under the following guidelines: 1. All fixtures must be ENERGY STAR -qualified, DesignLights Consortium (DLC) approved, or Utility approved. 2. If a fixture is not ENERGY STAR -qualified, it must be vetted through the Utility for approval. See Section E2 of this appendix for approval process instructions and required manufacturer-provided supporting documentation. Please note, Utility approval for fixture must be completed prior to application submittal. Replacement lamps are not eligible. E1: APPROVED LED LIGHTING TABLE... 2 E2: UTILITY APPROVAL PROCESS... 3 E3: SUBMISSION SUMMARY AND CHECKLIST... 4 E4: APPENDIX OF RESOURCES... 6 E5: SUMMARY OF NONRESIDENTIAL TECHNICAL REQUIREMENTS... 7 E6: SAMPLE REPORT IESNA LM February 25, 2010 H- 1 Version 1.1

288 E1: APPROVED LED LIGHTING TABLE MANUFACTURER BRAND MODEL TYPE LUMINAIRE EFFICACY (lumens/watt) DATE QUALIFIED Cree LED Lighting Solutions Cree LED Lighting Solutions LR4E-15 Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR4E-15C Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR4E-30 Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR4E-30C Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR5E Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR5E-15C Recessed downlights /25/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR6 Recessed downlights /9/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR6-GU24 Recessed downlights /9/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR6C Recessed downlights /16/2009 Cree LED Lighting Solutions Cree LED Lighting Solutions LR6C-GU24 Recessed downlights /16/2009 Cooper Lighting HALO ML W Recessed downlights /25/2009 Cooper Lighting HALO ML W-493 Recessed downlights /25/2009 Juno Lighting, Inc. Juno IC20LED-35K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC20LED-3K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC20LED-41K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC20RLED-35K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC20RLED-3K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC20RLED-41K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC22LED-35K Recessed downlights 41 3/16/2009 Juno Lighting, Inc. Juno IC22LED-3K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC22LED-41K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC22RLED-35K Recessed downlights 41 3/16/2009 Juno Lighting, Inc. Juno IC22RLED-3K Recessed downlights /16/2009 Juno Lighting, Inc. Juno IC22RLED-41K Recessed downlights /16/2009 ENERGY STAR QUALIFIED Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y UTILITY APPROVED Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y REVIEWED BY (IOU/Agency) ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR ENERGY STAR February 25, 2010 H- 2 Version 1.1

289 E2: UTILITY APPROVAL PROCESS Please note, Utility approval for fixture must be completed prior to application submittal. Replacement lamps are not eligible. For Fixture/Luminaires not currently covered by an ENERGY STAR label, submit the following from the Fixture Manufacturer: 1. LM-79 Test: Provide Independent Testing according to IES LM-79 that provides efficacy, output, color, and photometric distribution of your product. An Integrating Sphere Test will be required to provide color information. A Goniophotometer test by itself is not adequate. A sample test report is included with this document. At a minimum, the LM-79 testing report(s) should include: a. Electrical Data i. Input voltage ii. Current in (A)mperes iii. Power in (W)atts iv. Power Factor & THD b. Total Light Output i. Luminous Flux in Lumens ii. Luminous efficacy (Lm/W) iii. Zonal Lumen Summary c. Luminous Intensity Distribution i. Candela Distribution ii. Polar Graph iii. Suggested additional data 1. Spacing Criteria 2. Coefficient of Utilization (CU) and 3. Isoilluminance plot d. Color characteristics i. Color Temperature (CCT) ii. Color Rendering Index (CRI) iii. Chromaticity Coordinates iv. Spectral Power Distribution (SPD) 2. IES File: Provide absolute photometric testing data in IES LM-63 electronic file format. 3. Lifetime: Provide written explanation of how L70 Lifetime of Product is determined using the LM-80 and In-situ temperature tests referenced below. a. LM-80 Test: Provide LED Package Manufacturer IES LM-80 Test Report with results showing relative (%) light output over time at 55 C, 85 C and X C (a third temperature at the manufacturer s choice). b. In-Situ Temperature Test: Provide test report indicating the Temperature of the hottest LED In-Situ in ANSI/UL (hardwired) or ANSI/UL (corded) environments. This temperature measurement will be used with LM-80 data to validate lumen maintenance and useful life of product. Note that this temperature measurement should be specially requested by the manufacturer as they are getting their UL testing. February 25, 2010 H- 3 Version 1.1

290 E3: SUBMISSION SUMMARY AND CHECKLIST Company Name Address Phone Fax Web Site MANUFACTURER CONTACT INFORMATION Item ATTACHMENTS Included Check 1. LM 79 Test Report 2. IES File 3. Lifetime Determination Statement 4. LM 80 Test Report 5. In-situ Temperature Test Report LUMINAIRE INFORMATION FOR NON-ENERGY STAR QUALIFIED LUMINARIES/FIXTURES Required Information & Test Results Fill In Verified Table 1 Check Reviewer Notes For Office use Only Manufacturer Name Manufacturer Part or Catalog# Intended application(s) Wattage as tested Operating voltage Operating current Total Luminous Flux (Lumens) Luminous Efficacy (Lm/W) Color temperature (CCT) NTE 6500k Color Rendering Index (CRI) >75 for February 25, 2010 H- 4 Version 1.1

291 Interior / 70 for Exterior Manufacturer Warranty (5 yr min) Off-State Power (Must be zero) Power Factor (>0.9) THD (<20%) UL File # Submission: February 25, 2010 H- 5 Version 1.1

292 E4: APPENDIX OF RESOURCES Suggested Testing Services (From CALiPER and DOE Manufacturer's Guide LM-79 and LM-80 Testing Laboratories Integrating Sphere (LM-79 Section 9.1 and 9.2) Independent Testing Laboratories, Inc. Boulder, CO Lighting Sciences, Inc. Scottsdale, AZ Lighting Research Center; Rensselaer Polytechnic Institute Troy, NY Luminaire Testing Laboratory, Inc. Allentown, PA Goniophotometry (LM-79 Section 9.3) Independent Testing Laboratories, Inc. Boulder, CO Luminaire Testing Laboratory, Inc. Allentown, PA Lighting Sciences, Inc. Scottsdale, AZ UL 1598 or UL 153 testing Nationally Recognized Testing Laboratories (NRTLs) Canadian Standards Association (CSA); Intertek Testing Services NA, Inc. (ITSNA); MET Laboratories, Inc. (MET); NSF International (NSF); SGS U.S. Testing Company, Inc. (SGSUS); TUV America, Inc. (TUVAM); TUV Product Services GmbH (TUVPSG); TUV Rheinland of North America, Inc. (TUV); Underwriters Laboratories Inc.(UL); and Wyle Laboratories, Inc. (WL). A complete and current listing of NRTLs: February 25, 2010 H- 6 Version 1.1

293 E5: SUMMARY OF NONRESIDENTIAL TECHNICAL REQUIREMENTS Application 1. Recessed, surface and pendant-mounted downlights 2. Under cabinet shelf-mounted task Lighting Min Light Output < L, > L Zonal Lumen Density Minimum Luminaire Efficacy Allowable CCTs 75% 0º-60º 35 L/w 2700 K, 3000 K, 3500 K, 4000K, 5000K 125 L/ft 60% 0º-60º, 25% 60º-90º 29 L/w 2700K, 3000K, 3500K, 4000K, 5000K 3. Portable desk task lights 200 L 85% 0º-60º 29 L/w 2700K, 3000K, 3500K, 4000K, 4500K and 5000K Minimum CRI Minimum L70 Lifetime 75 35,000 hrs 75 35,000 hrs 75 35,000 hrs February 25, 2010 H- 7 Version 1.1

294 Application Min Light Output Zonal Lumen Density Minimum Luminaire Efficacy Allowable CCTs 4. Wall wash luminaires 575 L 50% 20º-40º 40 L/w 2700K, 3000K, 3500K, 4000K, 4500K and 5000K 5. Bollards N/A <15% 90º-110º, 0% >110º 40 L/w 2700K, 3000K, 3500K, 4000K, 4500K and 5000K 6. Outdoor Pole/Arm-Mounted Area and Roadway Luminaires 2,300 L 100% 0-90º, <10 % 80-90º plus meet IES Type I, II, III, IV, or V Minimum CRI Minimum L70 Lifetime 75 35,000 hrs 75 35,000 hrs 50 L/w < 6500K 70 50,000 hrs 7. Outdoor Pole/Arm-Mounted 2,300 L 95% 0-90º 50 L/w < 6500K 70 50,000 hrs Decorative Luminaires 8. Outdoor Wall-Mounted Area 1,300 L 100% 0-90º, <10 % 80-90º 50 L/w < 6500K 70 50,000 hrs Luminaires 9. Parking Garage Luminaires 4,000 L >20% 60-70º, >15% 70-80º 50 L/w < 6500K 70 50,000 hrs 10. Track or Mono-point Directional Lighting Fixtures 250 L >85% 0-90º 30 L/w 2700K, 3000K, 3500K, 4000K, 5000K 75 35,000 hrs * DOE ENERGY STAR V1.1 Nonresidential Applications Products must be ENERGY STAR-qualified: DOE ENERGY STAR Eligibility Criteria Version 1.1 December 19, ** Non-ENERGY STAR Applications Submit Product Information and Testing Results to Utility for qualification February 25, 2010 H- 8 Version 1.1

295 E6: SAMPLE REPORT IESNA LM-79 February 25, 2010 H- 9 Version 1.1