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HomeMy WebLinkAbout2018-10-16 Finance Committee Agenda PacketFinance Committee 1 MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE CITY COUNCIL AFTER DISTRIBUTION OF THE AGENDA PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE CITY CLERK’S OFFICE AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS HOURS. Tuesday, October 16, 2018 Special Meeting Community Meeting Room 6:00 PM Agenda posted according to PAMC Section 2.04.070. Supporting materials are available in the Council Chambers on the Thursday 12 days preceding the meeting. PUBLIC COMMENT Members of the public may speak to agendized items. If you wish to address the Committee on any issue that is on this agenda, please complete a speaker request card located on the table at the entrance to the Council Chambers/Community Meeting Room, and deliver it to the Clerk prior to discussion of the item. You are not required to give your name on the speaker card in order to speak to the Committee, but it is very helpful. Public comment may be addressed to the full Finance Committee via email at City.Council@cityofpaloalto.org. Call to Order Oral Communications Members of the public may speak to any item NOT on the agenda. Action Items 1.Staff Recommendation That the Finance Committee Recommends the City Council Approve the Updated User Fee Cost Recovery Policy and Discuss Police and Community Services Department Fees 2.Approval of Contract Amendment Number 2 With Verizon Wireless Through June 30, 2019, Utilizing the Western State Contracting Alliance (WSCA) Contract, California Participating Addendum, for Wireless, Voice and Broadband Services, Accessories and Equipment (Referred by City Council on October 1, 2018) 3.Utilities Advisory Commission Recommendation That the Finance Committee Recommend the City Council Adopt a Resolution Approving the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and Related Documents 4.Staff and the Utilities Advisory Commission Recommendation That Finance Committee Recommend the City Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure-based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers MEMO 2 October 16, 2018 MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE CITY COUNCIL AFTER DISTRIBUTION OF THE AGENDA PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE CITY CLERK’S OFFICE AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS HOURS. Future Meetings and Agendas Adjournment AMERICANS WITH DISABILITY ACT (ADA) Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance. Finance Committee Items Tentatively Scheduled Meeting Date Line No. Item Title Referral Date 11/28/2018 1 No agenda as of yet 12/4/2018 2 No agenda as of yet Finance Committee Items to be Scheduled Referral Date Line No. Item Title Status 3 HSRAP Allocation (CSD) 4 FY18 Comprehensive Annual Financial Report (CAFR) 5 Council Chambers Upgrade Project - IT/PW/CLK 6 FY2020 - FY2029 Long Range Financial Forecast (LRFF) - ASD 7 $4 million GF Council referral, Round 2 - ASD 8 Transparency Colleagues Memo Round 2 CMO/ATTY/HR/ASD City of Palo Alto (ID # 9664) Finance Committee Staff Report Report Type: Action Items Meeting Date: 10/16/2018 City of Palo Alto Page 1 Summary Title: User Fee Cost Recovery Policy and Police/CSD Fees Title: Staff Recommends That the Finance Committee Recommends That the City Council Approve the Updated User Fee Cost Recovery Policy and Discuss Police and Community Services Department Fees From: City Manager Lead Department: Administrative Services Recommendation Staff recommends that the Finance Committee recommend the City Council to 1. Adopt an update to the User Fee Cost Recovery Level Policy (Attachment A) to include language clarifying certain types of fees are not subject to state laws limiting fees to cost recovery. 2. Review and provide feedback on augmenting the City’s Municipal Codes in association with either removing obsolete, or updating existing, Police Department fees from the Municipal Fee Schedule. Background User Fee Cost Recovery Level Policy The City Auditor’s Office issued an audit on April 17, 2017 the Community Services Department (CSD) Fee Schedule Audit, which included a review of CSD’s procedures around municipal fee setting. The full audit report can be found: https://www.cityofpaloalto.org/civicax/filebank/documents/56884. The audit objectives were to determine if CSD fees recover an adequate level of costs of providing service and appropriately subsidize various City programs depending on the level of benefit to the community versus the individual in accordance with the City’s current User Fee Cost Recovery Level Policy. The City Auditor’s Office found that the department’s cost recovery level guidelines, consisting of four cost ranges, are not aligned with the City’s User Fee Cost Recovery Level Policy and recommended to revise the current Policy to clarify categories of fees that are not subject to state laws limiting those fees to cost recovery. Given this audit recommendation, staff examined and made updates to the current User Fee Cost Recovery Level Policy. Details City of Palo Alto Page 2 on these proposed changes can be found in the Discussion section below, as well as in Attachment A. Police Department Fees At the May 16th, 2018 meeting, the Finance Committee noted that some of the Police Department (PD) fees may be outdated and recommended examining existing fees to determine whether certain fees need to be updated or even deleted. Staff examined existing PD fees, and findings are presented in the Discussion section below. Discussion User Fee Cost Recovery Level Policy The City provides a variety of services and programs to the public that benefit the entire community, including individuals and local businesses. The City’s fee-based services and programs must adhere to the City’s User Fee Cost Recovery Level Policy, which was adopted by the City Council on May 18, 2015 (CMR #5735). Table 1 below summarizes the three levels of cost recovery allowed under the current policy. Table 1: Current User Fee Cost Recovery Levels Cost Recovery Level Group Cost Recovery Percentage Range Policy Considerations Low 0% - 30% • No intended relationship between the amount paid and the benefit received • Fee collection would not be cost effective and/or would discourage compliance with regulatory requirements • No intent to limit the use of the service • Public at large benefits even if they are not the direct users of the service • Affordability of service to low‐income residents • The service is heavily supported through donations Medium 30.1% - 70% • Services which promote healthy activities and educational enrichment to the community • Services having factors associated with the low and high cost recovery levels High 70.1% - 100.0% • Individual users or participants receive most or all of the benefit of the service • Other private or public sector alternatives provide the service • The use of the service is specifically discouraged • The service is regulatory in nature Current policy aligns with the requirements outlined in the State Constitution. Specifically, Propositions 13, 218, and 26 have placed both substantive and procedural limits on local governments’ ability to impose fees and charges. Collectively, these state constitutional amendments provide safeguards against taxes being imposed without a vote of the people. City of Palo Alto Page 3 Proposition 26 in particular contains a general articulation of the cost of service principle and includes a requirement that the local government bears the burden of proving by a preponderance of the evidence that a levy, charge, or other exaction is not a tax, that the amount is no more than necessary to cover the reasonable costs of the governmental activity, and that the manner in which those costs are allocated to a payor bear a fair or reasonable relationship to the payor’s burdens on, or benefits received from, the governmental activity. (California Constitution, Article XIII C, Section 1). Certain types of fees, such as fines, penalties and/or late charges, or any charge imposed for entrance to or use of, as well as the purchase, rental, or lease of local government property, are exempted from the provision quoted above and not required to be based on actual costs of providing service. Instead, these types of fees are more typically governed by local market rates, reasonableness and potentially other policy factors. Certain fees, primarily found in CSD activities, such as facility rental fees, golf course greens fees for example, fall into this category, where fee rates are more appropriately set based on local market rates. Consequently, these fees are not bound to certain cost recovery levels and can even have rates that are higher than the full cost recovery level, if appropriate. As outlined in the audit, currently CSD applies the criteria in Table 2 as a general guideline to determine an appropriate cost recovery level. Table 2: CSD Fee Cost Recovery Guideline Cost Recovery Level Group Programs and Services Low • Programs targeted at low-income or special needs populations • Human Services programs • Programs supported by Friends groups • Facility rentals by non-profit partners • Classes aimed at teaching an essential life-skill or a skill aimed at increasing safety, such bike safety • Programs aimed at decreasing teen stress such as participating in the Mitchell Park Teen Center Medium • Group classes, camps and workshops • Sports league registrations • Field and facility rentals for programs providing services to majority Palo Alto residents High • Private lessons for residents • Facility rentals for private events for residents Very High • Private lessons for non-residents • Facility rentals for private events for non-residents & for- profit entities • Golf course greens fees • Birthday parties and other private special event packages Staff recommends updating the Policy to include a provision to clarify the category of fees that are exempted from state laws limiting rates to full cost recovery. This update will bring the City’s municipal fee policy in alignment with the City Auditor’s recommendation, as well as the City of Palo Alto Page 4 full scope of services and programs the City offers. Proposed changes to the cost recovery levels are shown below in Table 3. For details, refer to the Attachment A. Table 3: Proposed User Fee Cost Recovery Levels Cost Recovery Level Group Cost Recovery Percentage Range Policy Considerations Low 0.0% - 30.0% • No intended relationship between the amount paid and the benefit received • Fee collection would not be cost effective and/or would discourage compliance with regulatory requirements • No intent to limit the use of the service • Public at large benefits even if they are not the direct users of the service • Affordability of service to low-income residents Medium 30.1% - 70.0% • Services which promote healthy activities and educational enrichment to the community • Services having factors associated with the low and high cost recovery levels High* 70.1% - 100.0+%* • Individual users or participants receive most or all of the benefit of the service • Other private or public sector alternatives provide the service • The use of the service is specifically discouraged • The service is regulatory in nature *Certain types of fees, such as fines, penalties and/or late charges, or any charge imposed for entrance to or use of, as well as the purchase, rental, or lease of local government property, are not bound by state laws that limit to full cost recovery. Police Department Fees At the May 16th, 2018 meeting, the Finance Committee directed staff to review existing Police Department (PD) fees to determine if some of the fees can be considered obsolete and deleted from the Municipal Fee Schedule. Per the Finance Committee’s direction, staff examined existing PD fees specifically. Staff first reviewed to determine which fees have not been charged in recent years and assessed if fees may be considered obsolete. After this review, staff has identified 14 fees that have not had any activity over the past 5 years. From these fees, staff has grouped them into ones that are recommended for deletion and ones that are recommended for further review and possible deletion or adjustment in the future. It is important to note that a number of these fees were City of Palo Alto Page 5 added through changes to the City’s Municipal Code; therefore, deleting these fees would also require removing relevant Municipal Code sections. Attachment B outlines the two groups of fees. Those that staff recommends to be deleted as they are no longer necessary are listed in Table 4 below. There are a number of other fees that staff identified as being potentially obsolete or needing to be updated for a number of reasons. A complete list of these fees with staff recommendation can be found in Attachment B. Any potential implications of making adjustments need to be researched further, and staff will return to the Finance Committee with more concrete recommendations as part of the annual Municipal Fee Schedule update process in May, 2019. Table 4: Obsolete Police Department Fees Fee Title Last Transaction Annual # of Transaction (Past 5 years) Municipal Code Section Hot Tub Sauna - Employee (New) Unknown 0 4.56.060 Hot Tub Sauna - Employee (Renewal) Unknown 0 4.56.070 Hot Tub Sauna – New Unknown 0 4.56.030 Hot Tub Sauna - Renewal Unknown 0 4.56.040 Hot Tub Sauna - Sale or Transfer of Interest Unknown 0 4.56.140 Mechanical Amusement Device Establishment Unknown 0 4.10.120 Billiard Room (non-refundable) Unknown 0 4.52.020 Bowling Alley (non-refundable) Unknown 0 4.52.020 Carnival Unknown 0 4.52.020 Circus Unknown 0 4.52.020 Rodeo – New Unknown 0 4.10.070 Bingo Establishment 4-6 years ago 0 4.51.160 Bingo Employee – New 4-6 years ago 0 4.51.160 Bingo Employee - Renewal 4-6 years ago 0 4.15.160 Resource Impact Based on discussions with the Finance Committee and the City Council, any changes to fee rates for existing fees, such as potentially establishing a lower Special Event Permit fee rate for residents and/or non-profit organizations will have an impact on associated fee-based revenues. These potential changes and their impacts are anticipated to be discussed through the development of the FY 2020 Operating Budget and FY 2020 Municipal Fee Schedule. The City of Palo Alto Page 6 elimination of the fees discussed above is not anticipated to have impacts on current fee revenue, since they are not currently being charged. Policy Implications Recommendations in this staff report are consistent with existing City policies. Updates to the User Fee Cost Recovery Level Policy is still in accordance with Proposition 26 since recommended changes simply clarifies category of fees that are exempt from the requirement where the amount of new or increased fees and charges is no more than necessary to cover the reasonable cost of the City service, and the manner in which those costs are allocated to a payor bears a fair and reasonable relationship to the payor’s burden on, or benefits received from, such a City service. Environmental Review Updating the User Fee Cost Recovery Level Policy, Municipal Codes, and the Municipal Fee Schedule do not constitute a project as defined in Public Resource Code Section 21065 for the purpose of the California Environment Quality Act. Attachments: • Attachment A - User Fee Cost Recovery Level Policy • Attachment B - Police Department Fees Staff Report #9664 - Attachment A Page 1 of 2 USER FEE COST RECOVERY LEVEL POLICY BACKGROUND The City provides a variety of services to the public which benefit the entire community or individual residents or businesses. For certain services such as regulatory fees, arts and science classes, or recreational classes, the City has partially or fully recovered the cost for providing these services, which would have been otherwise paid from the General Fund. Propositions 13, 218, and 26 have placed both substantive and procedural limits on cities’ ability to impose fees and charges. Collectively these constitutional amendments provide safeguards against taxes being imposed without a vote of the people. POLICY STATEMENT It is the policy of the City of Palo Alto to set Municipal Fees based on cost recovery levels in lieu of fully subsidizing fee-related activities with General Fund dollars. The cost recovery levels are reflective of the following policy statements. 1. Community-wide vs. Private Benefit: Funding services such as Police patrol services only through taxpayer dollars is appropriate for services that benefit the entire community. When the service or program provides a benefit to specific individuals or businesses such as the issuance of building permits, it is expected that individuals or businesses receiving that benefit pay for the costs to provide that service. 2. Service Recipient vs. Community Benefit: For regulated activities such as development review and Police issued permits, it is appropriate that the service recipient such as an applicant of a building permit pay for the permit although the community at large benefits from the regulation. 3. Consistency with City Goals and Policies: City policies and City Council goals related to the community’s quality of life are factors in setting cost recovery levels. For example, fee levels can be set to promote healthy habits, facilitate environmental stewardship, or discourage certain actions (e.g. false alarms). 4. Elasticity of Demand for Services: The level of cost recovery can affect the demand for services. A higher level of cost recovery could ensure the City is providing services such as recreational classes or summer camps for children and youth without over stimulating a market with artificially low prices. Such low prices, which are a reflection of a high General Fund subsidy, may result in waiting lists and attract participants from other cities; however, high cost recovery levels could negatively impact the demand for such services from low income individuals, special needs individuals, and seniors. 5. Availability of Services from the Private Sector: High cost recovery levels are generally sought in situations where the service is available from other sources in order to preserve taxpayer funds for other General Fund funded City services. Conversely, services that are not available from other sources Staff Report #9664 - Attachment A Page 2 of 2 and are typically delivered when residents experience an emergency typically have low or zero cost recovery levels. Based on these policy statements, the table below overlays certain cost recovery levels grouped in low (0.0% to 30.0%), medium (30.1% to 70.0%), and high (70.1% to 100.0+%) cost recovery percentage ranges. It is important to note that these groupings provide policy guidance and are not absolute. Some policy statements may weigh more heavily than others, which may result in a different cost recovery level grouping for particular fees. For example, fees for recreational activities are expected to be set in general at the medium cost recovery level; however, fees for recreational activities for which there is a high demand may have a high cost recovery level due to high enrollment levels per class. Additionally, while state laws limit most categories of fees to the reasonable cost of providing the service, certain types of fees, such as fines, penalties and/or late charges, or any charge imposed for entrance to or use of, as well as the purchase, rental, or lease of local government property, are not bound by those laws that limit to full cost recovery. Instead, these types of fees are more typically governed by local market rates, reasonableness and other policy driven factors. Therefore, these fees can potentially have rates higher than the full cost recovery level. It is important to note that Municipal fees are reviewed annually by the Finance Committee and subsequently by the City Council as part of approval of the Municipal Fee Schedule. Table 1: User Fee Cost Recovery Levels Cost Recovery Level Group Cost Recovery Percentage Range Policy Considerations Low 0.0% - 30.0% • No intended relationship between the amount paid and the benefit received • Fee collection would not be cost effective and/or would discourage compliance with regulatory requirements • No intent to limit the use of the service • Public at large benefits even if they are not the direct users of the service • Affordability of service to low-income residents Medium 30.1% - 70.0% • Services which promote healthy activities and educational enrichment to the community • Services having factors associated with the low and high cost recovery levels High* 70.1% - 100.0+% • Individual users or participants receive most or all of the benefit of the service • Other private or public sector alternatives provide the service • The use of the service is specifically discouraged • The service is regulatory in nature *Certain types of fees, such as fines, penalties and/or late charges, or any charge imposed for entrance to or use of, as well as the purchase, rental, or lease of local government property, are not bound by state laws that limit to full cost recovery. Attachment B ‐ Police Department Fees  Recommended for Deletion Fee Subgroup General Recommendation Fee Title *Last Transaction Palo Alto  Statute Billiard Room (non‐refundable)Unknown 4.52.020 Bingo Employee ‐ New 4‐6 years ago 4.51.160 Bingo Employee ‐ Renewal 4‐6 years ago 4.15.160 Bingo Establishment 4‐6 years ago 4.51.160 Bowling Alley (non‐refundable)Unknown 4.52.020 Carnival Unknown 4.52.020 Circus Unknown 4.52.020 Delete recommended due to obsolescence and high risk to  City liability potentially resulting in collecting this permit. Mechanical Amusement Device  Establishment Unknown 4.10.120 Hot Tub Sauna ‐ Employee (New)Unknown 4.56.060 Hot Tub Sauna ‐ Employee (Renewal)Unknown 4.56.070 Hot Tub Sauna ‐ New Unknown 4.56.030 Hot Tub Sauna ‐ Renewal Unknown 4.56.040 Hot Tub Sauna ‐ Sale or Transfer of Interest Unknown 4.56.140 POL ‐ Rodeo Delete recommended due to obsolescence, outdated and no  longer used. Rodeo ‐ New Unknown 4.10.070 POL ‐ Hot Tub / Sauna POL ‐ Adult Entertainment Delete recommended due to obsolescence, outdated and no  longer used. Delete recommended due to obsolescence or overlap with  other permit. Attachment B ‐ Police Department Fees  Recommended for Further Review Fee Subgroup General Recommendation Fee Title *Last Transaction Palo Alto  Statute Closing‐out Sale 4‐6 years ago 4.34.020 Closing‐out Sale Renewal (Two Maximum) 4‐6 years ago 4.34.020 Massage Establishment ‐ New 2017 4.54.040 Massage Establishment ‐ Non‐Certified  (New) None Massage Establishment ‐ Non‐Certified  (Renewal) 2018 None Massage Establishment ‐ Renewal 2018 4.54.040 Massage Establishment ‐ Sale or Transfer of  Interest 4.54.150 Massage Establishment ‐ Sole Proprietor  (New) None Massage Establishment ‐ Sole Proprietor  (Renewal) 2018 None Massage Practitioner ‐ Non‐Certified (New)2018 None Massage Practitioner ‐ Non‐Certified  (Renewal) 2018 None Massage Technician ‐ New 2018 None Massage Technician ‐ Renewal 2018 None Solicitation for Commercial Purpose 2018 4.32.020 Solicitor Employee (Under Master License)4.10.055 Solicitor/Peddler Master License 2018 4.10.055 Taxicab ‐ Driver 2018 4.42.220 Taxicab ‐ Master License (New)2018 None Taxicab ‐ Master License (Renewal)2018 None Taxicab ‐ Vehicle Inspection for Each  Vehicle 2018 None Taxicab Driver ‐ Replacement or Transfer  Fee 2018 None POL ‐ Adult Entertainment POL ‐ Taxicab POL ‐ Massage  Establishment Update in progress, this permit is also covered county‐wide,  and under a state senate bill so the city needs to align  ordinance. The Code Enforcement Officer is currently  working on this with the Attorney's Office. Move recommended to another department that regulates  more business that is related to this function than police  does. Consolidate/Update Recommended due to overlapping  requirements with state permits. Update: Non‐Profits have to follow the same process/rules  as For‐Profits. Certain updates can reduce liability, for  example having a "do not solicit" list and performing a  background check for all businesses, including non-profits. Unknown Unknown Unknown UnknownPOL ‐ Miscellaneous City of Palo Alto (ID # 9702) Finance Committee Staff Report Report Type: Action Items Meeting Date: 10/16/2018 City of Palo Alto Page 1 Summary Title: WSCA Verizon Wireless Amendment Title: Approval of Contract Amendment Number 2 With Verizon Wireless Through June 30, 2019, Utilizing the Western State Contracting Alliance (WSCA) Contract, California Participating Addendum, for Wireless, Voice and Broadband Services, Accessories and Equipment (Referred by City Council on October 1, 2018) From: City Manager Lead Department: IT Department Recommendation Staff recommends that Council approve and authorize the City Manager or his designee to enter into a contract renewal with Verizon Wireless for wireless, voice, and broadband services, accessories and equipment, through June 30, 2019, utilizing the Western States Contracting Alliance (“WSCA”) Master Service Agreement with Verizon Wireless–, State of California Participating Addendum No. 7-11-70-16 (WSCA No.1907)., Executive Summary The Western States Contracting Alliance (“WSCA”) is a cooperative group-contracting consortium for state government departments, institutions, agencies and political subdivisions (i.e., colleges, school districts, counties, cities, etc.,) for the states of Alaska, Arizona, California, Colorado, Hawaii, Idaho, Minnesota, Montana, Nevada, New Mexico, Oregon, South Dakota, Utah, Washington and Wyoming. This is a contract between the Western States Contracting Alliance (now known as NASPO ValuePoint), acting by and through the State of Nevada Department of Administration, Purchasing Division. The State of Nevada has been authorized by WSCA to negotiate a Master Agreement as a lead state, for and on behalf of WSCA and its members. The contract allows the City to utilize Verizon Wireless, T-Mobile, AT&T and/or Sprint networks. Background The City has over 500 devices which consist of cell phones, wireless devices and equipment with an annual spend of roughly $300,000 per year. By using the WSCA contract the City can utilize the significant cost savings that this contract sets forth. The WSCA contract, State of California Participating Addendum, has been renewed through City of Palo Alto Page 2 June 30, 2019 (Attachment A: Amendment #2 WSCA Verizon Wireless). Council previously approved using this cooperative contract through October 31, 2018 (CMR #3999, September 9, 2013). The City currently has an account with Verizon Wireless with the IT department as the master account. Several sub-accounts have been created under the master account for each City department. Each City department is responsible for payment of their respective accounts each month. The City would like to continue using the WSCA contract for all mobile needs. Discussion By utilizing the WSCA wireless contract, the City can receive more aggressive cellular rate plans and significant hardware cost savings (Attachment B: Current NASPO-WSCA Verizon Pricing). In addition to cellular services and equipment, the City will also be utilizing the contract pricing to purchase tablet devices, equipment and accessories. By utilizing this contract, it also allows IT to keep up with City department demand for mobile computing and to lead the way in supporting a more mobile workforce. Resource Impact Funds for these services are provided from departmental operating budgets. Environmental Review Approval of this contract does not constitute a project under the California Environmental Quality Act (CEQA); therefore, no Environmental Assessment is required. Attachments: • Attachment A: Amendment #2 WSCA Verizon Wireless • Attachment B: Current NASPO-WSCA Verizon Pricing Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 1 of 41 Verizon Wireless Pricing Sheet NASPO ValuePoint or NVLPT (f/k/a WSCA) Contract for Services #1907 22% NVLPT Discount Offer WIRELESS VOICE CALLING PLANS NVLPT Nationwide for Government Share Calling Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. NVLPT Nationwide for Government Account Share 0 Minutes 100 Minutes 200 Minutes Monthly Access Fee $15.991 (86137) $23.98 (80006) $27.29 (73736) NVLPT Nationwide for Government EVP (Profile) Share 0 Minutes 100 Minutes 200 Minutes Monthly Access Fee $15.991 (86136) $23.98 (80010) $27.29 (73575) Monthly Anytime Voice Minutes 0 100 200 Domestic Voice Overage Rate $0.25 per minute Domestic Mobile to Mobile Unlimited Domestic Night & Weekend Minutes Unlimited Domestic Long Distance Included Data Sent or Received $1.99/ MB or per data package2 Domestic Text, Picture and Video Messages 100 Included (76678) Overage per message: Incoming Text $0.02/ Outgoing Text $0.10 / Pic & Video $0.25 Optional Features Domestic Text, Picture and Video Messages Unlimited (75439) $12.00 per line Domestic Push To Talk Plus Not Available $2.00 (Basic phone- 83270) Notes Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1The $15.99 zero access plan can only be 50% of an accounts total share lines. 2Smartphones and Data Multimedia Phones require a data package. 4G service requires 4G Equipment and 4G coverage. Account Share Voice Sharing: At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. EVP (Profile) Share - Voice Sharing (Domestic Only): At the end of each bill cycle, any unused voice allowances for lines sharing across multiple accounts will be applied proportionally to all lines with overages. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 2 of 41 NVLPT Nationwide for Government Calling Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. NVLPT Nationwide for Government 400 Voice Minutes 600 Voice Minutes 1000 Voice Minutes Monthly Access Fee (non-share) $35.88 (74538) $52.56 (74540) $67.94 (74542) Monthly Access Fee less discount (non-share) $27.98 $40.99 $52.99 Monthly Access Fee (share) $38.45 (74539, 76363) $55.12 (74541, 76364) $70.50 (74543, 76365) Monthly Access Fee less discount (share) $29.99 $42.99 $54.99 Monthly Anytime Voice Minutes 400 600 1000 Friends & Family (up to 10 numbers per account) Not Included Included1 Voice Overage Rate $0.25 per minute Domestic Mobile to Mobile Unlimited Domestic Night & Weekend Minutes Unlimited Domestic Long Distance Included Data Sent or Received $1.99/ MB or per data package2 Domestic Text, Picture and Video Messages 100 Included (76678) Overage per message: Incoming Text $0.02/ Outgoing Text $0.10 / Pic & Video $0.25 Optional Features Domestic Text, Picture and Video Messages Unlimited (75439) $12.00 per line Domestic Push To Talk Plus $2.00 (Basic phone- 83270) Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1Friends & Family eligibility varies on selected calling plan. 2Smartphones and Data Multimedia Phones require a data package. 4G service requires 4G Equipment and 4G coverage. Account Share Voice Sharing: At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. NVLPT Nationwide for Business Calling Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. Nationwide for Business 450 Voice Minutes 900 Voice Minutes Unlimited Voice Minutes Monthly Access Fee (Talk) $39.99 (73713) $59.99 (73714) $69.99 (83233) Monthly Access Fee less discount (Talk) $31.19 $46.79 $54.59 Monthly Access Fee (Talk & Text) $59.99 (73761) $79.99 (73762) $89.99 (83234) Monthly Access Fee less discount (Talk & Text) $46.79 $62.39 $70.19 Domestic Anytime Voice Minutes 450 900 Unlimited Friends & Family (up to 10 numbers per account) Included with share plan only Included1 Voice Overage Rate $0.25 per minute National Mobile to Mobile Unlimited Domestic Night & Weekend Minutes Unlimited Domestic Long Distance Included Data Sent or Received $1.99/ MB or per data package2 Domestic Text, Picture and Video Messages 100 Included (76678) Overage per message: Incoming Text $0.02/ Outgoing Text $0.10 / Pic & Video $0.25 Optional Features Domestic Text, Picture and Video Messages Unlimited (75439) $12.00 per line Domestic Push To Talk Plus $2.00 (Basic phone- 83270) Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1Friends & Family eligibility varies on selected calling plan. 2Smartphones and Data Multimedia Phones require a data package. 4G service requires 4G Equipment and 4G coverage. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 3 of 41 WIRELESS VOICE & DATA PLANS Unlimited Plan for Smartphones - Government Government Subscribers Only This plan is not eligible for monthly access fee discounts. Monthly Access Fee $70.00 (99719) Monthly Anytime Minutes – Domestic, Canada and Mexico Unlimited Domestic Data and Messaging Allowance* Unlimited Canada & Mexico Data and Messaging Allowance** Unlimited Mobile Hotspot^ Included Domestic, Canada and Mexico Long Distance Toll Free^^ Included International Messaging Allowance^^^ Unlimited Notes: Coverage area includes the Verizon Wireless 4G network; and the 3G and Extended partner networks, while available. Data speeds are not guaranteed while on Extended or roaming partner networks. Only a 4G LTE GSM/UMTS global-capable smartphone can be activated on this plan. No domestic roaming or long distance charges. *After 25 GB of data usage on a line during any billing cycle usage may be prioritized behind other customers in the event of network congestion. To ensure users are able to maximize their high-speed data use for business applications, video applications will stream at up to 480p. **For data usage in Canada and Mexico, after the first 512 MB of usage in a day, throughput speeds will be reduced for the remainder of the day. ^Mobile Hotspot is available on all capable devices and allows the line to share data allowance with multiple Wi-Fi enabled devices. If 15 GB of Mobile Hotspot data usage is exceeded on any line in any given billing cycle, Verizon Wireless will limit the data throughput speeds for additional usage for the remainder of the then-current billing cycle for the line that exceeds the data usage. ^^Toll free calling from the US to Canada and Mexico, from Mexico to the US and Canada, and from Canada to the US and Mexico. ^^^Unlimited Messaging from within the United States to anywhere in the world where messaging services are available. For other messaging rates go to www.verizonwireless.com. Custom 4G Verizon Unlimited Smartphone Plan for Public Sector Government Subscribers Only The calling plan below reflects the monthly access fee discount. No additional discounts apply. Only 4G LTE GSM/UMTS global-capable smartphones can be activated on this plan. Monthly Access Fee $65.00 (13656) Monthly Access Fee (Discount Applied) $50.70 Monthly Minutes in U.S Unlimited Domestic Data Allowance Unlimited(1) Domestic Mobile Hotspot Unlimited(2) Domestic and International Messaging Allowance Unlimited(3) Notes: Current coverage details can be found at www.verizonwireless.com. No domestic roaming or long distance charges. Coverage includes the Verizon Wireless 4G network; and the 3G and 3G Extended networks, while available. (1) In the event of network congestion, after 10GB of data usage on a line during any billing cycle, usage on such line may result in slightly slower download speeds relative to another user. To ensure users are able to maximize their high-speed data use for business applications, video applications will stream at 480p. (2) Mobile Hotspot is available on all capable devices and allows Corporate Subscribers to use their device and share data allowance with multiple Wi-Fi enabled devices. If 10GB of Mobile Hotspot data usage is exceeded on any line in any given billing cycle, Verizon Wireless will limit the data throughput speeds for additional usage for the remainder of the then-current billing cycle for the line that exceeds the data usage. (3) Unlimited Messaging from within the United States to anywhere in the world where messaging services are available. For other messaging rates go to www.verizonwireless.com. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 4 of 41 The New Verizon Plan - Talk, Text and Data: Government Subscribers (Up to 10 Phone/Internet Devices/20 Connected Devices) Select Device Type Smartphones Purchased at Discounted Price (Matrix) (SFO 84014) Smartphones Purchased at Full Retail Price or Customer Provided Equipment (SFO 84015**) Basic Phones (SFO 84016) 4G LTE Routers - with voice only(SFO 84019) or Voice and Data (SFO 84020) 4G LTE Broadband Router- Data Only (SFO 84018) Jetpacks/Netbooks/ /Notebooks/ USBs (SFO 84022, 84023, 84024) and Tablets (including Google Chromebook) (SFO 84021) / 4G LTE Internet device (Installed)1 (SFO 84025) Wireless Home Phone2 (SFO 84017) Select Connected Devices3 (SFO 84026, 84027, 84028) Monthly Line Access Fee $40.00 per device $20.00 per device $20.00 per device $20.00 per device $10.00 per device $10.00 per device $20.00 per device $5.00 per device Select Data Amount (Talk and Text are Unlimited) The calling plans below reflect the monthly access fee discount. No additional discounts apply. Monthly Account Access Fee Maximum Number of Lines (per billing account) Shared Data Allowance Domestic Data Overage Safety Mode6 (682) Safety Mode6 (672) Carryover Data (671) Data Boost7 (681) $35.004 $27.30 (96325) Up to 10 Phone/ Internet devices Up to 20 Connected Devices 2 GB (Small) $15.00 per 1 GB $5.00 N/A Included $15.00 for 1 GB (optional) $50.00 $39.00 (96327) 4 GB (Medium) $5.00 N/A $70.00 $54.60 (96328) 8 GB (Large) $5.00 N/A $90.005 $70.20 (96329) 16 GB (XLarge) N/A Included $110.005 $85.80 (96331) 24 GB (XX Large) N/A Included $135.005 $105.30 (96333) 30 GB N/A Included $180.005 $140.40 (963334) 40 GB N/A Included $225.005 $175.50 (96335) 50 GB N/A Included $270.005 $210.60 (96337) 60 GB N/A Included $360.005 $280.80 (96339) 80 GB N/A Included $450.005 $351.00 (96340) 100 GB N/A Included General Allowance Minutes Unlimited Domestic Long Distance Included BlackBerry Enterprise Server $15.00 per line (77515) Cloud Storage 5 GB per line Unlimited Domestic Text and Multimedia Messages and International Text Messages Included Domestic Mobile Hotspot Included Notes: Data-only devices on these plans share in the data allowance but do not share the minutes or message allowance unless the device is capable. 1LTE Internet (Installed) require the new Verizon Plans 8 GB or higher.2Wireless Home Phone shares in the unlimited voice minutes but not the message or data allowance. 3Only approved connected devices are eligible. 4No additional discounts apply. 5All Talk, Text and Data allowances on the new Verizon Plan XL or higher plans include Mexico and Canada and unlimited calling from the US to Mexico and Canada at no additional charge. TravelPass (including Canada and Mexico) may be added on the new Verizon Plan XL or higher plans for access to additional countries. 6Safety Mode speeds do not impact the quality of HD calls; however, the speeds will impact HD video calling experience. While in Safety Mode customer can return to full 4G LTE speed by purchasing Data Boost or switching to a plan with a higher data allowance. 7Data Boost allows additional 4G LTE data to be purchased when needed. Accounts with Data only devices must use the data only plans. Current coverage details can be found at www.verizonwireless.com. Access fee discounts applied at the account level only. Text Messages originating from Mexico are $0.50 per message sent (per recipient) and $0.05 per message received on the 2GB, 4GB, and 8 GB plans. Data allowances from new Verizon Plans with not share with any other Verizon Plans. The new Verizon Plan is not compatible with Private Network Traffic Management. Sharing: Sharing is available only among Government Subscribers on Verizon Plans – Talk Text and Data for up to 10 lines on the same account. **The $40.00 monthly line access for Smartphones will automatically change to $20.00 monthly line access once the line term is fulfilled. Proration may occur. Promotions may be available for Monthly Line and Account Access Fees. Please contact your Government Account Manager. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 5 of 41 The New Verizon Plan for Business Plan - Talk, Text and Data Plans: Government Subscribers (Up to 25 Phone/Internet Devices/50 Connected Devices) Select Device Type Smartphones Purchased at Discounted Price (Matrix) (SFO 84040) Smartphones Purchased at Full Retail Price or Customer Provided Equipment (SFO 84041**) Basic Phones (SFO 84042) 4G LTE Routers - with voice only(SFO 84044) or 4G LTE Routers (with voice and data bundle) (SFO 84045) 4G LTE Routers (data only) (SFO 84018) Jetpacks(SFO 84022)/ Netbooks/ Notebooks(SFO 84024)USBs(SFO 84023) Tablets (including Google Chromebook) (SFO 84021) Wireless Home Phone1(SFO 84043) Select Connected Devices2 (SFO 84026, 84027, 84028) Monthly Line Access Fee $35.00 per device $15.00 per device $15.00 per device $15.00 per device $10.00 per device $10.00 per device $15.00 per device $5.00 per device Select Data Amount (Talk and Text are Unlimited) The calling plans below reflect the monthly access fee discount. No additional discounts apply. Monthly Account Access Maximum Number of Lines (per billing account) Shared Data Allowance Domestic Data Overage Safety Mode3 (672) Carryover Data (671) Data Boost4 (681) $175.00 $136.50 (96345) Up to 25 Phone/ Internet devices Up to 50 Connected Devices 25 GB3 $15.00 per 1 GB Included Included $15.00 for 1 GB (optional) $245.00 $191.10 (96366) 35 GB3 $350.00 $273.00 (96368) 50 GB3 $500.00 $390.00 (96369) 85 GB3 $750.00 $585.00 (96370) 150 GB3 $1000.00 $780.00 (96371) 200 GB3 General Allowance Minutes Unlimited Domestic Long Distance Included BlackBerry Enterprise Server $15.00 per line (77515) Cloud Storage 5 GB per line Unlimited Domestic Text and Multimedia Messages and International Text Messages Included Domestic Mobile Hotspot Included Notes: Data-only devices on these plans share in the data allowance but do not share the minutes or message allowance unless the device is capable. 1Wireless Home Phone shares in the unlimited voice minutes but not the message or data allowance. 2Only approved connected devices are eligible. All Talk, Text and Data allowances on the new Verizon Plan for Business Plan include Mexico and Canada, and unlimited calling from the US to Mexico and Canada at no additional charge. TravelPass (including Canada and Mexico) may be added to the new Verizon Plan for Business plans for access to additional countries. 3Safety Mode speeds do not impact the quality of HD calls; however, the speeds will impact HD video calling experience. While in Safety Mode customer can return to full 4G LTE speed by purchasing Data Boost or switching to a plan with a higher data allowance. 4Data Boost allows additional 4G LTE data to be purchased when needed. Accounts with Data only devices must use the data only plans. Current coverage details can be found at www.verizonwireless.com. Access fee discounts applied at the account level only. Included Text Messages originating in the U.S. to Canada and Mexico. The new Verizon Plan is not compatible with Private Network Traffic Management. Sharing: Customers subscribing to Verizon Plan for Business will be billed on separate billing accounts and invoices. Sharing is available only among Government Subscribers on these Verizon Plan for Business – Talk Text and Data with 11 or more lines on the same account. **The $35.00 monthly line access for Smartphones will automatically change to $15.00 monthly line access once the line term is fulfilled. Proration may occur. Promotions may be available for Monthly Line and Account Access Fees. Please contact your Government Account Manager. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 6 of 41 The New Verizon Single Basic Phone Plan: Unlimited Talk and Text Only The calling plan below reflects the monthly access fee discount. No additional discounts apply. Basic Phones Only 3G or 4G LTE Basic Phone 4G LTE Basic Phone Only Monthly Device Access Fee $30.00 (98245) $50.00 $39.00 (98817) Domestic Anytime Voice Allowance Per Month Unlimited Voice Per Minute Rate (after allowance) N/A Domestic Data Allowance 500 MB 4 GB Data Overage $5.00 per 500 MB Domestic Long Distance Included Domestic Text Messages Unlimited Notes: Current coverage details can be found at www.verizonwireless.com. Not eligible for monthly access discounts. The new Verizon Basic Plan is not available for accounts with Smartphones data devices, or connected devices- Customers subscribing to the new Verizon Single Basic Plan and non- new Verizon Basic Plan will be billed on separate billing accounts and invoices. The New Verizon Single Basic Plan is a standalone plan. Nationwide Flat Rate Calling Plan The calling plan below reflects the monthly access fee discount. No additional discounts apply. Nationwide Flat Rate Government Subscribers Only Monthly Access Fee $11.99 (73809) Monthly Anytime Voice Minutes 0 Domestic Voice Per Minute Rate $0.25 Domestic Long Distance Included Data Sent or Received $1.99/ MB or per data package1 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1Smartphones and Multimedia Phones require a data package. NVLPT Local Flat Rate Calling Plan The calling plan below reflects the monthly access fee discount. No additional discounts apply. NVLPT Local Flat Rate Calling Plan Government Subscribers Only Monthly Access Fee $8.99 (Market specific) Domestic Anytime Minutes 0 Per Minute Rate $0.10 Domestic Long Distance Included National Access Roaming $0.69 Domestic Data Sent or Received $1.99 / MB or per data package1 Optional Features 1000 Domestic Night & Weekend Minutes OR 1000 Nationwide Mobile to Mobile $5.00 additional monthly access fee per line (72062) Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 13G/4G Smartphones and 3G/4G Multimedia Phones require a data package. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 7 of 41 Nationwide Push to Talk Plus Calling Plan (non-share) The calling plan below reflects the monthly access fee discount. No additional discounts apply. Nationwide Push to Talk Plus (non-share) Government Subscribers Only Monthly Access Fee $19.99 (94244/92857) Monthly Anytime Voice Minutes1 0 One to One & Group Talk Unlimited Data Sent or Received $1.99/ MB or per data package2 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Push to Talk Plus terms and conditions apply. 1Subscribers to the Push to Talk Plus Unlimited Calling Plan cannot place or receive regular cellular wireless calls other than to 611 and 911. (These calls may be placed anywhere in the Nationwide Rate and Coverage Area). If the voice block feature is removed, subscribers will be charged $0.25 per minute for non-Push to Talk Plus voice calls. 2Smartphones and Multimedia Phones require a data package. Nationwide Add-a-Line Voice Plan with Push to Talk Plus The calling plan below reflects the monthly access fee discount. No additional discounts apply. Nationwide Add-a-Line Voice Plan with Push to Talk Plus Government Subscribers Only Monthly Access Fee $18.991 (94990/92904) Monthly Anytime Voice Minutes 0 Minutes Minutes can share minutes from voice and/or voice & data bundle plans Push to Talk Plus Unlimited Domestic Voice Per Minute Rate $0.25 Domestic Night & Weekend Minutes Unlimited Domestic Nationwide Mobile to Mobile Unlimited Domestic Long Distance Included Domestic Roaming Rate per minute $0.25 Domestic Text (SMS) and Multimedia (MMS) Messages 100 Included Overage: $0.20 (SMS) Text, $0.25 (MMS) sent/received Data Sent or Received $1.99/ MB or per data package2 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Push to Talk Plus terms and conditions apply. 1No More than 50% of plans on a single account can be placed on the $18.99 Additional Line Voice & Push to Talk Plus plans 2Smartphones and Data Multimedia Phones require a data package. Account Share Voice Sharing: At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 8 of 41 NVLPT 3G/4G Nationwide Email for Government Calling Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. NVLPT Nationwide for Government 400 Voice Minutes 600 Voice Minutes 1000 Voice Minutes Monthly Access Fee (non-share) $61.53 (74510) $78.19 (74512) $93.58 (74514) Monthly Access Fee less discount (non-share) $47.99 $60.99 $72.99 Monthly Access Fee (Account share) $64.09 (74511) $80.76 (74513) $96.16 (74515) Monthly Access Fee less discount (share) $49.99 $62.99 $75.00 Monthly Access Fee (EVP (Profile) share) $64.09 (76369) $80.76 (76370) $96.16 (76371) Monthly Access Fee less discount (EVP (Profile) share) $49.99 $62.99 $75.00 Monthly Anytime Voice Minutes 400 600 1000 Friends & Family (up to 10 numbers per account) Included Voice Overage Rate $0.25 per minute Domestic Mobile to Mobile Unlimited Domestic Night & Weekend Minutes Unlimited Domestic Long Distance Included Domestic Data Allowance Unlimited* Domestic Text (SMS) and Multimedia (MMS) Messages Unlimited Optional Features Domestic Push To Talk Plus $2.00 (Smartphone- (76785/81129/81174) Unlimited Hotspot/Tethering $10.00 per line (82219 3G) (76445 4G) Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Account Share Voice Sharing: At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. EVP (Profile) Share - Voice Sharing (Domestic Only): At the end of each bill cycle, any unused voice allowances for lines sharing across multiple accounts will be applied proportionally to all lines with overages. *Verizon Wireless will limit the data throughput speeds should 25 GB of data usage be reached in any given billing cycle on any line. Data throughput speeds for additional usage will be limited for the remainder of the then-current bill cycle for the line(s) that exceed the 25 GB high-speed data usage threshold. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB with prior written notice. . NVLPT 3G/4G Nationwide Email for Government Nationwide Add-a-Line Plan The calling plan below reflects the monthly access fee discount. No additional discounts apply. NVLPT 3G/4G Nationwide Email for Government Add-a-Line Plan Government Subscribers Only Monthly Access Fee $35.991 (86140) Monthly Anytime Voice Minutes 0 Minutes Minutes can share minutes from voice & data bundle plans Domestic Voice Per Minute Rate $0.25 Domestic Night & Weekend Minutes Unlimited Domestic Nationwide Mobile to Mobile Unlimited Domestic Long Distance Included Domestic Data Allowance Unlimited* Domestic Text (SMS) Unlimited Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1The $35.99 Add-a-Line plan can only be 50% of an accounts total share lines. The $35.99 Add-A-Line plan shares with the NVLPT Nationwide for Government 400, 600 and 1000 minute plans. * Verizon Wireless will limit the data throughput speeds should 25 GB of data usage be reached in any given billing cycle on any line. Data throughput speeds for additional usage will be limited for the remainder of the then-current bill cycle for the line(s) that exceed the 25 GB high-speed data usage threshold. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB with prior written notice. Account Share Voice Sharing: At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 9 of 41 NVLPT Smartphone Calling Plans for Government Subscribers The calling plan below reflects the monthly access fee discount. No additional discounts apply. Includes Wireless Sync or BlackBerry Solution compatible with Microsoft Outlook, Lotus Notes, POP3, and IMAP email accounts. . Monthly Access Fee $35.99 (86139) Domestic MB Allowance Unlimited* Domestic Voice Per Minute Rate1 $0.12 Domestic Nationwide Mobile to Mobile Unlimited Domestic Text (SMS) and Multimedia (MMS) Messages Unlimited Domestic Long Distance2 Included Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Subject to the Data Services terms and conditions; additional terms and conditions apply to Unlimited, Megabyte (MB), Smartphone and BlackBerry Plans. Current coverage details can be found at www.verizonwireless.com. 1Per minute roaming applies to Voice calls.2Domestic long distance is included when placing calls in the America’s Choice home airtime rate and coverage area. * Verizon Wireless will limit the data throughput speeds should 25 GB of data usage be reached in any given billing cycle on any line. Data throughput speeds for additional usage will be limited for the remainder of the then-current bill cycle for the line(s) that exceed the 25 GB high-speed data usage threshold. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB with prior written notice.. Flexible Business Plans For Basic & Smartphones The calling plans below reflect the monthly access fee discount. No additional discounts apply. Basic Phones* Smartphones1 Monthly Access Fee $35.00 (92731) $65.00 (92732) $75.00 (92736) $85.00 (92737) $95.00 (92738) $105.00 (92740) Monthly Access Fee less discount $27.30 $50.70 $58.50 $66.30 $74.10 $81.90 Shared Data Allowance 100 MB 2 GB 4 GB 6 GB 8 GB 10 GB Data Overage $10.00 per GB Mobile Hotspot2 Included Monthly Anytime Minutes Unlimited Messaging Allowance3 Unlimited Domestic and International Messaging Optional Features Domestic Push to Talk Plus Additional monthly access fee per line $5.00 per line Notes: Current coverage details and additional plan and feature information can be found at www.verizonwireless.com. No Domestic Roaming or Long Distance Charges. 4G service requires 4G Equipment and 4G coverage. Government subscribers only. * Basic phones may only be added to an account with at least 1 Smartphone (bill account level). 1. Access to corporate email using BlackBerry Enterprise Server (BES) is available for an additional $15.00 per line. 2. Mobile Hotspot is available on all capable devices and allows you to use your device and share data allowance with multiple Wi-Fi enabled devices. 3. Unlimited Messaging from within the United States to anywhere in the world where messaging services are available. Data Sharing: Lines activated on these plans can only share with other lines on these plans and with lines on the Flexible Business Plans for Data Devices. At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 10 of 41 WIRELESS DATA SERVICES Data Only Plans: Government Subscribers (Up to 10 Data Only Devices) Select Device Type Jetpacks1 (SFO 77555) USBs (SFO 77555) Netbooks/ Notebooks, LTE Internet (SFO 77555, 78045) 4G LTE Routers with data only (SFO 77555) Verizon 4G LTE Broadband Routers with data only (SFO 79392) Tablets (including Google Chromebook and Amazon Kindle Fire) (SFO 77567) Connected Devices (SFO 78303) Monthly Line Access Fee $20.00 per device $20.00 per device $20.00 per device $20.00 per device $20.00 per device $10.00 per device $5.00 per device Select Data Amount The calling plans below reflect the monthly access fee discount. No additional discounts apply. Monthly Account Access Maximum Number of Devices (per billing account) Shared Data Allowance Domestic Data Overage $20.002 (90525) Tablet & Connected Devices only Up to 10 2GB $15.00 per 1 GB $30.002 (86504) 4 GB $40.00 $31.20 (86505) 6 GB $50.00 $39.00 (86506) 8 GB $60.00 $46.80 (86507) 10 GB $70.00 $54.60 (86508) 12 GB $80.00 $62.40 (86509) 14 GB $90.00 $70.20 (86510) 16 GB $100.00 $78.00 (86511) 18 GB $110.00 $85.80 (86512) 20 GB $185.00 $144.30 (86513) 30 GB $260.00 $202.80 (87271) 40 GB $335.00 $261.30 (87272) 50 GB $410.00 $319.80 (90910) 60 GB $560.00 $436.80 (90911) 80 GB $710.00 $553.80 (90912) 100 GB Domestic Messaging (Text and Multimedia) $10.00 for 1000 message package Pay as you go or message package overage: $0.20 (SMS) Text, $0.25 (MMS) sent/received Cloud Storage 5 GB per line (must be selected) Notes: Data-only devices on these plans share in the data allowance but do not share the minutes or message allowance unless the device is capable. Verizon Plans data-only plans are not available for accounts with Smartphones, basic phones or connected devices with voice. 1LTE Internet (installed) devices require a data package of 10 GB or higher. 2No additional discounts apply. Current coverage details can be found at www.verizonwireless.com. Access fee discounts applied at the account level only. Sharing: Customers subscribing to Verizon Plans - Data Only - will be billed on separate billing accounts and invoices. Sharing is available only among Government Subscribers to these Data Only Plans - Data Only on the same account. Promotions may be available for Monthly Line and Account Access Fees. Please contact your Government Account Manager. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 11 of 41 Business Data Only Plans: Government Subscribers (Up to 25/50/100 Data Only Devices) Select Device Type Jetpacks (SFO 77555) USBs (SFO 77555) Netbooks/ Notebooks, LTE Internet (SFO 77555, 78045) 4G LTE Broadband Router (SFO 77555) Verizon 4G LTE Broadband (SFO 79392) Tablets (including Google Chromebook) (SFO 77567) Connected Devices (SFO 78303) Monthly Line Access Fee $20.00 per device $20.00 per device $20.00 per device $20.00 per device $20.00 per device $10.00 per device $5.00 per device Select Data Amount The calling plans below reflect the monthly access fee discount. No additional discounts apply. Monthly Account Access Maximum Number of Devices (per billing account) Shared Data Allowance Domestic Data Overage $185.00 $144.30 (87184) Up to 25 30 GB $15.00 per 1 GB $245.00 $191.10 (87185) 40 GB $350.00 $273.00 (87186) 50 GB $410.00 $319.80 (90430) Up to 50 60 GB $560.00 $436.80 (90431) 80 GB $710.00 $553.80 ( 90429) 100 GB $1,025.00 $799.50 (91521) Up to 100 150 GB $1,400.00 $1,092.00 (91520) 200 GB Domestic Text Messaging 10.00 for 1000 text and multi media Overage: $0.20 (SMS) Text, $0.25 (MMS) sent/received Optional Cloud Storage 25 GB per line (must be selected) Notes: Data-only devices on these plans use the data allowance but do not use the minutes or message allowance unless the device is capable. The Small Business for data-only devices is not available for accounts with Smartphones, basic phones or connected devices with voice. Current coverage details can be found at www.verizonwireless.com. Access Fee discounts applied at the account level only. Sharing: Sharing is available only among Government Subscribers to these Business Data Only Plans - Data Only. Calling plan changes may not take effect until the billing cycle following the change request. Text, Picture and Video messages are not eligible for sharing. Data allowances from Business Data Only plans will not share with any non- Business Data Only Plans. Safety Mode, Carryover Data and Data Boost features cannot be added to data-only plans. Promotions may be available for Monthly Line and Account Access Fees. Please contact your Government Account Manager. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 12 of 41 Flexible Business Plans For Data Devices The calling plans below reflect the monthly access fee discount. No additional discounts apply. Connected Devices Connected Devices, Tablets, Netbooks, Notebooks Connected Devices, Tablets, Netbooks, Notebooks, Jetpacks, USBs, Mobile Broadband Devices Monthly Access Fee $5.00 (92739) $10.00 (92741) $35.00 (92742) $45.00 (92744) $55.00 (92745) $65.00 (92746) $75.00 (92747) Monthly Access Fee less discount $5.00 $10.00 $27.30 $35.10 $42.90 $50.70 $58.50 Shared Data Allowance 1 MB 100 MB 2 GB 4 GB 6 GB 8 GB 10 GB Data Overage Rate $10.00 per GB Notes: Current coverage details and additional plan and feature information can be found at www.verizonwireless.com. 4G service requires 4G Equipment and 4G coverage. Government subscribers only. Data Sharing: These plans only share with other lines on these plans and with lines on the Flexible Business Plans for Basic & Smartphones. At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. Flexible Business Plans For Data Devices - Connected Device / Internet with Voice Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. Connected Device* Broadband Router Monthly Access Fee $5.00 (94532) $65.00 (94495) $75.00 (94496) $85.00 (94497) $95.00 (94500) $105.00 (94504) Monthly Access Fee less discount $5.00 $50.70 $58.50 $66.30 $74.10 $81.90 Shared Data Allowance 1 MB 2 GB 4 GB 6 GB 8 GB 10 GB Domestic Data Overage Rate $10.00 per GB Notes: Current coverage details and additional plan and feature information can be found at www.verizonwireless.com. 4G service requires 4G Equipment and 4G coverage. Government subscribers only. Data Sharing: These plans only share with other lines on these plans and with lines on the Flexible Business Plans for Basic & Smartphones. At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. Custom Flat Rate Mobile Broadband - Government Government Subscribers Only This plan is not eligible for monthly access fee discounts. Monthly Access Fee $34.99 (99716) Domestic Data Allowance* Unlimited Overage Rate per KB NA NOTE: Subject to the Mobile Broadband terms and conditions; additional terms and conditions apply to Unlimited, Megabyte (MB), and Smartphone data Plans. Throughput speeds on the Custom Flat Rate Mobile Broadband will be limited up to 600kbps throughout the duration of each billing cycle while on the Verizon Wireless 4G network only. Data speeds are not guaranteed while on Extended or roaming partner networks. Devices utilized in conjunction with the Custom Flat Rate Mobile Broadband plan are limited to mobile (non-stationary) applications. Dedicated internet connections on stationary router devices and streaming video on stationary video surveillance cameras are expressly prohibited on this rate plan. Custom Mobile Broadband Plan II – Government Government Subscribers Only This plan is not eligible for monthly access fee discounts. Monthly Access Fee $44.99 (99717) Domestic Data Allowance Unlimited Overage Rate Per KB NA NOTE: Subject to the Mobile Broadband terms and conditions; additional terms and conditions apply to Unlimited, Megabyte (MB), and Smartphone data Plans. Verizon Wireless will limit throughput of data speeds should 30GB of data be used within a given bill cycle. Devices utilized in conjunction with the Custom Mobile Broadband Plan II are limited to mobile (non-stationary) applications. Data speeds are not guaranteed while on Extended or roaming partner networks. Dedicated internet connections on stationary router devices and streaming video on stationary video surveillance cameras are expressly prohibited on this rate plan. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 13 of 41 Data Packages for Feature Phones and Smartphones The Data Packages are eligible for monthly access fee discounts and promotions, when available1 Monthly Access Per Line when added to an eligible voice plan Data Allowance Rate After Allowance Optional Business Email Feature Compatible with server based email solutions N/A -0- $1.99 per MB N/A $10.00 (77810) 75 MB $10.00 per each additional 75 MB of usage N/A $12.00 1 (Basic Devices Only) 300 MB $15.00 per each additional GB of usage N/A $30.00 $23.40 2, 3 (Smartphone 76375) (Basic 76381) 2 GB2 $10.00 per each additional GB of usage $15.00 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options.. 1The $12.00/300MB data package for Basic Devices can be added to a voice only price plan with a monthly access fee of $15.99 or higher, this feature cannot be activated on a Smartphone Device. 2The $30.00/2GB data package is eligible for a monthly access fee discounts when combined with select Business calling plans 3Smartphone Subscribers require a data package with a minimum allowance of 2GB. Personal Email Feature is included with all data packages contained herein. Mobile Broadband Data Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. Mobile Broadband Pricing for Tablets, Netbooks, 4G LTE Modems, 3G & 4G LTE Dedicated Mobile Hotspots Monthly Access Fee $30.001 (85320/85322) $39.99 (84357/ 98715) Domestic Monthly Data Allowance 2GB Unlimited* Per GB Rate After Allowance $10.00 per each additional GB of usage N/A Domestic Per Minute Rate2 $0.25 per minute Domestic Long Distance Included Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 4G and 3G Mobile Broadband coverage details can be found at www.verizonwireless.com. 4G service requires 4G equipment and 4G coverage. 2Per Minute Rate applies to voice calls and other non-NationalAccess data usage in the United States. * Verizon Wireless will limit the data throughput speeds should 25 GB of data usage be reached in any given billing cycle on any line. Data throughput speeds for additional usage will be limited for the remainder of the then-current bill cycle for the line(s) that exceed the 25 GB high-speed data usage threshold. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB with prior written notice. Public Sector Mobile Broadband Share Plans: Government Subscribers Only The calling plans below reflect the monthly access fee discount. No additional discounts apply. Public Sector Mobile Broadband 5 Gigabytes 10 Gigabytes 20 Gigabytes Monthly Access Fee $39.99 (90239) $59.99 (90240) $99.99 (90241) Shared Domestic Data Allowance 5GB 10GB 20GB Overage Per Gigabyte $8.00 Per Gigabyte Note: This plan is available for domestic data only devices, on the Verizon Wireless network only. Data Sharing: At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. Current NationalAccess and Mobile Broadband coverage details can be found at www.verizonwireless.com. New activations on these service plans require 4G LTE devices. Existing customers transitioning to one of these service plans are able to utilize existing 3G devices. The 5GB, 10GB, and 20GB Public Sector Mobile Broadband Plans are able to share with each other. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 14 of 41 MACHINE TO MACHINE (M2M) Mobile Broadband Machine to Machine (M2M) Share Group 1 Plans - Low Usage The data plans below reflect the monthly access fee discount. No additional discounts apply. Mobile Broadband Machine-to-Machine Plans 1 Megabyte 5 Megabytes 25 Megabytes 50 Megabytes 150 Megabytes Domestic Profile Shared Data Allowance 1 MB (87660) 5 MB (87661) 25 MB (87662) 50 MB (87663) 150MB (87664) Monthly Access Fee $5.00 $7.00 $10.00 $15.00 $18.00 Domestic Account Shared Data Allowance 1 MB (87640) 5 MB (87641) 25 MB (87642) 50 MB (87643) 150MB (87644) Monthly Access Fee $5.00 $7.00 $10.00 $15.00 $18.00 Overage Rate Per Megabyte $1.00 Mobile Broadband Machine to Machine (M2M) Share Group 2 Plans - High Usage The data plans below reflect the monthly access fee discount. No additional discounts apply. Mobile Broadband Machine-to-Machine Plans 250 Megabytes 1 Gigabyte 5 Gigabytes 10 Gigabytes Domestic Profile Shared Data Allowance 250 MB (87665) 1 GB (87668) 5 GB (87671) 10 GB (87673) Monthly Access Fee $20.00 $25.00 $50.00 $80.00 Monthly Access Fee less discount $20.00 $25.00 $39.00 $62.40 Domestic Account Shared Data Allowance 250 MB (87645) 1 GB (87646) 5 GB (87647) 10 GB (87648) Monthly Access Fee $20.00 $25.00 $50.00 $80.00 Monthly Access Fee less discount $20.00 $25.00 $39.00 $62.40 Overage Rate Per Megabyte $0.015 Note: Machine to Machine coverage included the Verizon Wireless 4G, 3G and 3G Extended networks. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Government Subscribers may supply their own authenticated Equipment (CPE) approved by Verizon Wireless to be activated on these plans. Netbook, Smartphone, and Tablet devices are not eligible for Mobile Broadband M2M pricing. 4G service requires 4G Telemetry equipment and 4G coverage. All terms and conditions of the Agreement apply to M2M service and M2M Lines as a Wireless Service. Sharing. Customer may select either the Account Share or Multi-Account Share option on the Mobile broadband Machine-to-Machine (M2M) Share Plans. Please note that the low usage cannot share with the high usage plans on profile share. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 15 of 41 Public Sector Mobile Broadband Machine to Machine (M2M) Share Plans: Government Subscribers Only The calling plans below reflect the monthly access fee discount. No additional discounts apply. Public Sector Mobile Broadband 5 Gigabytes 10 Gigabytes 20 Gigabytes Monthly Access Fee $39.99 (90233) $59.99 (90234) $99.99 (90235) Shared Domestic Data Allowance 5GB 10GB 20GB Overage Per Gigabyte $8.00 Per Gigabyte Note: This plan is available for domestic data only devices, on the Verizon Wireless network only. Data Sharing: At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. Current NationalAccess and Mobile Broadband coverage details can be found at www.verizonwireless.com. New activations on these service plans require 4G LTE devices. Netbook, Smartphone, and Tablet devices are not eligible for Mobile Broadband M2M pricing. Existing customers transitioning to one of these service plans are able to utilize existing 3G devices. Sharing. The 5GB, 10GB, and 20GB Public Sector Mobile Broadband Machine to Machine Plans are able to share with each other. 3G/4G Mobile Broadband Machine-to-Machine (M2M) Wireless Backup Router Plan: Government Subscribers Only The data plan below reflect the monthly access fee discount. No additional discounts apply. 3G/4G M2M Wireless Backup Router Plan Monthly Access Fee (non-pooled) $10.00 (868473G/868484G) Domestic Data Allowance Per Month 25 MB Share Option N/A Domestic Overage Rate Per GB $10.00 per GB Domestic Voice Rate Per Minute $0.25 per minute (Device Dependent) Text Messaging Per Message $0.20 per message sent or received (Device Dependent) International Roaming N/A. Verizon Wireless network only. Notes: Current coverage details can be found at www.verizonwireless.com. See the attached M2M Data Plan and Feature Details as well as Calling Plan and Feature Details in your Agreement for important information about calling plans, features and options. During an outage of the primary connection, all usage within the billing cycle in excess of the 25 MB allowance will be charged at the overage rate of $10.00 per GB. Text messaging feature packages may be added to this plan. The Wireless Router Plan is approved for use as a backup solution for business continuity only and is not to be used for primary connectivity. Verizon Wireless reserves the right to move Customer to the standard commercial 5 GB M2M price plan should usage on the lines provisioned on the M2M Wireless Backup Router Plan exceed 1 GB for three (3) consecutive months. M2M Wireless Backup Router Plan may be used with Private Network. M2M router devices must be approved for use on Verizon Wireless’ network; no other device types may be activated on this plan. Not eligible for Verizon Wireless Government Equipment Matrix pricing. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 16 of 41 INTERNATIONAL WIRELESS SERVICES NVLPT Nationwide International Email for Government Calling Plans The calling plans below reflect the monthly access fee discount. No additional discounts apply. NVLPT Nationwide for Government 400 Voice Minutes 600 Voice Minutes 1000 Voice Minutes Monthly Access Fee (non-share) $84.14 (74524/ 86740) $99.99 (74526/86742) $114.62 (74528/ 86744) Monthly Access Fee (non-share) less discount $65.63 $77.99 $89.40 Monthly Access Fee (share) $86.57 (74525/ 86741) $102.43 (74527/ 86743) $117.06 (74529/ 86745) Monthly Access Fee (share) less discount $67.52 $79.89 $91.30 Monthly Anytime Voice Minutes 400 600 1000 Friends & Family (up to 10 numbers per account) Included Voice Overage Rate $0.25 per minute Domestic Mobile to Mobile Unlimited Domestic Night & Weekend Minutes Unlimited Domestic Long Distance Included Domestic Email Allowance Unlimited1 International Email Allowance Unlimited Domestic Messaging Unlimited Optional Features Domestic Push To Talk Plus $2.00 (Smartphone- 76785/81129/81174) Notes: Requires a 4G Global capable smartphone. Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. The domestic data allowance applies in the United States. †The international travel data allowance applies in Canada, Mexico, and the rest of the world where coverage is available. To see supported countries and rates for services such as voice and messaging, go to verizonwireless.com/international. Verizon Wireless will terminate a line of service if more than half of the usage over three consecutive billing cycles is outside of the United States. 1Domestic Data Allowance: Verizon Wireless will limit the data throughput speeds should 25 GB of data usage be reached in any given billing cycle on any line. Data throughput speeds for additional usage will be limited for the remainder of the then-current bill cycle for the line(s) that exceed the 25 GB high-speed data usage threshold. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB with prior written notice.. Account Share - Voice Sharing (Domestic Only): At the end of each bill cycle, any unused voice allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the highest overage need. Profile Share - Voice Sharing (Domestic Only): At the end of each bill cycle, any unused voice allowances for lines sharing across multiple accounts will be applied proportionally to all lines with overages. Zone 1 Countries are as follows: Aland Islands, Albania, American Samoa, Andorra, Anguilla, Antigua, Antarctica, Argentina, Aruba, Australia, Austria, Bahamas, Barbados, Belarus, Belgium, Belize, Bermuda, Bolivia, Bosnia and Herzegovina, Brazil, British Virgin Islands, Brunei, Bulgaria, Cambodia, Cayman Islands, Chile, China, Christmas Island, Colombia, Cook Islands, Costa Rica, Croatia, Cyprus, Czech Republic, Denmark, Dominica, Dominican Republic, Ecuador, El Salvador, England, Estonia, Falkland Islands, Faroe Islands, Fiji Islands, Finland, France, French Guiana, French Polynesia, Germany, Gibraltar, Greece, Greenland, Grenada, Guadeloupe, Guam, Guatemala, Guernsey, Guyana, Haiti, Honduras, Hong Kong, Hungary, Iceland, India, Ireland, Isle of Man, Italy, Jamaica, Jersey, Latvia, Liechtenstein, Lithuania, Luxembourg, Macau, Macedonia, Malaysia, Malta, Martinique, Moldova, Monaco, Montenegro, Nauru, Netherlands, Netherlands Antilles, New Caledonia, New Zealand, Nicaragua, Norfolk Island, Northern Ireland, Northern Mariana Island, Norway, Palau, Panama, Papua New Guinea, Paraguay, Peru, Poland, Portugal, Reunion, Romania, Russia, Samoa, San Marino, Scotland, Serbia, Singapore, Slovakia, Slovenia, Solomon Islands, Spain, South Korea, St. Barthelemy, St. Kitts and Nevis, St. Lucia, St. Martin, St. Vincent & Grenadines, Suriname, Svalbard, Sweden, Switzerland, Taiwan, Thailand, Tonga, Turkey, Turks and Caicos Islands, Ukraine, Uruguay, Vanuatu, Vatican City, Venezuela, Vietnam and Wales. Zone 2 Countries are as follows: Afghanistan, Algeria, Angola, Armenia, Azerbaijan, Bahrain, Bangladesh, Benin, Bhutan, Botswana, Burkina Faso, Burundi, Cameroon, Cape Verde Islands, Central African Republic, Chad, Comoros, Congo, Cuba, Djibouti, East Timor, Egypt, Equatorial Guinea, Ethiopia, Gabon, Gambia, Georgia, Ghana, Guinea, Guinea Bissau, Indonesia, Iraq, Israel, Ivory Coast, Japan, Jordan, Kazakhstan, Kenya, Kuwait, Kyrgyzstan, Laos, Lebanon, Lesotho, Liberia, Libya, Madagascar, Malawi, Maldives, Mali, Mauritania, Mauritius, Mayotte Island, Micronesia, Mongolia, Montserrat, Morocco, Mozambique, Myanmar, Namibia, Nepal, Niger, Nigeria, Oman, Pakistan, Philippines, Qatar, Rwandese Republic, Sao Tome and Principe, Saudi Arabia, Senegal, Seychelles, Sierra Leone, South Africa, Sri Lanka, South Sudan, Sudan, Swaziland, Syria, Tajikistan, Tanzania, Togo, Trinidad and Tobago, Tunisia, Turkmenistan, Uganda, United Arab Emirates, Uzbekistan, Western Sahara, Yemen, Zambia and Zimbabwe. Other available countries will be billed at the Zone 2 rates. The list of countries is subject to change. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 17 of 41 International Options Monthly Features: Mexico and Canada The calling features below reflect the monthly access fee discount. No additional discounts apply. International Options Monthly Feature: Mexico and Canada 0 Voice Minutes 0 Voice Minutes 100 Voice Minutes 250 Voice Minutes 500 Voice Minutes Monthly Access Fee (1 Month)* $10.00 (SPO 428)* $20.00 (SPO 426)* $15.00 (SPO 441)* $30.00 (SPO 425)* $25.00 (SPO 443)* Monthly Access Fee less discount $10.00 $20.00 $15.00 $23.40 $25.00 International Options Monthly Recurring Feature: Mexico and Canada 0 Voice Minutes 0 Voice Minutes 100 Voice Minutes 250 Voice Minutes 500 Voice Minutes Monthly Access Fee (Recurring)** $10.00 (SPO 427)** $20.00 (SPO 446)** $15.00 (SPO 434)** $30.00 (SPO 424)** $25.00 (SPO 442)** Monthly Access Fee less discount $10.00 $20.00 $15.00 $23.40 $25.00 Voice Overage Rate Pay Go $0.10/minute $0.05/minute Data Allowance1 100 MB 250 MB 100 MB 250 MB 1 GB Data Overage Rate After Allowance2 $10.00/100 MB $20.00/1 GB Messaging Allowance3 Pay Go 100 sent; unlimited incoming 250 sent; unlimited incoming 500 sent; unlimited incoming Messaging Overage Rate After Allowance2 Pay Go $0.10/Sent Message $0.05/Sent Message Notes: Current coverage details and additional information can be found at www.verizonwireless.com. 1The data allowance applies in Canada and Mexico only, where coverage is available. All data usage, including dedicated Mobile Hotspot, deducts from the same data allowance. Requires an eligible domestic data plan or feature and an International GSM capable device. 2The overage rate is not eligible for discounts. 3Multimedia messages (MMS) are included in the allowance, but incur data transport charges (deducts from the International data allowance). Pay Go rates for International Voice, International Messaging, and Data Roaming can be found at www.verizonwireless.com/International. *This is a monthly feature and will be removed from the account one month after being added to an account. **This is a recurring feature and will remain on the account until removed. International Options Monthly Features: 140+ Countries The calling features below reflect the monthly access fee discount. No additional discounts apply. International Options Monthly Feature: 140+ Countries 0 Voice Minutes 0 Voice Minutes 100 Voice Minutes 250 Voice Minutes Monthly Access Fee (1 Month)* $25.00 (SPO 431)* $50.00 (SPO 433)* $40.00 (SPO 445)* $85.00 (SPO 423)* Monthly Access Fee less discount $19.50 $39.00 $31.20 $66.30 International Options Monthly Recurring Feature: 140+ Countries 0 Voice Minutes 0 Voice Minutes 100 Voice Minutes 250 Voice Minutes Monthly Access Fee (Recurring) $25.00 (SPO 412)** $50.00 (SPO 432)** $40.00 (SPO 444)** $85.00 (SPO 422)** Monthly Access Fee less discount $19.50 $39.00 $31.20 $66.30 Voice Overage Rate Pay Go $0.25/minute Data Allowance1 100 MB 250 MB 100 MB 250 MB Data Overage Rate After Allowance2 $25.00/100 MB Messaging Allowance3 Pay Go 100 sent; unlimited incoming 250 sent; unlimited incoming Messaging Overage Rate After Allowance2 Pay Go $0.25/Sent Message Notes: Current coverage details and additional information can be found at www.verizonwireless.com. 1The data allowance applies in 140+ countries where coverage is available. All data usage, including dedicated Mobile Hotspot, deducts from the same data allowance. Requires an eligible domestic data plan or feature and an International GSM capable device. 2The overage rate is not eligible for discounts. 3Multimedia messages (MMS) are included in the allowance, but incur data transport charges (deducts from the International data allowance). Pay Go rates for International Voice, International Messaging, and Data Roaming can be found at www.verizonwireless.com/International. 1This is a monthly feature and will be removed from the account one month after being added to an account. 2This is a recurring feature and will remain on the account until removed. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 18 of 41 Global Messaging1 No additional discounts apply. Global Text Messaging Canada $0.20 per recipient per message sent and $0.20 per message received, or according to your Domestic Messaging Plan Other Countries $0.50 per recipient per message sent and $0.05 per message received Global Picture and Video Messaging Canada, Mexico and Puerto Rico $0.25 per recipient per message sent or received, or according to your Domestic Messaging Plan, plus global data roaming charges. Other Countries $0.50 per recipient to send, $0.25 per message to receive plus global data roaming charges. Visit verizonwireless.com/internationalmms for supported countries. Notes: Current coverage details, and list of Other Available Countries can be found at www.verizonwireless.com/International. See attached Calling Plan and Feature Details for important information about calling plans, features and options. 1Applies to all global-capable devices. Must be added to a domestic 3G Mobile Broadband calling plan with domestic 3G Mobile Broadband Connect/Mobile Hotspot. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 19 of 41 ADDITIONAL WIRELESS OPTIONS One Talk Solution: Government Subscribers Only The plans/features below reflect any applicable discount. No additional discounts apply. One Talk is a business telephone system that combines landline and mobile phone capabilities into a fully integrated mobile and office solution providing a single telephone number (“Mobile Data Number/MDN”) with the same mobile and landline features. One Talk Solution: Desk Phone/Mobile Client Price Plan Type Line Level Plans (e.g. Flexible Business Plans, Custom Flexible Business Plans, Nationwide Plans) Account Level Plans (e.g. Verizon Plans, More Everything) One Talk Primary MDN Monthly Access Monthly Access One Talk Price Plan (100 MB Data) $10.00 $0.00 (the new Verizon Plan) One Talk Feature $15.00 $15.00 One Talk Line Access Charge N/A $10.00 One Talk Solution: Auto Receptionist (AR) /Hunt Group (HG) Each One Talk solution includes one (1) Auto Receptionist and one (1) Hunt Group at no cost per Customer. Price Plan Type Line Level Plans (e.g. Flexible Business Plans, Custom Flexible Business Plans, Nationwide Plans) Account Level Plans (e.g. Verizon Plans, More Everything) One Talk Primary MDN Monthly Access Monthly Access One Talk AR/HG Price Plan (100 MB Data) $10.00 $0.00 One Talk AR/HG Feature $10.00 $10.00 One Talk AR/HG Line Access Charge N/A $10.00 One Talk Solution: Additional Features One Talk Premium Voicemail for Andriod $2.99 $2.99 One Talk - Talk to Text for iOS $2.99 $2.99 Additional Devices A maximum of up to seven (7) devices can share one (1) MDN as follows: Up to 2 desk phones and up to 5 mobile clients; limit one (1) MDN per Government Subscriber line. Primary One Talk MDN Device Desk Phone1 Mobile Client2 (Includes Smartphones and Tablets) Auto Receptionist/ Hunt Group Additional devices per MDN: Monthly Access $0.00 for additional devices (excluding Smartphone devices with One Talk Dialer client) $0.00 for additional devices (excluding Smartphone devices with One Talk Dialer client) N/A Once a number is provisioned into an Auto Receptionist or Hunt Group, the phone number cannot be moved to a different One Talk device (i.e. desk phone or Smartphone). Notes: One Talk service is applied to the Verizon Wireless MDN and is available on all of the user’s devices. One Talk is not compatible with Fax machines, credit card POS solutions, or Security Systems. 4G LTE Coverage: Similar to Advanced Calling, One Talk calls drop if either party leaves Verizon 4G LTE coverage. When outside of the 4G LTE coverage area and without 3G or WiFi service, the device operates as a standard device (1X calling) with standard voice and SMS messaging capabilities with no One Talk features available to the user. Mobile client is the One Talk client. 1One (1) additional Desk Phone can be added as an additional device per MDN. 2Mobile Client eligible devices (includes devices from other carriers); Smartphones (without One Talk Dialer client), wireless and WiFi tablets; limit five (5) total per MDN (including primary device). Not currently available for Smartphone devices with One Talk Dialer client. Installing the One Talk Mobile client consumes an estimated 15MB of data. For additional information regarding One Talk please visit: http://www.verizonwireless.com/onetalk Custom Wireless Home Phone for Government Plan*: No Domestic Roaming or Long Distance Charges This Plan is NOT eligible for monthly access fee discounts. Monthly Access Fee $20.00 Monthly Anytime Minutes Unlimited Notes: Current coverage details and additional plan and feature information can be found at www.verizonwireless.com. Activation on this plan requires a separate billing account. Activations on this plan are limited to no more than 9 lines per account. *May only be activated on a Verizon Wireless Home Phone Approved Device. This is not a Home Phone service. This service is generally utilized to replace POTS lines. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 20 of 41 4G Smartwatch with NumberShare1 Unlimited Plan - Government This plan is not eligible for monthly access fee discounts. Monthly Access Fee $10.00 (13413) Domestic Anytime Minutes Unlimited Domestic Data Allowance2 Unlimited Domestic and International Messaging Allowance3 Unlimited Notes: Current coverage details and additional plan information can be found at www.verizonwireless.com. This plan is for use only in the United States on the Verizon Wireless 4G network. When NumberShare is active on a 4G Smartwatch, certain services will not work on the Smartwatch device including: Call Forwarding, No Answer Transfer, Busy Transfer, Caller Name ID, Voicemail (access voicemail on the Smartwatch device by dialing the host smartphone number and pin)), and RingBack Tones. Calls and messages to/from blocked contacts will not be blocked on the Smarthwatch when NumberSharing with a host smartphone. Verizon does not guarantee that NumberShare will work at all times in every situation and the service works only with eligible devices. 1. Only lines on select smartwatches with the NumberShare service can be activated on this plan. Certain conditions must be met prior to activation. This plan can only be used when paired with a Verizon Wireless Smartphone that has unlimited data. 2. Usage may be prioritized behind other customers in the event of network congestion. 3. Unlimited messaging from within the United States to anywhere in the world where messaging services are available. Private Network/Dynamic Mobile Network Routing (DMNR)/Service Based Access(SBA) Static IP – Isolated Pool w/Fixed End System (FES) [Internet Restricted] The Account Set-Up Fees below reflect any applicable discount. No additional discounts apply. Mobile Broadband and NationalAccess plans or features only Configuration Cost Per Account FES Connect Set-Up (One time fee) $1500.00 Private Network Only Private Network with DMNR Private Network with SBA Static IP Only Per Account Level Set-Up (One time fee) Waived for NASPO Valuepoint subscribers $250.00 $250.00 Waived for NASPO Valuepoint subscribers DMNR or SBA (Per build) $250.00 (Adding to existing Private Network Only) Public Safety Subscribers Account Set-Up: Verizon Wireless will waive all account set-up fees including the $1500.00 connection fee, $500.00 Account Set-up Fee and the DMNR/SBA for new Public Safety builds classified with the following NAICS (formerly SIC) Codes only. • 621910 Ambulance Services • 922160 Fire Protection • 922110 Courts • 922190 Other Justice, Public Order, and Safety Activities • 922120 Police Protection • 928110 National Security • 922130 Legal Counsel and Prosecution • 922150 Parole Offices and Probation Offices • 922140 Correctional Institutions Note: Set-Up fees apply to new Private Network/DMNR/SBA builds (Verizon Home Agent Portal (VHAP)). This applies to New Private Networks built as Standard, Parent or Child. Subscribers that are placed into this pool will be limited to utilizing the Verizon Wireless Network for transport to and from their FES connections to the Verizon Wireless Network. Static IP addresses will be available on remote access, Mobile Broadband and Unlimited NationalAccess plans or features only. Fees may not apply in certain VPN environments. Fees are per account level (regardless of the number of IPs ordered) selecting Static IP, and may apply in addition to $1500.00 Connect Fee in certain configurations. Does not include MPLS. Static IP: Fees are per account level (regardless of the number of IPs ordered). Static IP addresses will be available on remote access, Mobile Broadband and NationalAccess plans or features only. Static IP addresses may be reserved and should be assigned to the mobile numbers within 90 days. De-activated Static IP addresses will go into an “ageing pool” for 24 hours. After 24 hours, these Static IP addresses will be returned to reserved status for the account. Reserved Static IP addresses will be shown at the account level and can be viewed from the billing system. Feature activations will be stored in the “data warehouse” database along with the Static IP Address for reporting. A Static IP address is associated with the device’s MDN (Mobile Dialing Number). Each time the subscriber initiates a data session the Static IP address that is associated with their MDN is assigned to their device for each session. Subscribers completing an ESN (Electronic Serial Number) change will retain their Static IP address. Eligible 3G/4G data service: Mobile Broadband, Mobile Broadband Wireless Router, Telemetry (M2M), Wireless Email, or usage-based Megabyte pricing. DMNR and SBA are optional features that can co-exist on a Customer's Private Network profile. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 21 of 41 4G LTE Private Network Traffic Management (PNTM) Feature: Private IP Only (fixed WAN) Metered Data Pricing only. Not compatible with Unlimited Data Plans (PNTM feature is available for use with Verizon Wireless Private Network and 4G LTE devices only.) The plans below reflect any applicable discount. No additional discounts apply. Class of service (“CoS”) Customer can allocate bandwidth for applications into the Mission Critical CoS according to the PNTM Service Option selected. Remaining 4G LTE bandwidth supports Best Effort CoS. Mission Critical CoS Applications Recommended for video, Voice over IP, interactive services, and other mission critical applications Best Effort CoS Applications Suitable for best effort applications (e.g. email, web browsing) PNTM Service Options: Enhanced(Entry Level) Premium (Mid Level) Public Safety (Highest Level) (Qualifying Public Safety NAICS Only) Monthly Access Fee (per line) Waived Waived Waived Mission Critical CoS Speeds Mapped Up to 0.5 Mbps Mapped Up to 2 Mbps Mapped Up to 2 Mbps Best Effort CoS Applications Speeds Remaining available 4G LTE bandwidth Remaining available 4G LTE bandwidth Remaining available 4G LTE bandwidth RF Priority on access network N/A N/A During heavy network usage periods Qualifying Public Safety NAICS: Public Safety Subscribers classified with the following NAICS codes, performing First Responder responsibilities only. The Public Safety PNTM service option is not an on demand service. The Public Safety PNTM must be provisioned on the account prior to use in the event of an emergency situation. • 621910 Ambulance Services • 922150 Parole Offices and Probation Offices • 922110 Courts • 922160 Fire Protection • 922120 Police Protection • 922190 Other Justice, Public Order, and Safety Activities • 922130 Legal Counsel and Prosecution • 928110 National Security • 922140 Correctional Institutions Notes. 4G LTE Private Network subscribers with unlimited data plans are ineligible for Private Network Traffic Management. This service is only available while on Verizon Wireless’ 4G network and is not available while roaming. VZ Private IP (MPLS) connectivity required. PNTM relies on customer’s applications (VoIP, video, etc.) to appropriately mark IP sessions in order to prioritize their application over the 4G LTE Private Network using Internet Protocol Differentiated Services Code Point (IP DSCP). PNTM 4G LTE device must be certified for use on the Verizon Wireless network (e.g. Open Development/Open Access certified, validated for Private Network and Private Network Traffic Management.) Zipit Now Messaging Solution* The calling plan below reflects the monthly access fee discount. No additional discounts apply. Please note a separate agreement must be negotiated and executed between the Customer and Zipit Wireless for the services* it will provide. Monthly Access Fee $15.00 (86024) Optional Feature Access Fee N/A Domestic MB Allowance 35 MB Overage Rate Per MB $0.10 MB Home Airtime/Min. Rate N/A Domestic Long Distance1 Included NOTE: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Data usage is rounded to next full kilobyte at end of each billing cycle. Any unused portion of the monthly megabyte allowance is lost. This plan is not eligible for pooling or sharing of the megabyte allowance. *Please note installation, maintenance, warranty, customer service, billing, and pricing of Zipit equipment are provided separately, directly through Zipit Wireless. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 22 of 41 Verizon Mobile Device Management (MDM): Government Subscribers Only Verizon MDM is not eligible for the monthly access charge discount. No additional discounts apply. Verizon MDM Feature Access Fee Enterprise Firmware Over the Air (FOTA) Management $0.00 Device Diagnostics $0.99/device per month Broadband Hotspot Management $1.49/device per month OR $15.00/device per year Verizon Software Management $0.10/device per month OR Event-based pricing of $6 per device per update Notes: See attached Calling Plan and Feature Details for important information about calling plans, features and options. MDM supports select devices and operating systems and may require installation of a software agent. MDM features are billed separately; however, all supported options will appear and cannot be blocked. . Due to a number of features that require HTML 5, Verizon MDM requires Internet Explorer Version 10 and above to work efficiently. Push to Talk Plus License (PTT+): Government Subscribers Only Push to Talk License licenses are not eligible for any further discounts. Product Monthly Access Tablet $3.75 Inter-carrier (only any device) $3.75 3rd Party Web (HTML) API Client $3.75 Dispatch (License) Windows PC with PTT and mapping $22.50 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Push to Talk license only. Push to Talk Plus requires PTT+ capable device. Land Mobile Radio (LMR) for PTT+ : Government Subscribers Only Push to Talk Plus service is required. LMR licenses are not eligible for any further discounts. Product Monthly Access LMR Channel per account $0.00 Notes: Customer may have multiple channels. LMR FEATURE Only (When added to a Basic/Smartphone Device with PTT+) Basic/Smartphone Devices (FEATURE) $4.50 (85280) Notes: LMR cannot be added to any device without Domestic Push to Talk Plus. Push to Talk Plus requires PTT+ capable device. LMR License bundled with PTT+ License Tablet $8.25 Inter-carrier (any device) $8.25 3rd Party Web (HTML) API Client $8.25 LMR with Dispatch (for Windows PC with PTT+ and mapping) $27.00 Notes: Current coverage details can be found at www.verizonwireless.com. See attached Calling Plan and Feature Details for important information about calling plans, features and options. Land Mobile Radio (LMR) Interoperability works with all PTT+ capable devices. To use PTT+, Customer needs a PTT+ feature (or a software license for tablets and dispatch) and a PTT+ compatible device. An Internet Protocol (IP) link is required to connect Verizon’s PTT+ service with the customer’s LMR network through the “IP Gateway”. By purchasing the Land Mobile Radio for PTT+ Customer consents to the tracking of Land Mobile Radio for PTT+ equipment and must obtain authorized consent to tracking from all users and affected persons. No guarantee of accuracy of information transmitted, disclosed, displayed or otherwise conveyed or used. Service could be interrupted or disrupted due to atmospheric conditions, inaccurate ephemeris data and other factors associated with use of satellites and satellite data. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 23 of 41 MobileIron Enterprise Mobility Management License Fees On-Premise (Core) (Minimum 500+ MI Core Licenses Required for initial order/installation) A discount has been applied. MobileIron Licenses and Installation services are not eligible for any further discounts. On-Premise (Core) (Software Subscription License) Annual Subscription License Bundle per Device with Direct Support Annual Subscription License Bundle per User with Direct Support (3 Devices per User) License Type Description/SKU Monthly Cost Annual Cost Description/SKU Monthly Cost Annual Cost Silver MobileIron Core (on-premise) EMM Silver Bundle per Device SKU: MICore Silver Per Device $3.00 $36.00 MobileIron Core (on-premise) EMM Silver Bundle per User SKU: MICore Silver Per User $4.50 $54.00 Gold MobileIron Core (on-premise) EMM Gold Bundle per Device SKU: MICore Gold Per Device $4.50 $54.00 MobileIron Core (on-premise) EMM Gold Bundle per User SKU: MICore Gold Per User $6.75 $81.00 Platinum MobileIron Core (on-premise) EMM Platinum Bundle per Device SKU: MICore Platinum Per Device $5.63 $67.50 MobileIron Core (on-premise) EMM Platinum Bundle per User SKU: MICore Platinum Per User $8.63 $103.50 On-Premise (Core) (Software Perpetual License) Annual Subscription License Bundle per Device and Direct Support Annual Subscription License Bundle per User and Direct Support (3 Devices per User) Type Description/SKU Monthly Cost Annual Cost One-Time Cost Description/SKU Monthly Cost Annual Cost One-Time Cost Silver License MobileIron Core (on-premise) EMM Silver per Device Perpetual License SKU: MICore Silver Per Device Perpetual License - - $56.25 MobileIron Core (on-premise) EMM Silver per User Perpetual License SKU: MICore Silver Per User Perpetual License - - $82.50 Silver Support (REQUIRED) Maintenance Support for MobileIron Core (on-premise) EMM Silver per Device Perpetual License SKU: Maintenance Support MICore Silver Per Device Perpetual License $0.94 $11.25 - Maintenance Support MobileIron Core (on-premise) EMM Silver per User Perpetual License SKU: Maintenance Support MICore Silver Per User Perpetual License $1.38 $16.50 - Gold License MobileIron Core (on-premise) EMM Gold per Device Perpetual License SKU: MICore Gold Per Device Perpetual License - - $82.50 MobileIron Core (on-premise) EMM Gold per User Perpetual License SKU: MICore Gold Per User Perpetual License - - $123.75 Gold Support (REQUIRED) Maintenance Support MobileIron Core (on-premise) EMM Gold $1.38 $16.50 - Maintenance Support MobileIron Core (on-premise) EMM Gold per User Perpetual License $2.06 $24.75 - Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 24 of 41 per Device Perpetual License SKU: Maintenance Support MICore Gold Per Device Perpetual License SKU: Maintenance Support MICore Gold Per User Perpetual License Platinum License MobileIron Core (on-premise) EMM Platinum per Device Perpetual License SKU: MICore Platinum Per Device Perpetual License - - $105.00 MobileIron Core (on-premise) EMM Platinum per User Perpetual License SKU: MICore Platinum Per User Perpetual License - - $157.50 Platinum Support (REQUIRED) Maintenance Support MobileIron Core (on-premise) EMM Platinum per Device Perpetual License SKU: Maintenance Support MICore Platinum Per Device Perpetual License $1.75 $21.00 - Maintenance Support MobileIron Core (on-premise) EMM Platinum per User Perpetual License SKU: Maintenance Support MICore Platinum Per User Perpetual License $2.63 $31.50 - PROFESSIONAL SERVICES On-Premise (Core) Installation1 Support and Maintenance Included License Type Description/SKU One-time Cost2 Silver MICore Silver Installation MI-PS-DEPLOY1 $3,000.00 Gold MICore Gold Installation MI-PS-DEPLOY2 $6,000.00 Platinum MICore Platinum Installation MI-PS-DEPLOY3 $8,000.00 Note. Customer must choose one License Type; selection cannot be mixed and/or matched. 1A minimum of 500 MobileIron licenses are required for On-Premise (Core) for initial order for new MobileIron Customers. 2On-premise (Core) requires integration and setup with backend systems. Installation charges are prepackaged services providing access to a Professional Services Engineer to assist customer in installing/integrating the MobileIron platform. Pricing above applies to the installation of up to 5,000 MobileIron licenses. If Customer installation requires more than 5,000 MobileIron licenses, MobileIron Premium Implementation Services may apply which provides advisory services and an implementation engineer at a cost of $25,000.00 to manage large scale deployments; alternatively, Customer may use its own installation services. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 25 of 41 MobileIron Enterprise Mobility Management License Fees Cloud (Minimum 25+ MI Cloud Licenses Required for initial order/installation) A discount has been applied. MobileIron Licenses and Installation services are not eligible for any further discounts. Cloud License Annual Subscription License Bundle per Device with Direct Support Annual Subscription License Bundle per User with Direct Support (3 Devices per User) License Type Description/SKU Monthly Cost Annual Cost Description/SKU Monthly Cost Annual Cost Silver MobileIron Cloud EMM Silver Bundle per Device SKU: MICloud Silver Per Device $3.00 $36.00 MobileIron Cloud EMM Silver Bundle per User SKU: MICloud Silver Per User $4.50 $54.00 Gold MobileIron Cloud EMM Gold Bundle per Device SKU: MICloud Gold Per Device $4.50 $54.00 MobileIron Cloud EMM Gold Bundle per User SKU: MICloud Gold Per User $6.75 $81.00 Platinum MobileIron Cloud EMM Platinum Bundle per Device SKU: MICloud Platinum Per Device $5.63 $67.50 MobileIron Cloud EMM Platinum Bundle per User SKU: MICloud Platinum Per User $8.63 $103.50 PROFESSIONAL SERVICES Cloud Installation1 Support and Maintenance Included License Type SKU One-time Cost2 Silver MICloud Silver Installation MI-PS-DEPLOY1-MICLOUD $1,500.00 Gold MICloud Gold Installation MI-PS-DEPLOY2-MICLOUD $3,000.00 Platinum MICloud Platinum Installation MI-PS-DEPLOY3-MICLOUD $4,000.00 Note. Customer must choose one License Type; selection cannot be mixed and/or matched. 1A minimum of 25 MobileIron licenses are required for initial Cloud order for new MobileIron customers. 2MICloud requires integration and setup with backend systems. Installation charges are prepackaged services providing access to a Professional Services Engineer to assist customer in installing/integrating the MobileIron platform. Pricing above applies to the installation of up to 5,000 MobileIron licenses. If Customer installation requires more than 5,000 MobileIron licenses, MobileIron Premium Implementation Services may apply which provides advisory services and an implementation engineer at a cost of $25,000.00 to manage large scale deployments; alternatively, Customer may use its own installation services. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 26 of 41 MobileIron Enterprise Mobility Management: Government Subscribers On-Premise and Cloud Managed Service Features All features are available on both On-premise and Cloud managed installations. Included features are determined by MobileIron License Type Feature Functionality Included Features by License Silver Gold Platinum Apple DEP Supports Apple DEP (for iOS devices)    Android for Work Supports AFW (on AFW enabled devices)    Samsung KNOX Integrates with Samsung KNOX (KNOX sold separately)    Email Access Secure Active Sync (all bundles) Divide PM (Gold/Platinum bundles for additional fee)    Secure Enterprise Gateway (Sentry) In-line gateway that manages, encrypts, and secures traffic between the mobile device and back-end enterprise systems. (Requires user setup/installation)    Apps@Work Enterprise App Store Basic Container    Content Catalog Secure Doc catalog and publishing (basic content repository) 25 files/ 2MB each 50 files/ 25MB each Docs@Work Access, annotate and share documents from email, and on-premise management repositories    AppConnect Containerization of Application at Rest App wrapping AppConnect ecosystem (3rd Party applications already compatible with MobileIron container)    Web@Work Secure Browser Secure data in motion No VPN required    Tunnel iOS per App VPN native functionality    Help@Work Customizable app that enables screen sharing on device for trouble shooting for internal customer trouble shooting    Identity@Work MobileIron’s ability to proxy Kerberos allows iOS devices that are not on the corporate network to use iOS 7 SSO without needing to expose the Kerberos Key Distribution Center (KDC)    Service Connect Integrations ServiceNow integration to streamline IT workflows    Notes. Customer may purchase MobileIron, Inc. (“MobileIron”) licenses and services (“MobileIron Services”), to be billed by Verizon Wireless, at the prices listed above. Verizon Wireless is not the licensor of the MobileIron Services and makes no representations or warranties whatsoever, either express or implied, with respect to them. MobileIron Services are manufactured by MobileIron, Inc. Any license for MobileIron Services must be obtained directly from MobileIron either upon purchase or installation of the MobileIron Services. MobileIron Services are subject to MobileIron’s terms and conditions and can be viewed here: www.mobileiron.com/legal. Verizon Wireless will direct MobileIron to fulfill Customer’s MobileIron Services order. Customer support for MobileIron Services must be obtained directly from MobileIron, Inc. If Verizon Wireless in its sole discretion determines that an inquiry from a subscriber is related to MobileIron Services and is not one concerning Equipment or Wireless Service, it may transfer the service request to appropriate MobileIron representatives. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 27 of 41 Canvas Canvas is a service that helps you replace paper forms and processes with efficient mobile business apps and forms to save money and time on data collection. Canvas offers 3 plans: Startup Business and Professional. Customers can only select one of the plans at a time (e.g. cannot mix plans on the same account.) Monthly or annual subscription available. Item Name Canvas Startup Canvas Business Canvas Professional Number of Users Supported 1 - 5 Unlimited Unlimited Monthly Service Fee $15.00 $25.00 $35.00 Annual Service Fee $156.00 $264.00 $372.00 Canvas Features Features Startup Business Professional Form Submissions Unlimited Unlimited Unlimited 3rd Party Cloud Integration    App Builder    PDF Designer    Email/Chat Support    Mobile and Web Editing   Phone Support   Dispatch   Submission Status   HIPPA Compliance   Dedicated Support Representative  Dispatch Scheduling  Advanced Password Management  Webservices  Work flow  Canvas Connect  Notes: Products shown or referenced are provided by Canvas, a Verizon Partner Program Member, which is solely responsible for the representations and the functionality, pricing and service agreements. Canvas can connect to several different systems including cloud based and server based applications. Customer may purchase Canvas licenses and services (“Canvas Services”), to be billed by Verizon Wireless, at the prices listed above. Verizon Wireless is not the licensor of the Canvas Services and makes no representations or warranties whatsoever, either express or implied, with respect to them. Canvas Services are manufactured by Canvas Solutions, Inc. Any license for Canvas Services must be obtained directly from Canvas either upon purchase or installation of the Canvas Services. Canvas Services are subject to Canvas’ terms and conditions and can be viewed here: https://www.gocanvas.com/content/about-us/policy/. Verizon Wireless will direct Canvas to fulfill Customer’s Canvas Services order. Customer support for Canvas Services must be obtained directly from Canvas Solutions, Inc.. If Verizon Wireless in its sole discretion determines that an inquiry from a subscriber is related to Canvas Services and is not one concerning Equipment or Wireless Service, it may transfer the service request to appropriate Canvas representatives. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 28 of 41 IBM® MaaS360® Enterprise Mobility Management (EMM) Unified Endpoint Management (UEM) IBM MaaS360 Unified Endpoint Management License Fees A discount has been applied. IBM MaaS360 UEM Licenses and services are not eligible for any further discounts. IBM MaaS360 UEM offers a comprehensive, highly secure platform that manages and protects Devices and Things (smartphones, tablets, laptops, desktops,), People and Identity (authentication, authorization, Single Sign On, secure use access), Apps and Content combined with cognitive technology. Subscription License Bundle: per Device (One (1) license per device) Subscription License Bundle: per User (One (1) license per single user with multiple devices) License Type Description/SKU Monthly Cost Annual Cost Description/SKU Monthly Cost Annual Cost Essential EMM Essentials Suite Per Device License SKU: D1P3GLL (Monthly/Annual) $2.25 $27.00 EMM Essentials Suite Per User SKU: D1P3ILL (Monthly/Annual) $4.50 $54.00 Deluxe EMM Deluxe Suite Per Device License SKU: D1P3LLL (Monthly/Annual) $3.75 $45.00 EMM Deluxe Suite Per User License SKU: D1P3NLL (Monthly/Annual) $7.50 $90.00 Premiere EMM Premier Suite Per Device SKU: D1P3RLL (Monthly/Annual) $4.69 $56.25 EMM Premier Suite Per User License SKU: D1P3TLL (Monthly/Annual) $9.38 $112.50 Enterprise EMM Enterprise Suite Per Device SKU: D1P3WLL (Monthly/Annual) $6.75 $81.00 EMM Enterprise Suite Per User License SKU: D1P3YLL (Monthly/Annual) $13.50 $162.00 Additional UEM License Options License Type Description/SKU Monthly Cost Annual Cost Laptop Location Laptop Location SKU: D1AM8LL (Monthly/Annual) $0.38 $4.50 Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 29 of 41 IBM MaaS360 UEM Service Features Included features are determined by IBM MaaS360 UEM License Type Feature Functionality Included Features by License Essential Deluxe Premier Enterprise Device Management Manage smartphones, tablets & laptops featuring iOS, Android, Windows 10 Mobile, Windows 7, Windows 10 & macOS     App Management Deploy custom enterprise app catalogs Blacklist, whitelist & require apps     Patch and Update Management Identify & report on missing OS patches Schedule distribution and installation of Windows OS & macOS patches     Identity Management Single sign-on & touch access Conditional access to trusted devices Identity federation with apps     Advisor Improve IT operational efficiency by applying best practices & learning from industry & peer benchmarks     Container App A separate, corporate mobile workplace for iOS, Android & Windows Productivity apps for work in one place     Mobile Expense Management Monitor mobile data usage with real-time alerts Set policies to restrict or limit data & voice roaming     Secure Mobile Email Contain emails, attachments & chat to prevent data leakage Enforce authentication, copy/paste & forwarding restrictions FIPS 140-2 compliant, AES-256 bit encryption for data at res     Secure Mobile Chat Contain all chat mobile conversations and data Establish quick connections via corporate directory lookup     OS VPN Leverages the hosted MaaS360 Certificate Authority to issue authentication certs Deployed alongside your corporate VPN solution     Secure Browser A feature-rich web browser for secure access to intranet sites Define URL filters & security policies based on categories Block known malicious websites     Gateway for Browser Enable MaaS360 Secure Mobile Browser to access enterprise intranet sites, web apps & network resources Access seamlessly & securely without needing a VPN session on mobile device     Content Management Enforce authentication, copy/paste & view-only restrictions     Gateway for Documents Secure access to internal files: e.g., SharePoint & Windows File Share     App Security Enforce authentication & copy/paste restrictions     Gateway for Apps Add per app VPN to Application Security to integrate behind-the-firewall data in private apps     Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 30 of 41 Mobile Document Editor Create, edit & save content in a secure, encrypted container     Mobile Document Sync Restrict copy/paste & opening in unmanaged apps Store content securely, both in the cloud & on devices     Mobile Threat Management Detect and analyze mobile malware on compromised devices Automate remediation via near real-time compliance engine Take action on jailbroken/rooted devices over-the-air     Notes. Customer may purchase IBM MaaS360 software licenses and services (“IBM MaaS360 Services”), to be billed by Verizon Wireless, at the prices listed above. Verizon Wireless is not the licensor of the IBM MaaS360 Services and makes no representations or warranties whatsoever, either express or implied, with respect to them. IBM MaaS360 Services are manufactured by International Business Machines Corporation, Inc. Any license for IBM MaaS360 Services must be obtained directly from IBM MaaS360 either upon purchase or receipt of notification from IBM of access to IBM MaaS360 Services. IBM MaaS360 Services are subject to IBM MaaS360’s terms and conditions and can be viewed here: http://www-03.ibm.com/software/sla/sladb.nsf/sla/saas. Verizon Wireless will direct IBM MaaS360 to fulfill Customer’s IBM MaaS360 Services order. Customer support for IBM MaaS360 Services must be obtained directly from International Business Machines Corporation, Inc. If Verizon Wireless in its sole discretion determines that an inquiry from a subscriber is related to IBM MaaS360 Services and is not one concerning Equipment or Wireless Service, it may transfer the service request to appropriate IBM MaaS360 representatives. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 31 of 41 Samsung Knox Solutions KnoxTM is Samsung’s mobile device defense-grade security platform. The Knox Platform services multiple user segments through three separate offerings. Samsung Knox Premium is cloud-based device management that allows users to securely manage the business side of corporate devices. Samsung Knox Workspace, another offering, is an enterprise device container that acts as a secure and productive environment for work data and apps. Package Name Samsung Knox Premium Samsung Knox Workspace Target Audience SMB & Enterprise with basic security needs Enterprise, Government & Regulated Industries Components End-to-end secure mobile platform bundled with Samsung cloud EMM for device management  Works on both Android and iOS ecosystems  Knox container with essential policy controls   Knox Workspace container with expanded and advanced policy controls  IT Admin management of employee devices  Enterprise can black list/white list apps within the Knox Workspace container  Can manage VPN profiles in Knox Workspace container  Notes: Customer may purchase Samsung Knox for Enterprise licenses and services (“Knox Services”), to be billed by Verizon Wireless, at the prices listed above. Verizon Wireless is not the licensor of the Knox Services and makes no representations or warranties whatsoever, either express or implied, with respect to them. Knox Services are manufactured by Samsung Electronics Co., Ltd. (“Samsung”). Any license for Knox Services must be obtained directly from Samsung either upon purchase or installation of the Knox Services. Knox Services are subject to Knox Services’ terms and conditions and can be viewed here: https://www.samsungknox.com/en/eula. Verizon Wireless will direct Knox Services to fulfill Customer’s Knox Services order. Customer support for Knox Services must be obtained directly from Samsung. If Verizon Wireless in its sole discretion determines that an inquiry from a subscriber is related to Knox Services and is not one concerning Equipment or Wireless Service, it may transfer the service request to appropriate Knox Services representatives. SAMSUNG Knox FOR ENTERPRISE Samsung Knox Premium Knox Premium is a cloud-based cross-platform enterprise mobility management solution combined with an on-device secure container for Samsung devices. Subscription Monthly (Month to month) 1 – Year Term (Paid in advance) 2 – Year Term (Paid in advance) License Fee $0.75 $9.00 $18.00 SKU# Knox Premium EMM - Monthly Knox Premium EMM - 1-Year Knox Premium EMM - 2-Year Samsung Knox Workspace Knox Workspace is an on-device container that isolates business applications and data from personal ones with government-grade security. Knox Workspace also provides enhanced granular controls over device features to enterprise IT administrators. Requires an additional MDM/EMM (like Knox Premium) to manage the container. Manage the container by integrating Knox IT policies with your existing MDM solution. Only available for Samsung Devices. Subscription Monthly (Month to month) 1 – Year Term (Paid in advance) 2 – Year Term (Paid in advance) License Fee $2.70 $32.40 $64.80 SKU# Knox Workspace - Monthly Knox Workspace - 1-Year Knox Workspace - 2-Year Samsung Knox Customization Knox Customization is a comprehensive set of tools and services that allow businesses to customize and deploy end-to-end mobile solutions. Transform Samsung devices into purpose-built solutions for any industry. *Requires upfront proof of device ownership. One Time Charge $3.00/per license Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 32 of 41 Verizon Auto Share (In-Vehicle) Plan* This plan is NOT eligible for monthly access fee discounts. Monthly Access Fee per Connection (device) Shared Data Allowance Data Overage Rate Included Domestic Text Message Allowance (non-shared)** Overage Rate per Text Message $25.00 (93074) 20 MB (82297) $10.00 per GB 20 $0.20 per message Notes: Coverage is only available in the United States and includes the Verizon Wireless 4G network; and the 3G and 3G Extended networks, while available. Current data coverage details and additional plan information can be found at www.verizonwireless.com. This plan is restricted for use on the Delphi Onboard device only. Components of this plan include Verizon Auto Share Platform access and an in-vehicle hardware device. *Voice calls cannot be placed or received on this plan, except for calls to 611 or 911 (these calls may be placed anywhere in the Nationwide Rate and Coverage Area). If the voice block feature is removed, there will be a $0.25 per minute charge for voice calls. ACCOUNT SHARING- Data Sharing: Sharing is only available among lines active on this plan. At the end of each bill cycle, any unused data allowances for lines sharing on the same account will be applied to the overages of the other lines on the same account beginning with the line with the lowest overage need. Plan changes may not take effect until the billing cycle following the change request. **Domestic text message allowance does not include picture or video messages. Custom Verizon Auto Share Components for Government Subscribers Verizon Auto Share Components are NOT eligible for discounts. Verizon M2M Management Center Included Mobile App Included QR Code1 Included Verizon Auto Share Included Delphi Onboard Device (OBD) SKU - ACT233LVWQE $199.00 Verizon Auto Share Security Kit2 (self-install kit) SKU – VZN-SECKIT $199.97 1The QR code is in the Equipment Guide and can be ordered as an accessory. 2Professional Installation services not available to government customers. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 33 of 41 Intrepid Networks®: Government Subscribers Intrepid Networks provides a real-time situational awareness solution for both public and private organizations. Intrepid Networks solution suite is suited for emergency response agencies within the public sector, as well as any private sector companies that require day-to-day operational efficiencies and tracking needs. The solution provides critical end-user-level situational awareness which substantially improves operational efficiency and reduces the communication loop. Package Name Description Cost Conditions Software INT_RESP_PKG INTREPID RESPONSE PACKAGE ANNUAL SUBSCRIPTION $90.00/yr - INT_ACT_PKG INTREPID ACTIVATE PACKAGE ANNUAL SUBSCRIPTION $27.00/yr - INT_RESP_ACT_PKG INTREPID RESPONSE PACKAGE & INTREPID ACTIVATE PACKAGE ANNUAL SUBSCRIPTION $103.50/yr - INT_EXT_GPS ADDITIONAL EXTERNAL GPS ASSET ANNUAL SUBSCRIPTION $90.00/yr - INT_RESP+_PKG INTREPID RESPONSE 'PLUS' PACKAGE ANNUAL SUBSCRIPTION $180.00/yr - VZ_PTT_PLUS VERIZON PTT+/KODIAK INTEGRATION YEAR SUBSCRIPTION $12.00/yr SKU cannot be purchased separately. Customer must purchase either Response, Activate, and/or Response+ solution. Also, customer must subscribe to Verizon’s PTT+ service. ES_CHAT_INTEGRATION ES-CHAT PTT INTEGRATION YEAR SUBSCRIPTION $72.00/yr SKU cannot be purchased separately. Customer must purchase either Response, Activate, and/or Response+ solution. Services ON_PREM_SETUP ON-PREMISES SETUP FEE ONE TIME AND ONE YEAR SUPPORT $20,000 One-time fee SKU cannot be purchased separately. Customer must purchase with either Response, Activate, and/or Response+ solution. ON_PREM_SUPPORT ON-PREMISES MAINTENANCE AND ONGOING SUPPORT ANNUAL FEE $10,000/yr - TRAINING_AT_INTREPID 1 TRAINING DAY AT INTREPID FACILITY $1,000/day 1 day of training at Intrepid Networks’ facility in Orlando, FL. TRAINING_AT_CUST 1 TRAINING DAY AT CUSTOMER'S SITE $2,500/day 1 Day of training at Customer’s site (includes travel expenses) Trials INT_RESP_TRIAL INTREPID RESPONSE PACKAGE 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 month period. One per customer. Recurring trials are not permitted. INT_ACT_TRIAL INTREPID ACTIVATE PACKAGE 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 34 of 41 month period. One per customer. Recurring trials are not permitted. INT_RESP_ACT_TRIAL INTREPID RESPONSE PACKAGE & INTREPID ACTIVATE 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 month period. One per customer. Recurring trials are not permitted. INT_RESP+_TRIAL INTREPID RESPONSE+ 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 month period. One per customer. Recurring trials are not permitted. VZ_PTT_PLUS_TRIAL VERIZON PTT+/KODIAK INTEGRATION 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 month period. One Trial per customer. Recurring trials are not permitted. Trial is free, but customer must subscribe to Verizon PTT+ monthly service. Cannot utilize VZ PTT Plus trial concurrently with ESChat trial. ES_CHAT_INTGR_TRIAL ESCHAT PTT INTEGRATION 30 DAY FREE TRIAL $0.00 Free 30-Day trial for 5-10 licenses. Trial can only be utilized once per customer within a 6 month period. One Trial per customer. Recurring trials are not permitted. Cannot utilize ESChat trial concurrently with PTT Plus trial. Customer may purchase Intrepid Networks licenses and services (“Intrepid Networks Services”), to be billed by Verizon Wireless, at the prices listed above. Verizon Wireless is not the licensor of the Intrepid Networks Services and makes no representations or warranties whatsoever, either express or implied, with respect to them. Intrepid Networks Services are manufactured by Intrepid Networks®. Any license for Intrepid Networks Services must be obtained directly from Intrepid Networks either upon purchase or installation of the Intrepid Networks Services. Intrepid Networks Services are subject to Intrepid Networks’ terms and conditions and can be viewed here: https://documents.intrepid-networks.com/Intrepid+Networks+Standard+Services+Agreement+Feb2017+Click+Through+Version.pdf. Verizon Wireless will direct Intrepid Networks to fulfill Customer’s Intrepid Networks Services order. Customer support for Intrepid Networks Services must be obtained directly from Intrepid Networks®. If Verizon Wireless in its sole discretion determines that an inquiry from a subscriber is related to Intrepid Networks Services and is not one concerning Equipment or Wireless Service, it may transfer the service request to appropriate Intrepid Networks representatives. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 35 of 41 Networkfleet Service Options for NVLPT The Service Options below have been discounted. No additional discounts apply. Service Options Purchase Cost 5200-GPS Only $17.00 5500-Diagnostics + GPS $19.00 H6100 Expressfleet $13.86 AssetGuard BX Non-Powered Asset Tracking $13.00 Connect $2.95 Customizable Update Rates (“CUR”) 1 Minute $0.00 Customizable Update Rates (“CUR”) 45 Seconds $1.00 Customizable Update Rates (“CUR”) 30 Seconds $2.00 Customizable Update Rates (“CUR”) 15 Seconds $3.00 Satellite $34.95 Data Services $0.00 Notes: Only one Hardware tier and one Service tier per Customer Account. Must be on a 12 month service agreement. Applicable taxes are not included in the above pricing. Any applicable taxes will be applied to the billing invoice. Additional terms & conditions apply to Networkfleet Service that are subject to review by end user government agencies. Customizable Update Rates (CUR). Authorized registered user may change a device update rate through the Self Service Portal (SSP) to 60 seconds at no additional cost. Please note, if the device update rate is changed to a 45 (CUR45), 30 (CUR30), or 15 (CUR15) second update rate, an additional charge per device would apply per the CUR list price for the selected rate. Networkfleet Device/Hardware Options for NVLPT The Devices/Hardware Options below have been discounted. No additional discounts apply. Device/Hardware Options Purchase Cost 5200-GPS Only $85.00 5500-Diagnostics + GPS $85.00 1009N2VD-6100 Expressfleet $55.00 AssetGuard BX Non-Powered Asset Tracking $150.00 Notes: Only one Hardware tier and one Service tier per Customer Account. Must be on a 12 month service agreement. Applicable taxes are not included in the above pricing. Any applicable taxes will be applied to the billing invoice. Item Number Accessory Price PARTS030 Reinstallation Kit $3.00 PARTS031 Tamper Resistant Zip Ties (100 per pack) $50.00 PARTS032 Combination Antenna A (standard) $30.00 PARTS037 AT-1400 Replacement Battery $45.00 PARTS039 AT-1400 Bracket $20.00 PARTS040 Window-Mount GPS Antenna Module (5500/5200) $35.00 PARTS041 Sensor Input Harness (5500/5200) $10.00 PARTS042 OBD-II Adapter Kit only including Core Connector & 8 Adapters (5500/5200) $20.00 PARTS043 6-pin Heavy Duty Harness (5500/5200) $35.00 PARTS044 9-pin Heavy Duty Harness with Square Flange (5500/5200) $35.00 PARTS045 9-pin Heavy Duty Harness with “D” Mount (5500/5200) $35.00 PARTS069 OBD Harness Extension $10.00 PARTS070 16-Pin Heavy Duty Harness $35.00 PARTS046 Universal Harness (5200) $10.00 PARTS047 Light Duty Harness plus OBD-II Adapter Kit (5500/5200) $35.00 PARTS090 Alternate Power/Ground Adapter (5200/5500) $20.00 PARTS053 Garmin FMI 45 Cable with Traffic for Connect $145.95 PARTS054 Garmin FMI Modified Cable $55.00 PARTS057 Pelican Micro Case for 5200 w/ 15’ Universal Harness $74.95 A-PEM001 PEM Port Expansion Module $140.00 PARTS059 Quick Install Harness $10.00 A-SAT001 Satellite Modem $550.00 PARTSS063 Satellite Antenna $50.00 PARTSS064 Satellite Harness $50.00 KIT-SAT Satellite Kit (includes one modem, antenna & harness) $650.00 PARTS065 Asset Guard BX Replacement Batter (1) $75.00 Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 36 of 41 PARTS066 Asset Guard BX Magnet Mount Kit (set of 4) *See Note $75.00 PARTS095 ID Reader Adapter Install Kit $30.00 PARTS060 Driver ID Reader $15.00 PARTS061 Driver ID Key $3.50 PARTS087 Audible Driver ID Alert $15.00 PARTS071 Bluetooth Extension $0.00 PARTS093 Universal Harness (6100) $10.00 PARTS058 Universal Harness $10.00 PARTS097 5000 9-Pin “D” Mount Harness Type 2 $35.00 PARTS098 5000 9-Pin Square Harness Type 2 $35.00 Notes: * Asset Guard BX Magnet Mount Kit includes CalAmp 133561 hardware and lanyard & CalAmp 1M101-MNC25 magnets (set of 4). Item Number Installation Type Pricing (per unit) Notes I-INSTALL-UNIT Base Installation – Plug/Play or 3 Wire $65.00 Base Installation includes 1 Device and 1 Harness D-INSTALL-UNIT Limited Lifetime Base Installation $2.00 Monthly Service Fee I-INSTALL-FMI Add-On to Base Installation (Garmin) $35.00 I-INSTALL-SENSOR Add-On to Base Installation (Sensor) $65.00 Sensor Install is $65.00 PER SENSOR I-INSTALL-AG Add-On to Base Installation (AssetGuard BX) $65.00 I-INSTALL-PMC Add-On to Base Installation (Pelican Micro Case) $35.00 I-INSTALL-PEM Add-On to Base Installation (Port Expansion Module) $35.00 I-INSTALL-SAT Add-On to Base Installation (Satellite) $35.00 I-INSTALL-DID Add-On to Base Installation (Driver ID) $35.00 I-INSTALL –BTE Add-On to Base Installation (Bluetooth) $35.00 D-INSTALL-BTE Limited Lifetime Add-On to Base Installation (Bluetooth) $1.00 Monthly Service Fee D-INSTALL-FMI Limited Lifetime Add-On to Base Installation (Garmin) $1.00 Monthly Service Fee D-INSTALL-SENSOR Limited Lifetime Add-On to Base Installation (Sensor) $1.00 D-INSTALL-AG Limited Lifetime Add-On to Base Installation (AssetGuard BX/PW) $2.00 D-INSTALL-PMC Limited Lifetime Add-On to Base Installation (Pelican Micro Case) $1.00 Monthly Service Fee D-INSTALL-PEM Limited Lifetime Add-On to Base Installation (Port Expansion Module) $1.00 Monthly Service Fee D-INSTALL-SAT Limited Lifetime Add-On to Base Installation (Satellite) $1.00 Monthly Service Fee D-INSTALL-DID Limited Lifetime Add-On to Base Installation (Driver ID) $1.00 Monthly Service Fee I-SWAP-UNIT Device Swap $65.00 I-TRANSFER-UNIT Device Transfer $65.00 I-REMOVAL-UNIT Removal $65.00 Removal of device. I-NOSHOW No Show $75.00 Applies per trip if the installer makes the trip and the designated vehicle is not available so the unit cannot be installed. I-TROUBLESHOOT-UNIT Troubleshoot; Mileage $65.00 Per Trip TRAINING-HALF ½ Day Installation Training $150.00 TRAINING-FULL Full Day Installation Training $300.00 Verizon Wireless Plan and Feature Details Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 37 of 41 Plans and Associated Charges: Billing, shipping and end-user address must be within an area where Verizon Wireless is licensed and provides service. Charges for calls will be based on the cell sites used, which may be outside the calling plan coverage area even when the subscriber is physically within the coverage area. Time of the call is based on the telephone switching office that carries the call, which may be different from the time of day shown on subscriber’s phone. Unused monthly minutes and/or Megabytes are lost. On outgoing calls, charges start when subscriber presses SEND or the call connects to a network, and on incoming calls, when the call connects to a network (which may be before it rings). A call may end several seconds after subscriber presses END or the call disconnects. Calls made on the Verizon Wireless network are only billed if they connect (which includes calls answered by machines). Billing for airtime and related charges may sometimes be delayed. Calls to "911" and certain other emergency services are toll-free and airtime-free. Airtime may be charged when dialing toll-free numbers. Anytime Minutes: Anytime Minutes apply when making or receiving calls from a calling plan’s rate and coverage area. Coverage information is available at www.verizonwireless.com. Airtime is rounded up to the next full minute. Allowance minutes/Megabytes are not transferable except as may be available on plans with sharing. In order to gain access to coverage in newly expanding markets, subscribers must periodically dial *228 to update roaming information from voice or Smartphone devices; from the VZAccess Manager, go into “Options” and click “Activation,” while in the National Enhanced Services Rate and Coverage Area every three months. This may alter the rate and coverage area. Automatic roaming may not be available in all areas and rates may vary. Roaming charges may be delayed to a later bill. Long Distance: Unlimited domestic long distance is included when calling from the plan’s rate and coverage area, unless otherwise specified in the plan. Unlimited Messaging: Unlimited Messaging is included with select plans and is available in the National Enhanced Services rate and coverage area in the United States. Messaging applies when sending and receiving (i) text, picture and video messages to and from Verizon Wireless and Non-Verizon Wireless customers in the United States, (ii) Text, picture, and video messages sent via email, (iii) Instant messages, and (iv) Text messages with customers of wireless carriers in Canada, Mexico, Puerto Rico, and the U.S. Virgin Islands. Messaging is subject to Text, Picture, and Video Messaging Terms and conditions. Premium messages are not included. Friends & Family for Business: Calls directed to and received from an account’s listed Friends & Family numbers shall not use Monthly Anytime Voice Minutes. For Nationwide for Business plans with 900 minutes or more or 450 minute plan with the share option can add up to ten (10) Friends & Family numbers. Only calls from Nationwide Coverage Area to designated domestic landline or wireless numbers (excluding Directory Assistance, 900 numbers, or customer’s own wireless or Voicemail access numbers) may be added; all qualifying lines on an account share the same Friends & Family numbers, up to account’s eligibility limits; My Verizon, My Business Account or Verizon Enterprise Center is required to set up and manage Friends & Family numbers. Mobile to Mobile Calling: Mobile to Mobile Calling minutes apply when making calls directly to or receiving calls directly from another Verizon Wireless subscriber while in the Nationwide Rate and Coverage area. Mobile to Mobile calls must originate and terminate while both Verizon Wireless subscribers are within the Mobile to Mobile Calling area. Mobile to Mobile Calling is not available (i) with fixed wireless devices with usage substantially from a single cell site, (ii) for data usage including Push to Talk Plus calls, Picture or Video Messaging (iii) if Call Forwarding or No Answer/Busy Transfer features are activated, (iv) for calls to Verizon Wireless customers using any of the International services, (v) for calls to check Voice Mail, (vi) in those areas of Louisiana and Mississippi where the users roaming indicator flashes, (vii) in Canada and Mexico and (viii) to users whose current wireless exchange restricts the delivery of Caller ID And (viiii) for incoming calls if Caller ID is not present or Caller ID Block is initiated. Mobile to Mobile Calling minutes will be applied before Anytime Minutes. Night and Weekend Minutes: Apply to calls made in a calling plan’s rate and coverage area only during the following hours: 12:00 am Saturday through 11:59 pm Sunday and 9:01 pm to 5:59 am Monday through Friday. If both Night and Weekend and Mobile to Mobile Calling minute allowances apply to a given call, Mobile to Mobile Calling minutes will apply before Night and Weekend minutes. However, if either allowance is unlimited, the unlimited allowance will always apply first. Nationwide for Business Share Option: The Share Option is available to businesses with a minimum of five (5) Nationwide for Business lines on the same account with the share option. The Monthly Anytime Minutes of all lines on an account will be aggregated, and then allocated first to the line with the highest anytime minute usage, and then to the line with the next highest usage. Push to Talk Plus: Push to Talk Plus (PTT+) capable Equipment required. Push to Talk Plus capable Equipment can only be used with a Push to Talk Plus calling plan. Subscribers switching from a Push to Talk Plus Calling Plan to another calling plan may not be able to use certain Push to Talk Plus capable Equipment with the new plan. Push to Talk Plus calls may only be made with other Verizon Wireless Push to Talk Plus subscribers. Push to Talk Plus Subscribers may initiate or participate on a call, simultaneously, with as many as 250 total participants (total is limited to (50) if interoperating between 3G and 4G participants). Administrators can be designated to manage the Push to Talk contact lists via a single website interface with a single user name/password. . Existing Push to Talk Subscriber Equipment may require a software upgrade to use Push to Talk Plus or replacement with a Push to Talk Plus capable device. Push to Talk Plus is only available within the National Enhanced Services Rate and Coverage Area and WiFi access points. There will be a delay from the time a Push to Talk Plus call is initiated until the Push to Talk Plus call is first received by the called party. If an incoming voice call is received while on a Push to Talk Plus call the voice call may be answered and the Push to Talk Plus placed on hold. If an incoming Push to Talk Plus call is received while on a Push to Talk Plus call the PTT call icon can be selected to connect to the Push to Talk Plus call. If the incoming voice or Push to Talk Plus call is not answered a missed call alert will display. Network registration information will be sent to the Equipment each time it is powered on in the National Enhanced Services Rate and Coverage Area, each time the Subscriber travels into the National Enhanced Services Rate and Coverage Area, and every 12 hours if the Subscriber stays within the National Enhanced Services Rate and Coverage Area. While the updated network registration information is being sent to the Equipment, incoming voice calls will go directly to voice mail. Contact list cannot be modified from certain Equipment. Subscriber cannot prevent others who have the Subscriber’s MTN from entering the MTN into their Push to Talk contact list. Only one person can speak at a time during a Push to Talk Plus call. In-Call Talker Override (Talker Priority) allows a pre-determined user priority to take the floor to communicate urgent message over participant. Push to Talk Plus services cannot be used for (i) access to the Internet, intranets or other data networks, except as the device’s native applications & capabilities permit, (ii) any applications that tether Equipment to laptops, personal computers or other devices for any purpose. Please visit our website www.verizonwireless.com for additional Push to Talk Plus information. International Long Distance: You need International Eligibility to make international calls to most countries, but you can make calls to some North American destinations without it. Additional surcharges may apply when calling certain countries; see verizonwireless.com/International for details. Verizon Wireless International Long Distance Value Plan: International Eligibility required to call most countries. Value Plan feature is not available on all Plans. Rates are subject to change without notice. Standard International Long Distance rates apply in addition to airtime charges per your Plan on calls made from the Verizon Wireless network. Rates and service availability may vary when your phone’s banner displays “Extended Network.” Value Plan rates apply only on calls to Value Plan Countries made from your Plan’s Rate and Coverage Area. If a subscriber’s Plan’s Rate and Coverage Area includes calls to any Value Plan country, those calls will be billed per the Plan. Except when roaming on another carrier’s network, in which case that carrier's rates, taxes and surcharges apply. For Value Plan subscribers, calls made from the Verizon Wireless network to countries not included in the Value Plan will be billed at standard International Long Distance rates. Additional surcharges may apply when calling certain destinations, see www.verizonwireless.com/international for details. International Roaming: Some services, such as premium text messaging, directory assistance, entertainment lines and third-party services, may be available, and charges for these services will be billed (along with applicable toll charges) in addition to roaming rates. Message-waiting-indicator service is not available where Text Messaging is not available. When using International Phone, or International Data services, or if you subscribe to a Nationwide Plus Canada or Nationwide Plus Mexico Plan, and you’re roaming near country borders, calls may be carried by a cell site located in a neighboring country and billed at that country’s Verizon Wireless Plan and Feature Details Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 38 of 41 rates. Verizon Wireless will terminate your service for good cause if less than half of your voice or data usage over three consecutive billing cycles is on the Verizon Wireless National Enhanced Services Rate and Coverage Area. See verizonwireless.com/International for rates and destinations, which are subject to change without notice. International Eligibility required for GSM roaming, and for roaming in many destinations. Rates, terms and conditions apply only when roaming on participating GSM networks in published destinations. Availability of service, calling features, and Text messaging varies by country and network and may be restricted without notice. You must add International Eligibility to your account to roam in many destinations. Visit verizonwireless.com/naroaming. By using Equipment outside the United States, subscriber is solely responsible for complying with all applicable foreign laws, rules and regulations (“Foreign Laws”), including Foreign Laws regarding use of wireless phones while driving and use of wireless camera phones. Verizon Wireless is not liable for any damages that may result from subscriber’s failure to comply with Foreign Laws. Roaming in GSM countries: GSM International Phone, activated in the United States with compatible subscriber Identity Module (SIM) card required. Rates, terms and conditions apply only when roaming on participating GSM networks in published International Phone countries. Service may be available in additional countries, but airtime rates, availability of calling features, and ability to receive incoming calls (including return calls from emergency services personnel) may be restricted. See www.verizonwireless.com for coverage and airtime rates. Service in certain countries may be blocked without prior notice. Where Text messaging is available, Customer will be charged $0.50 for each message sent and $0.05 for each message received. Text messaging rates are subject to change. Text messages may be sent only to MTNs of (i) Verizon Wireless customers, and (ii) customers of foreign wireless carriers that participate in international text messaging. Check www.vtext.com for the most current list of participating foreign carriers. Data Services: Verizon Wireless charges you for all data and content sent or received using our network (including any network overhead and/or Internet Protocol overhead associated with content sent or received), as well as resolution of Internet Protocol addresses from domain names. Sending or receiving data using a virtual private network (VPN) involves additional VPN overhead for which you will be charged. Please note that certain applications or widgets periodically send and receive data in the background, without any action by the user, and you will be billed for such data use. Applications may automatically re-initiate data sessions without you pressing or clicking the SEND or connect button. Data sessions automatically terminate after 24 hours. A data session is inactive when no data is being transferred. Data sessions may seem inactive while data is actively being transferred, or may seem active when the data is actually cached and data is not being transferred. If you have a Data Only plan and use voice service, domestic voice calls will be billed at $0.25/minute. Verizon Wireless strives to provide customers with the best experience when using our network, a shared resource among tens of millions of customers. To further this objective, Verizon Wireless has implemented Network Optimization Practices designed to ensure that the overwhelming majority of data customers aren’t negatively impacted by the inordinate data consumption of a few users. The reduction can last for the remainder of the current bill cycle and the immediately following bill cycle to ensure high quality network performance for other users at locations and times of peak demand. For a further more detailed explanation of these techniques please visit www.verizonwireless.com/networkoptimization. Data transfer amounts will vary based on application. If you download an audio or video file, the file may be downloaded in sections or in its entirety; data charges will apply to the portion downloaded, regardless of whether you listen to or watch all of it. You may access and monitor your own data usage during a particular billing period, including during the Return Period, by accessing My Verizon online or by contacting Customer Service. Data Services: Permitted Uses: You can use Verizon Wireless Data Services for accessing the Internet and for such uses as: (i) Internet browsing; (ii) email; (iii) intranet access (including accessing corporate intranets, email and individual productivity applications made available by your company); (iv) uploading, downloading and streaming of audio, video and games; and (v) Voice over Internet Protocol (VoIP). Data Services: Prohibited Uses. You may not use our Data Services for illegal purposes or purposes that infringe upon others' intellectual property rights, or in a manner that interferes with other users' service, that violates trade and economic sanctions and prohibitions as promulgated by the Departments of Commerce, Treasury or any other U.S. government agency, that interferes with network's ability to fairly allocate capacity among users, or that otherwise degrades service quality for other users. Examples of prohibited usage include: (i) server devices or host computer applications that are broadcast to multiple servers or recipients such that they could enable “bots” or similar routines (as set forth in more detail (ii) below) or otherwise denigrate network capacity or functionality; (ii) “auto-responders,”“cancel-bots,” or similar automated or manual routines that generate amounts of net traffic that could disrupt net user groups or e-mail use by others; (iii) generating “spam” or unsolicited commercial or bulk e-mail (or activities that facilitate the dissemination of such e-mail); (iv) any activity that adversely affects the ability of other users or systems to use either Verizon Wireless’ services or the Internet-based resources of others, including the generation of dissemination of viruses, malware, or “denial of service” attacks; (v) accessing or attempting to access without authority, the information, accounts or devices of others, or to penetrate, or attempt to penetrate Verizon Wireless’ or another entity’s network or systems; or (vi) running software or other devices that maintain continuous active Internet connections when a computer’s connection would otherwise be idle or “any keep alive” functions, unless they adhere to Verizon Wireless” requirements for such usage, which may be changed from time to time. Verizon Wireless further reserves the right to take measures to protect our network and other users from harm, compromised capacity or degradation in performance. These measures may impact your service, and Verizon Wireless reserves the right to deny, modify or terminate service, with or without notice, to anyone Verizon Wireless believes is using Data Services in a manner that adversely impacts the Verizon Wireless network. Verizon Wireless may monitor your compliance, or other subscribers’ compliance, with these terms and conditions, but Verizon Wireless will not monitor the content of the communications except as otherwise expressly permitted or required by law. [See verizonwireless.com/privacy] Unlimited Data Plans and Features (such as NationalAccess, BroadbandAccess, Push to Talk Plus, and certain VZEmail services) may ONLY be used with wireless devices for the following purposes: (i) Internet browsing; (ii) email; and (iii) intranet access (including access to corporate intranets, email, and individual productivity applications like customer relationship management, sales force, and field service automation). The Unlimited Data Plans and Features MAY NOT be used for any other purpose. Examples of prohibited uses include, without limitation, the following: (i) continuous uploading, downloading or streaming of audio or video programming or games; (ii) server devices or host computer applications, including, but not limited to, Web camera posts or broadcasts, automatic data feeds, automated machine–to–machine connections or peer–to–peer (P2P) file sharing; or (iii) as a substitute or backup for private lines or dedicated data connections. This means, by way of example only, that checking email, surfing the Internet, downloading legally acquired songs, and/or visiting corporate intranets is permitted, but downloading movies using P2P file sharing services and/or redirecting television signals for viewing on laptops is prohibited. For individual use only and not for resale. We will protect our network from harm, which may impact legitimate data flows. We will limit throughput or amount of data transferred exceeding 25 GB in any given billing cycle on any line, in any given billing cycle, for all additional usage for the remainder of the then-current bill cycle for the line that exceeds the data usage, and reserve the right to deny or terminate service, without notice, to anyone we believe is using an Unlimited Data Plan or Feature in any manner prohibited above or whose usage adversely impacts our network or service levels. Anyone using more than 25 GB per line in a given billing cycle is presumed to be using the service in a manner prohibited above, and we reserve the right to immediately terminate the service of any such person without notice. We reserve the right to adjust data throughput limitation thresholds to as low as 5GB in with prior written notice. We also reserve the right to terminate service upon notification to the customer. Unlimited VZAccess and VZEmail: NationalAccess, BroadbandAccess, and InternationalAccess data sessions may be used for the following purposes: (i) Internet browsing, (ii) e-mail, and (iii) intranet access (including access to corporate intranets, e-mail and individual productivity applications like customer Verizon Wireless Plan and Feature Details Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 39 of 41 relationship management, sales force and field service automation). Unlimited VZAccess, VZEmail and Push to Talk Plus services cannot be used (i) for uploading, downloading or streaming of movies, music or games, (ii) with server devices or with host computer applications, other than applications required for BlackBerry or Wireless Sync service, including, but not limited to, Web camera posts or broadcasts, automatic data feeds, Voice over IP (VoIP), automated machine-to-machine connections, or peer-to-peer (P2P) file sharing, or (iii) as a substitute or backup for private lines or dedicated data connections. Additionally, Unlimited VZEmail services cannot be used for, (i) access to the Internet, intranets or other data networks, except as the Equipment’s native applications and capabilities permit, or (ii) for any applications that tether Equipment to laptops or personal computers other than for use of the Wireless Sync or BlackBerry Solutions. Unlimited BroadbandAccess and NationalAccess data sessions automatically terminate after 2 hours of inactivity, unless Subscriber has Mobile IP (MIP) capable Equipment Data Roaming: In the Canadian Broadband and Canadian Enhanced Services Rate and Coverage Areas, usage will be charged at a rate of $0.002/KB or $2.05/MB. In the Mexican Enhanced Services Rate and Coverage Area, usage will be charged at a rate of $0.005/KB or $5.12/MB. In other available countries, usage will be billed at a rate of $0.02/KB or $20.48/MB. International Eligibility is needed to roam in many destinations. Current coverage details, and list of Other Available Countries can be found at www.verizonwireless.com/International. International Data Optional Features: International PC Card required for international use. International PC Cards will not work in the United States or Canada and International Data Optional Features subscribers will need a NationalAccess or Mobile Broadband PC card for domestic use. The domestic and International PC Cards cannot be used at the same time. Prior to leaving the United States, subscribers must install International Data Optional Features VZAccess ManagerSM and run the OTA wizard. International Data Optional Features subscribers must activate and update their Preferred Roaming lists while in the National Enhanced Services Rate and Coverage Area every three months. Verizon Wireless reserves the right to terminate the service of any subscriber whose total usage is less than half on the Verizon Wireless National Enhanced Services Rate and Coverage Area over three consecutive billing cycles. . International Email SIM Cards: SIM Cards are available for use with your International PC Card, International Smartphone, or International Phone. Verizon Wireless is not responsible for any unauthorized use of subscriber’s SIM Cards and subscriber must safeguard security codes. Placing your InternationalEmail SIM in any other non BlackBerry or Smartphone device could result in additional charges or termination of service. Upon termination of service, subscriber must destroy SIM Card. M2M Data Plan Terms and Conditions A data session is inactive when no data is being transferred, and may seem inactive while data is actively being transferred to a device, or seem active when actually cached and not transferring data. Customer must maintain virus protection when accessing the service and is responsible for all data sent and received including “overhead” (data that is in addition to user-transmitted data, including control, operational and routing instructions, error-checking characters as well as retransmissions of user-data messages that are received in error) whether or not such data is actually received. Verizon Wireless will not be liable for problems receiving Service that result from Customer’s device. Megabyte (MB) Data Plans: M2M data usage is rounded to next full kilobyte at end of each billing cycle. Any unused portion of the megabyte allowance is lost. Equipment will not indicate kilobyte usage. Data Roaming: In the Canadian Broadband and Canadian Enhanced Services Rate and Coverage Areas, usage will be charged at a rate of $0.002/KB or $2.05/MB. In the Mexican Enhanced Services Rate and Coverage Area, usage will be charged at a rate of $0.005/KB or $5.12/MB. For more information on roaming in Canada and Mexico, visit verizonwireless.com/naroaming. In the Bermuda, China, Dominican Republic, Guam, India, Israel, Saipan and South Korea Enhanced Services Rate and Coverage Areas, usage will be billed at a rate of $0.02/KB or $20.48/MB. I-Dial is needed to roam in many destinations. Only the Canadian Broadband Rate and Coverage Area supports EV-DO. M2M Data Plan Share Options Share Options: Sharing is available only among Government Subscribers on applicable M2M Low Usage and High Usage calling plans. Account Share: Customer may activate up to 15 share groups per account. Sharing is available only among M2M Lines on the Mobile Broadband M2M Account Share Plans on the same billing account, in the same usage group (Low Usage and High Usage plans cannot share with each other). Unused KBs will be distributed to M2M Lines with an overage on an as needed basis to M2M Lines on the same billing account that have exceeded their MB allowance during the same monthly billing period. At the end of each bill cycle any unused KBs allowances will be applied to the overages of the other M2M Lines on the same account beginning with the line with the lowest overage need until depleted. Customers subscribing to Mobile Broadband M2M Account Share Plans will be billed on separate billing accounts and invoices from Subscribers to the Mobile Broadband M2M Profile Share Plans. Profile (Multi-Account) Share: Customer may activate one (1) share group per profile (Low Usage and High Usage plans cannot share with each other); however, customer may have multiple bill accounts on the same profile. Sharing is available only among M2M Lines on the Mobile Broadband M2M Multi-Account Share Plans on the same profile, in the same usage group. Each sharing M2M Lines unused KBs will pass to other sharing M2M Lines that have exceeded their data allowance during the same monthly bill cycle. Unused KBs will be distributed proportionally as a ratio of the KBs needed by each applicable M2M Line to the total KBs needed by all sharing M2M Lines on the same profile. Customers subscribing to Mobile Broadband M2M Profile Share Plans will be billed on separate billing accounts and invoices from Subscribers to the Mobile Broadband M2M Account Share Plans. Note: 1A profile is defined as a Customer’s overarching account of record under which Customer may have multiple billing accounts Verizon Wireless Private Network Terms and Conditions Verizon Wireless Private Network Service (“Private Network”): Private Network extends Customer’s IP network to its wireless equipment by segregating the data between such devices and Customer’s servers from the public Internet (the “Internet”). Customer’s use of Private Network is subject to the Private Network Roles and Responsibilities Customer Guidelines, which are available from your Sales representative. Customer Minimum Line Requirement: Customer must maintain a minimum of 100 Machine-to-Machine lines at all times during the term of its Agreement in order to remain eligible for Private Network. If Customer falls below the 100-line minimum, Verizon Wireless reserves the right to discontinue Private Network for non-use. Connection to Verizon Wireless Facility: Customer must establish a direct-connect circuit from its facilities to Verizon Wireless’s facilities by the use of Virtual Private Network, Verizon Private IP, or Fixed End System connections. Customer is solely responsible for making arrangements with a local access provider for installation and ongoing maintenance of such a connection, with sufficient data throughput to meet Customer’s anticipated data needs. Customer is also responsible for all charges incurred directly or through a third party associated with establishing the connection, as well as for accessing Private Network, including Internet access fees, hardware, software, license fees, and telecommunications charges. Customer Provided Equipment (“CPE”): Customer must procure routers and any other CPE that meet Verizon Wireless requirements for Private Network connectivity. Customer is responsible for ensuring any CPE meets its data capacity and throughput needs. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 40 of 41 IP Addresses: Customer is responsible for procuring private IP addresses, which must be communicated to Verizon Wireless during implementation. Private Network supports static and dynamic addressing for 1X service and/or EVDO service; 4G LTE service; and Internet addressing system Internet Protocol version 4. Direct Internet access requires static IP addressing. Dynamic Mobile Network Routing (“DMNR”): DMNR allows configuration of Private Network for dynamic routing to the subnets it serves (up to eight) to other devices on Customer’s network and as support for mobile or stationary routers. DMNR is based off Mobile IPv4-based Network Mobility protocol and requires the router to be configured to support this capability. Customer is responsible for any charges associated with the customization of its CPE to support DMNR. Verizon Wireless Private Network Traffic Management Private Network Traffic Management (PNTM): PNTM allows Customer to configure its Private Network to allow differentiated Quality of Service (QoS) by application over Verizon Wireless’s LTE network using standards-based IP packet marking. Customer can identify applications on its 4G LTE devices to get priority QoS over its Private Network. Verizon Wireless makes no guarantee of PNTM bandwidth allocations, which are subject to the limitations of wireless service availability as detailed in the Agreement. Customer is responsible for any charges associated with the customization of its CPE to support PNTM. PNTM for Public Safety: Eligible public safety accounts can take advantage of priority access to a data channel over the Wireless Service for its data traffic during times of heavy network demand. While PNTM for Public Safety enables a dedicated data channel, Verizon Wireless makes no guarantee of Wireless Service availability, which is subject to the limitations of wireless service availability as detailed in the Agreement. PNTM for Public Safety is only available to Customers approved by Verizon Wireless that qualify as Public Safety Entities classified by the following NAICS codes a) 621910 Ambulance Services; b) 922110 Courts; c) 22120 Police Protection; d) 922130 Legal Counsel and Prosecution; e) 922140 Correctional Institutions; f) 922150 Parole Offices and Probation Offices; g) Fire Protection; h) 922190 Other Justice, Public Order, and Safety Activities or i) National Security. Customer Private Network Contact: Customer must designate a Private Network representative and provide contact information, including a phone number and email address. The Private Network contact will work with the Verizon Wireless solution engineer through the Private Network implementation and testing processes detailed below. The contact shall be available during business hours and any other time period that Customer utilizes Private Network for the purpose of assisting to resolve service problems and trouble shooting. Private Network Implementation and Testing: Verizon Wireless will implement Customer’s Private Network, which requires Customer to a) provide any information (e.g., account numbers, IP address ranges, router/CPE information) necessary to compete the Private Network Connectivity Form; b) participate in a Private Network turn-up call to ensure that CPE is properly configured to support the Private Network connection; and c) participate in a Solution Validation call to confirm that Private Network is working properly from Verizon Wireless to Customer’s applications. Wireless Devices/Network Access: Customer must use Private Network-compatible end-user Equipment and at Customer’s expense must submit any devices not identified as Private Network compatible to Verizon Wireless, for network testing and Private Network certification. Private Network functionality is available on the Verizon Wireless 3G and 4G data network, subject to the limitations defined in this Addendum. While Private Network functionality may also be available on the networks of Verizon Wireless’ domestic and international roaming partners, Verizon Wireless makes no representation of Private Network availability or reliability on such networks. Permitted Use/Fraud: Customer shall use Private Network only for lawful purposes and shall not send or enable via the Private Network connection, by way of example, any SPAM, viruses, worms, trap doors, back doors or timers, nor shall Customer engage in any mail-bombing or spoofing via Private Network. Customer is responsible for the security of its network and end-user devices and is responsible for any unauthorized access to the Private Network. Verizon Wireless will treat any traffic over the Private Network as authorized by Customer. Verizon Wireless reserves the right but is not obligated to filter fraudulent usage. Maintenance/Service Changes/Termination of Private Network Service: Verizon Wireless may limit access to Private Network in order to perform maintenance to the service and will use reasonable efforts to provide Customer with prior notice of such maintenance. With reasonable advance notice, Verizon Wireless has the right to modify and reconfigure Private Network as it deems necessary to enhance Customer’s experience or to safeguard the Verizon Wireless network. In addition, VERIZON WIRELESS CAN WITHOUT NOTICE LIMIT, SUSPEND OR CANCEL CUSTOMER’S ACCESS TO OR USE OF PRIVATE NETWORK IF CUSTOMER VIOLATES THE RESTRICTIONS OF THIS ADDENDUM OR FOR GOOD CAUSE. Good cause includes (a) breach of the terms of this Addendum or the Agreement; (b) unlawful use of Private Network; (c) using Private Network in a way that adversely affects the Verizon Wireless network or Verizon Wireless’ customers; (d) breach of an obligation of Customer to comply with any applicable federal, state and local government laws, rules and regulations, industry practices, third-party guidelines, or other applicable policies and requirements; (e) the suspension or termination by any governmental body of competent jurisdiction of Customer’s service or the institution of a requirement, ruling or regulation that conflicts with this Addendum; or (f) for operational or governmental reasons. No Warranties: Verizon Wireless makes no warranties, express or implied, with respect to Private Network, which it provides to Customer on an “AS IS” basis “WITH ALL FAULTS” and “AS AVAILABLE.” The accuracy, timeliness, completeness, suitability, or availability of any aspect of Private Network cannot be guaranteed. THE IMPLIED WARRANTIES OF MERCHANTABILTY, FITNESS FOR A PARTICULAR PURPOSE, AND NON-INFRINGEMENT ARE HEREBY EXPRESSLY DISCLAIMED IN THEIR ENTIRETY. The foregoing limitations, exclusions and disclaimers shall apply to the maximum extent permitted by applicable law. Verizon Wireless makes no representation that it supports any service levels with respect to the availability, performance, capacity, uptime or any similar metrics of Private Network. Subject to the Agreement: The terms of this Addendum supplement the Agreement. The terms of the Agreement are applicable to Customer’s use of Private Network. If there are any inconsistencies between the terms of this Addendum and the Agreement, the terms of this Addendum shall control with respect to Private Network. Verizon Wireless offers this pricing utilizing the terms and conditions of the NASPO ValuePoint (NVLPT) Contract #1907, Addenda and Attachments can be found on www.naspovaluepoint.org site for your consideration and review. Your State may also have a NVLPT Participating Addendum which may be available on your State website. Alternatively, you may contact your local Verizon Government Sales representative for additional information. v.122017 (22%) Page 41 of 41 Regulatory Surcharges and Fees Verizon Wireless’ pricing does not include federal, state, local or foreign fees, assessments or other charges (collectively “fees”), which must be billed based on the jurisdiction in which the subscriber’s cellular number is set up and located. Fees vary by state and local areas and are subject to change without notice. Verizon Wireless cannot provide a comprehensive list of all charges and regulatory fees required and assessed when using a wireless device because they vary greatly from one jurisdiction to another. In addition to taxes, surcharges and fees that we are required to collect, we will also collect charges to recover or help defray costs of taxes and governmental surcharges and fees imposed on us, and costs associated with governmental regulations and mandates on our business. These charges include, among others, a Regulatory Charge and a Federal Universal Service Charge, and are described below in more detail. These charges are Verizon Wireless charges, not taxes, and are subject to change. Because these charges are not taxes, your tax exemptions, if any, will not apply to these charges. Federal Universal Service Charge Wireless carriers are assessed by the federal government to fund the delivery of universally-affordable telecommunications and information services under the Federal Universal Service Fund (FUSF) program. The Federal Universal Service Charge (FUSC) collected by Verizon is a percentage of the customer's monthly bill and is used to defray the costs of the FUSF. The FUSC is collected on most items on the bill, other than data charges for wireless broadband Internet access, equipment charges and taxes. As of January 1, 2018, the basic FUSC rate is 19.5% and changes quarterly. The FUSC rate for bundled minute plans is 5.08% if the customer does not exceed the included number of minutes. The 19.5% rate applies to long distance interstate calls that exceed the customer's included bundle of minutes. Other services, such as VOIP, are charged a lower FUSC rate. • Cellular Access for voice calling plans (only on first 79% of this item) • Verizon Wireless Toll • Roaming Charges • Activation Charges • Re-connect fees • Landline Connect Fee • TXT Messaging monthly service • TXT Messaging usage • Airtime usage for voice calls • Mobile to Mobile feature • Nights and Weekends feature • Toll free feature The quarterly percentage rate described above for the FUSC is applied in our billing system. Verizon Wireless also imposes state universal service charges. These charges vary by jurisdiction and are subject to change depending on changes in the state universal service impositions on Verizon Wireless. Regulatory Charge The Regulatory Charge is an assessment that helps defray our ongoing costs of complying with various governmental mandates and assessments. Examples include: • The cost of the license fees assessed by the FCC. • Costs assessed by the FCC to administer local number portability requirements. This charge is subject to change over time upon notice and is taxable in most jurisdictions. The Regulatory Charge is $0.02 per line for wireless Mobile Broadband Internet access and Machine to Machine devices and $0.21 per line for all other services. Regulatory fees impacting the wireless industry are constantly evolving and are subject to change without notice. For more information you can visit the FCC’s website at www.fcc.gov. City of Palo Alto (ID # 9627) Finance Committee Staff Report Report Type: Action Items Meeting Date: 10/16/2018 City of Palo Alto Page 1 Summary Title: Approval of the 2018 Electric Integrated Resource Plan (EIRP) and Related Documents Title: Utilities Advisory Commission Recommendation that the Finance Committee Recommend that the City Council Adopt a Resolution Approving the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and Related Documents From: City Manager Lead Department: Utilities Recommendation Staff and the Utilities Advisory Commission (UAC) recommend that the Finance Committee recommend that the City Council: 1. Adopt a Resolution (Attachment A) to approve the following: a. The 2018 Electric Integrated Resource Plan (EIRP) (Attachment B); b. An updated Renewable Portfolio Standard (RPS) Procurement Plan (Appendix A to Attachment B); c. An updated RPS Enforcement Program (Appendix B to Attachment B); d. The following four standardized tables (Appendix C to Attachment B): i. Capacity Resource Adequacy Table (CRAT); ii. Energy Balance Table (EBT); iii. Greenhouse Gas (GHG) Emissions Accounting Table (GEAT); iv. RPS Procurement Table (RPT); and 2. Approve the EIRP Objective and Strategies to guide future analysis and decisions (Attachment C); and 3. Approve the EIRP Work Plan outlining planned staff initiatives to implement the EIRP (Attachment D). EXECUTIVE SUMMARY Palo Alto regularly engages in long-term planning to optimally meet the community’s electrical loads with electric supplies. This planning was previously conducted under the framework of the Long-term Electric Acquisition Plan (LEAP) and in the future will be conducted under the City of Palo Alto Page 2 EIRP framework1, which the City is required to complete every five years under state law (Senate Bill (SB) 350). The current EIRP, which must be approved by Council by January 1, 2019 in order to satisfy the City’s SB 350 regulatory requirements, has a planning period of 2018 through 2030. The City of Palo Alto Utilities (CPAU) currently has sufficient supply resources to meet projected loads through 2030, with approximately 45% of its resources from hydro supplies and the remaining 55% from renewable contracts.2 The City’s 20-year contract with the Western Area Power Administration (Western) for hydroelectric resources, which supplies nearly 40% of the City’s energy needs in a normal hydro year, expires at the end of 2024. A primary focus of the EIRP, given its large supply cost implications, is the question of whether to renew the contract with Western for an additional 30-year term (and if so, at what participation level) and/or seek other renewable supplies to meet City loads. Along with the City’s final 2018 EIRP, this report includes: (1) an updated RPS Procurement Plan; (2) an updated RPS Enforcement Program; (3) a set of four standardized tables that the City is required to submit to the CEC along with the EIRP; (4) the proposed EIRP Objective and Strategies to guide future analysis and decisions; and (5) an EIRP Work Plan with a set of new initiatives, and timelines for their completion, that staff recommends undertaking in order to prepare the City’s electric supply portfolio for the upcoming shifts in the electric utility industry—including additional analysis focused on the 2025 Western contract decision and portfolio rebalancing initiatives. Although the approval of the EIRP in and of itself does not authorize or directly impact any supply portfolio-related costs, the initiatives that will be undertaken in the coming years under the EIRP Work Plan—in particular the Council decisions on renewing the Western contract and how to rebalance the supply portfolio—will greatly influence the electric supply costs in the coming decades. BACKGROUND The last time the City completed an integrated resource plan (IRP) was in 2012, when the City’s updated Long-term Electric Acquisition Plan (LEAP) was approved by Council on April 16, 2012 (Staff Report 2710, Resolution 9241). A few years later, in 2015, Senate Bill 350 (SB 350) was signed into law, and it includes a requirement that publicly-owned utilities (POUs) serving loads greater than 700,000 megawatt-hours per year, such as Palo Alto, develop and adopt an IRP and 1 Staff will hereafter discontinue using the term LEAP and in the future use the term EIRP when seeking long-term electric portfolio plan approvals from the Council. 2 The City’s first long-term renewable contract—for wind power—expires at the end of 2021 and the other wind contract and all five landfill-gas-to energy contracts expire in the late 2020’s or early 2030’s, while the solar contracts all extend beyond 2040. City of Palo Alto Page 3 submit it to the California Energy Commission (CEC) by January 2019 and every five years thereafter.3 The current EIRP planning period is from 2018 through 2030. As noted in the EIRP report (Attachment B), through 2028 the City has sufficient resources to meet its forecasted electric loads, with renewable power contracts supplying over 50% of its needs and the remainder coming from hydroelectric resources. The City’s contract for the Western hydroelectric resource expires at the end of 2024, but is available to be renewed under similar contractual terms for an additional 30-year period. A major consideration for the EIRP—and the subject of a significant amount of the efforts outlined in the work plan (Attachment D)—is whether to renew the contract with Western (and if so, at what participation level) and/or seek other carbon neutral power supplies.4 This decision will have significant long-term ramifications for the electric utility—on its overall supply costs, cost uncertainty, market price exposure, and the supply portfolio’s GHG emissions levels and RPS level. As part of the 2012 LEAP update, the City Council approved a set of electric portfolio decision- making Objectives and Strategies. At the outset of the current EIRP development process, staff developed an updated Objective and Strategies (Attachment B). The current version, which aligns with the Utilities 2018 Strategic Plan, is very similar to the ones adopted in 2012, although the new Objective and Strategies place greater emphasis on managing uncertainty related to resource availability and costs, regulatory uncertainty, and the increased penetration of DERs. Beginning in June 2017, staff has presented 12 different reports to the UAC and Council (including the present one) directly or indirectly related to the development of Palo Alto’s 2018 EIRP. These presentations and reports are summarized in Table 1 below. Table 1: Public Process Summary for Development of the 2018 EIRP Forum Date Topic Link UAC 6/7/2017 Overview of CPAU’s EIRP Development Process Report UAC 8/2/2017 Discussion of DER Plan Development Report UAC 8/2/2017 Discussion of California Wholesale Energy Market and Electric Portfolio Cost Drivers Report UAC 9/6/2017 Discussion of Hydroelectric Resources and Carbon Neutral Portfolio Alternatives Report 3 The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s renewable portfolio standard (RPS) to 50% by 2030 and required a doubling of energy efficiency savings by 2030. The primary objective of the IRP requirement in SB 350 is to ensure that the state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its overall target of reducing GHG emissions to 40% below 1990 levels by 2030. 4 Based on the current milestone schedule presented by the Western Area Power Administration (Western) related to the post-2024 contract extension process, staff’s understanding is that the City must execute the new contract, accepting the updated project allocation, by July 2020. However, according to Western there will be a “one-time contract reduction/termination provision” available to customers who execute the new contract in July 2024. https://www.wapa.gov/regions/SN/PowerMarketing/Documents/2025/2025-milestone-schedule.pdf City of Palo Alto Page 4 UAC 11/1/2017 Discussion of Proposed DER Plan Report UAC 12/6/2017 Discussion of Renewable and Carbon Neutral Portfolio Strategy Report UAC 4/12/2018 Assessment of CPAU’s Distribution System to Integrate DERs Report UAC & Council 5/2/18 & 5/21/2018 CPAU Demand Side Management Annual Report – FY 17 UAC, Council UAC 6/6/2018 Long-term Electric Portfolio Analysis Results and Options for Rebalancing Portfolio in the Next Five to Ten Years Report UAC 9/5/2018 2018 EIRP Executive Summary, Objective & Strategies, Work Plan Report UAC 10/3/2018 Recommendation to Approve the 2018 EIRP TBD Finance 10/16/2018 Recommendation to Approve the 2018 EIRP TBD Through these presentations and discussions, staff has laid out the motivations and context for the EIRP, and described the resources currently in the City’s supply portfolio as well as the upcoming planning decisions and uncertainties facing the City. Staff felt that this level of public discussion was important given that: (1) the City must make some important planning decisions in the next several years that have significant fiscal implications for the utility, and (2) the electric utility industry has undergone dramatic changes since Palo Alto prepared its last LEAP update in 2012, with a major shift underway towards greater levels of variable, distributed, low-emissions generation, along with an expanding suite of regulatory mandates that the City must satisfy. CEC IRP Guidelines & Required Elements The schedule and structure of the EIRP process has been dictated in large part by regulatory requirements imposed by SB 350,5 which states that Palo Alto’s IRP must be adopted by Council by January 1, 2019, submitted to the CEC by April 30, 2019, and updated at least every five years thereafter. At a minimum, Sections 9621 and 454.52 of the State Public Utilities Code require that the City’s IRP shall: • Ensure procurement of at least 50% renewable resources by 2030; • Meet Palo Alto’s share of the greenhouse gas emission reduction targets established by the California Air Resources Board (CARB) for the electricity sector, to enable California to achieve the economy wide greenhouse gas emissions reductions of 40% from 1990 levels by 2030; • Minimize impacts to customer bills; • Ensure system and local reliability; • Strengthen the diversity, sustainability, and resilience of the bulk transmission, distribution systems and local communities; • Enhance distribution systems and demand-side energy management; • Minimize localized air pollutants and other greenhouse gas emissions with early priority to disadvantaged communities; and 5 SB 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable Portfolio Standard (RPS) to meet 50% of the City’s load from applicable renewable supplies by 2030. The 10-Year Energy Efficiency Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements, while the City expects to achieve an RPS of 59% in 2018. City of Palo Alto Page 5 • Address the following procurement topics: o Energy efficiency and demand resources that are cost effective, reliable and feasible; o Energy storage; o Transportation electrification; o A diversified procurement portfolio of short term electricity, long term electricity, and demand response products; and o Resource adequacy capacity. The EIRP report presented as Attachment B satisfies all the above statutory requirements. And it is worth noting that Palo Alto has already exceeded the state’s 2030 goals under SB 350 of sourcing 50%6 of electricity supplies from renewable resources and reducing greenhouse gas emissions by 40%—which are the primary drivers of the IRP requirement in the first place. DISCUSSION An IRP represents a snapshot of a continuously evolving and transforming process, as the conditions and circumstances in which utilities make planning and procurement decisions are ever-changing. The IRP process utilizes a methodology and framework for assessing a utility’s shifting business and operating requirements and adapting to factors such as changing technology, regulations, and customer behavior and preferences. Assumptions, scenarios, and results are all reviewed and updated as information and events unfold, and the process is continually revisited. Proposed Work Plan As described in detail in the EIRP, Palo Alto faces a wide range of uncertainties in the course of the EIRP planning horizon. In particular, there is significant uncertainty around the costs and generation levels associated with the Western hydro resource, and around the magnitude and shape of the City’s customer load. As such, and as part of the process of revisiting the assumptions and analysis described in the EIRP, staff developed a proposed work plan describing ongoing activities and new initiatives, along with timelines for completing these initiatives, to be undertaken as a means to mitigate the uncertainties mentioned above. The seven new initiatives identified in the proposed work plan (Attachment D) and associated timelines are summarized in Table 2 below. Table 2: New Initiatives and Timeline from the EIRP Work Plan Summary of New Work Plan Initiatives Timeline 6 Note that on 9/10/18, the Governor signed SB 100 into law, which raises the 2030 RPS requirement for all utilities from 50% to 60%. If the City does not execute any new renewables contracts (or extend any existing ones), staff projects that its RPS level will reach 63% in 2021, then gradually decrease to 46% in 2030 as older contracts expire. Given that renewable energy certificates (RECs) from renewable resources can be “banked” in one year and used for compliance purposes in later years, the current set of renewables contracts is likely sufficient to ensure the City’s compliance with state RPS mandates well beyond 2030. City of Palo Alto Page 6 1. Western Contract Decision: Evaluate the merits of committing to a new 30- year contract with Western starting in 2025. • Recommendation on initial commitment to the Western contract • Recommendation on final commitment to the Western contract - Early 2020 - Early 2024 2. Portfolio Rebalancing Analysis: Evaluate the merits of rebalancing the electric supply portfolio to lower seasonal and daily market price exposure by more closely matching the City’s hourly and monthly electric loads – Initial scoping assessment report. - Dec 2019 3. COTP decision – Evaluate how to best utilize the City’s share of the California- Oregon Transmission Project (COTP), when the long-term layoff of this asset ends in 2024 – Initial assessment report in tandem with Initiative #2 report. - Dec 2019 4. Carbon accounting – Evaluate the carbon content of the electric portfolio on an hourly basis, and discuss the merits of buying carbon offsets to ensure the carbon content of the cumulative hourly portfolio is zero on an annual basis – Initial staff recommendation. - Dec 2019 5. RPS compliance strategy review – Investigate the merits of monetizing excess RECs to minimize the cost of maintaining an RPS compliant and carbon neutral electricity supply portfolio – Initial staff recommendation. - Dec 2019 6. Partner with external agencies – Explore greater synergistic opportunities with NCPA and other agencies to lower Palo Alto’s operating costs – Initial assessment report. - Dec 2019 7. Competitive assessment and load uncertainties – Undertake a competitive assessment for the electric utility within the context of the large proliferation of customer-sited DER technologies, and develop contingencies to address the potential for large changes in the City’s load level or load profile – Initial assessment report. - Dec 2020 It should be noted that many of the new initiatives listed above have the same projected completion date. This is intentional, and it is due to the fact that many of these initiatives are highly interrelated: a decision related to the City’s RPS compliance strategy, or carbon accounting methodology, or Western contract renewal, or portfolio rebalancing will impact all of the others. As such, rather than independent reports for each initiative listed, staff may produce a series of reports that address several of these areas at once. In addition to these new initiatives, staff will continue its activities in pursuit of lowering the overall cost to serve load (and addressing the tradeoffs between pursuing sustainable supply resources and lowering supply costs). These include continuing to optimize the use of the City’s Calaveras resource, and evaluating the benefits of the NCPA pool and/or the procurement of alternative scheduling services for its renewable resources. COMMISSION REVIEW On September 5, 2018, the UAC discussed a draft version of the EIRP Executive Summary, as well as the proposed EIRP Objective, Strategies, and Work Plan. Commissioners asked questions about the scope and objectives of the new initiatives staff described from the Work Plan, but City of Palo Alto Page 7 voiced support for the direction staff proposed to take. See Attachment E for excerpted draft minutes of this meeting. NEXT STEPS Staff plans to present the 2018 EIRP report (and associated documents) to the City Council in November. Under state law, final approval of the EIRP report is required by January 1, 2019. Once approved, staff will begin executing the tasks listed in the Work Plan, and will provide the UAC and Council with updates on the progress, successes, and new challenges over the implementation period of this IRP. RESOURCE IMPACT Using existing staffing resources, staff expects to devote approximately 0.75 to 1.5 FTE in the coming years to pursuing elements associated with the Work Plan, including investigating strategies to rebalance the electric portfolio to meet the challenges of the coming decades. In addition, staff has access to a wide pool of resources through NCPA to assist with the new initiatives listed in Attachment C. The 2025 Western contract decision, in particular, is a complex and highly important matter, and staff may seek external consulting and legal assistance to augment NCPA’s resources and services, as well as those of the City Attorney’s office. The cost of such external resources may amount to $100,000 to $200,000 over the next few years. The annual budget associated with electric power purchases is $61.5 million in FY 2019, of which costs related to the Western contract account for $13.5 million. The uncertainly in cost and value associated with the Western hydro resource is considerable over the 30-year term starting 2025. Though the approval of the EIRP by itself does not have direct impact on portfolio-related costs, the different initiatives that will be undertaken in the coming years—in particular the Council decision on whether and how to rebalance the supply portfolio—will greatly influence the electric supply costs in the coming decades. POLICY IMPLICATIONS The EIRP report, Objective and Strategies, and work plan are in line with the Utilities Strategic Plan mission and strategic direction. Specifically, the EIRP report itself was contemplated under Strategy 4, Action 5, of the Financial Efficiency and Resource Optimization Priority of the Utilities 2018 Strategic Plan. These EIRP documents are also in line with the Sustainability and Climate Action Plan goals of continuing to lower the carbon footprint of the community. ENVIRONMENTAL REVIEW The Finance Committee’s review and recommendation to Council on the 2018 EIRP report and related documents does not meet the definition of a project under Public Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not required. Attachments: • Attachment A: Resolution Approving the 2018 EIRP and Related Documents • Attachment B: 2018 Electric Integrated Resource Plan (EIRP) City of Palo Alto Page 8 • Attachment C: 2018 EIRP Objective & Strategies • Attachment D: 2018 EIRP Work Plan • Attachment E: Excerpted Draft Minutes of the September 5, 2018 UAC Meeting Attachment A * NOT YET APPROVED * 1 Resolution No. _________ Resolution of the Council of the City of Palo Alto Approving the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and Related Documents R E C I T A L S A. Senate Bill 350 was adopted in 2015, establishing a requirement that requires publicly owned utilities (POUs) with an average load greater than 700 GWh (in the 2013-16 period) to adopt Integrated Resource Plans (IRP) by January 1, 2019, submit them to the California Energy Commission (CEC), and update them at least once every five years thereafter. B. Based on historical data, the City of Palo Alto is one of 16 California POUs that are required to file an IRP. C. The CEC is required to review POU IRPs for consistency with Public Utilities Code 9621 and recommend corrections to deficiencies in the plans, according to the Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines (POU IRP Guidelines) most recently adopted by the CEC in August 2018. D. The POU IRP Guidelines require POUs to submit certain supporting information along with the IRP, including a set of four standardized tables and a Renewable Portfolio Standard (RPS) Procurement Plan. E. The City of Palo Alto first adopted an RPS Procurement Plan on December 12, 2011 (Resolution 9215) and last updated it on November 12, 2013 (Resolution 9381). F. The City of Palo Alto also adopted an RPS Enforcement Program on December 12, 2011 (Resolution 9214), which has not been updated since that date. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby approves the 2018 Electric Integrated Resource Plan (Attachment B). SECTION 2. The Council hereby approves the four standardized tables that accompany the 2018 EIRP (Appendix C to Attachment B). SECTION 3. The Council hereby approves the updated Renewable Portfolio Standard Procurement Plan that will be submitted to the CEC in conjunction with the 2018 EIRP (Appendix A to Attachment B). Attachment A * NOT YET APPROVED * 2 SECTION 4. The Council hereby approves the updated Renewable Portfolio Standard Enforcement Program (Appendix B to Attachment B). SECTION 5. The Council finds that the adoption of this resolution approving the EIRP and related documents is not a project subject to California Environmental Quality Act (CEQA) review because adoption of this resolution is an administrative government activity that will not result in any direct or indirect physical change to the environment as a result (CEQA Guidelines section 15378(b)(5)). Attachment A * NOT YET APPROVED * 3 INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ___________________________ ___________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ___________________________ ___________________________ Assistant City Attorney City Manager ___________________________ Utilities General Manager ___________________________ Director of Administrative Services City of Palo Alto 2018 Electric Integrated Resource Plan ATTACHMENT B Table of Contents i Table of Contents Executive Summary .................................................................................................................... 1 CEC IRP Guidelines & Required Elements................................................................................. 3 Public Process Summary ........................................................................................................... 4 Background & Achievements to Date ......................................................................................... 6 CPAU History and Mission Statement ...................................................................................... 6 Previous IRPs & Recent Accomplishments ............................................................................... 6 Changing Planning Environment .............................................................................................. 7 Increasing DER Penetration & Load Profile Uncertainty ................................................... 7 GHG Emission Reductions ................................................................................................. 9 Renewable Portfolio Standards (RPS) ............................................................................... 9 Energy Efficiency ............................................................................................................. 10 Overview of EIRP methodology .............................................................................................. 10 Forecast Methodology for Energy and Peak Demand ................................................................ 12 Description of Econometric Forecast Models ........................................................................ 14 Energy Econometric Model ............................................................................................. 14 Peak Demand Econometric Model .................................................................................. 14 Description of Distributed Energy Resources Forecasts ........................................................ 14 Energy Efficiency Forecast............................................................................................... 16 Solar Photovoltaic Forecast ............................................................................................. 17 Transportation Electrification Forecast........................................................................... 17 Energy Storage Forecast .................................................................................................. 17 Demand Response Forecast ............................................................................................ 18 Electrification of Space and Water Heating Forecast ..................................................... 18 SB 338 Requirements ...................................................................................................... 18 Existing Resource Portfolio ....................................................................................................... 20 Energy Efficiency & Local Renewable Generation .................................................................. 21 Energy Efficiency ............................................................................................................. 21 Local Renewable Generation .......................................................................................... 22 Hydroelectric Resources ......................................................................................................... 23 Western Base Resource .................................................................................................. 23 Calaveras ......................................................................................................................... 25 Renewable Energy Resources ................................................................................................. 26 Table of Contents ii Wind PPAs ....................................................................................................................... 26 Landfill Gas (LFG) PPAs .................................................................................................... 26 Solar PPAs ........................................................................................................................ 26 Market Purchases & RECs ....................................................................................................... 27 COBUG .................................................................................................................................... 27 California-Oregon Transmission Project (COTP)..................................................................... 27 Resource Adequacy Capacity.................................................................................................. 28 Future Procurement Needs and Portfolio Rebalancing .............................................................. 29 Needs Assessment: Energy, RPS, Resource Adequacy Capacity ............................................ 29 Portfolio Rebalancing Analysis ............................................................................................... 30 Portfolio Expected Net Value .......................................................................................... 33 Portfolio Fit ...................................................................................................................... 34 Portfolio Cost Uncertainty and Management ................................................................. 35 Supply Costs & Retail Rates ...................................................................................................... 36 Transmission & Distribution Systems ........................................................................................ 37 Transmission System .............................................................................................................. 37 Distribution System ................................................................................................................ 37 Low-income Assistance Programs ............................................................................................. 38 Localized Air Pollutants ............................................................................................................ 39 Electric Vehicle Programs ....................................................................................................... 39 Local Renewable Energy Programs ........................................................................................ 39 Electrification of Space and Water Heating Programs ........................................................... 39 Refrigerant Recycling Program ............................................................................................... 40 Path Forward & Next Steps ...................................................................................................... 41 Recommended Portfolio ........................................................................................................ 41 GHG Emissions ........................................................................................................................ 42 Scenario Analysis .................................................................................................................... 42 Next Steps ............................................................................................................................... 43 Key Issues to Monitor & Attempt to Influence ...................................................................... 43 Appendices ......................................................................................................................... XI—1 Key Supplemental Reports and Documents ....................................................................... XI—1 RPS Procurement Plan ........................................................................................................ XI—2 RPS Enforcement Program ............................................................................................... XI—16 Table of Contents iii Standardized IRP Tables ................................................................................................... XI—20 Capacity Resource Adequacy Table (CRAT) .............................................................. XI—20 Energy Balance Table (EBT) ....................................................................................... XI—21 GHG Emissions Accounting Table (GEAT) ................................................................. XI—22 RPS Procurement Table (RPT) ................................................................................... XI—23 List of Figures Figure 1: The Duck Curve – Net Load in California with Penetration of Intermittent Generation............. 8 Figure 2: Palo Alto Power Supply in 2012 and 2018 ................................................................................. 10 Figure 3: Annual Energy Forecast including DERs (2018-2030) ................................................................ 13 Figure 4: Impact of DERs on Hourly Summer Load Shape in 2030 ........................................................... 13 Figure 5: Projected Palo Alto Electric Supply Mix in CY 2020 by Resource Type ..................................... 20 Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements .......................... 29 Figure 7: Expected Net Value of New Resources and Western Relative to Market Value....................... 33 Figure 8: Average Hourly Load and Generation Profiles for Each Month for Western and Potential New Resources (Normalized to Average Hourly Load) ............................................................................. 34 Figure 9: Palo Alto’s Projected Resource Supply Mix in 2030 .................................................................. 41 Figure 10: CPAU Electric Supply GHG Emissions (2005-2030) .................................................................. 42 List of Tables Table 1: California Energy Market Changes Since 2012 ............................................................................. 1 Table 2: City of Palo Alto Energy-Related Changes Since 2012 .................................................................. 2 Table 3: Public Process Summary for Development of the 2018 EIRP ....................................................... 5 Table 4: Projected Number of DER Systems (2017-2030) ........................................................................ 15 Table 5: Projected Contribution to Energy Sales of DER Systems (2017-2030) ....................................... 15 Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio ..................................................................... 28 Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio ................. 32 List of Key Supplemental Reports and Documents 1. NCPA-CAISO Metered Sub-System Agreement 2. Ten-Year Electric Energy Efficiency Goals (2017) 3. Energy Storage Assessment Report (2017) 4. Proposed Distributed Energy Resources Plan (2017) 5. Distribution System Assessment Report (2018) 6. Demand Side Management Annual Report (2018) Section I: Executive Summary 1 Executive Summary The City of Palo Alto’s 2018 Electric Integrated Resource Plan (EIRP) is a comprehensive plan for developing a portfolio of power supply resources to meet the utility’s objective of providing safe, reliable, environmentally sustainable, and cost-effective electricity services while addressing the substantial risks and uncertainties inherent in the electric utility business. The EIRP also supports the City’s mission to promote and sustain a superior quality of life in Palo Alto. In partnership with our community, our goal is to deliver cost-effective services in a personal, responsive and innovative manner. The IRP meets the requirements of California Senate Bill (SB) 350 (de León, Chapter 547, Statutes of 2015), which requires publicly owned utilities (POUs) with an average annual energy load greater than 700 gigawatt-hours (GWh) to submit an IRP at least every five years to the California Energy Commission (CEC). The EIRP discusses current and anticipated California regulatory and policy changes facing Palo Alto and the electric utility industry. Additionally, the IRP presents the analyses conducted and underlying assumptions, and outlines a resource plan to reliably and affordably meet customers’ energy needs through calendar year 2030. The electric utility industry has undergone significant changes since Palo Alto prepared its last Long- term Electric Acquisition Plan (LEAP) update in 2012, with a major shift underway towards greater levels of variable, distributed, low-emissions generation, along with an expanding suite of regulatory mandates that the City must satisfy. Table 1 provides an overview of some of the key structural changes in California’s electricity market that must be addressed in the 2018 EIRP, compared to their status at the time of the 2012 LEAP update. Table 1: California Energy Market Changes Since 2012 EIRP Topic 2012 Status 2018 Status GHG Emissions Targets Statewide emissions reduced to 1990 levels by 2020 40% below 1990 levels by 2030 Cap and Trade Authorized through 2020 Authorized though 2030 Renewable Procurement 33% by 2020 and beyond 50% by 2030 and beyond Distributed Generation Modest growth High growth Energy Efficiency Utility-specific targets (all cost- effective energy efficiency) Statewide goal of doubling energy efficiency savings by 2030 Energy Storage No explicit requirement Requirement to study adoption of targets Transportation Electrification No explicit requirement Requirement to address procurement of EV infrastructure Structured Markets Hourly market Intra-hour market Resource Adequacy Local and system capacity requirements Local, system, and flexible capacity requirements Section I: Executive Summary 2 Similarly, Palo Alto itself has undergone a myriad of changes over the past six years—both in its long- term planning goals and in how it uses electricity currently. Table 2 describes some of the major changes and accomplishments in Palo Alto since 2012, from dramatic changes in the City’s power supply and emissions reduction targets, to considerable growth in local solar generation and electric vehicles (EVs). Table 2: City of Palo Alto Energy-Related Changes Since 2012 Topic 2012 Status 2018 Status Community-wide GHG Emissions (from electricity, natural gas and transportation) Goal: Reduce GHG emissions to 15% below 2005 levels by 2020. Achieved: 22% below 2005 emission levels (28% below 1990 emissions levels). Goal: Reduce GHG emissions to 80% below 1990 by 2030. Achieved: 43% below 1990 emission levels. Electric Supply Portfolio Goal: 33% RPS by 2015 Achieved: 21% RPS Goal: 50% RPS by 2030; 100% Carbon Neutral by 2015 Achieved: 58% RPS; 100% Carbon Neutral Local Solar PV Systems Goal: 0.71% of load by 2017 Achieved: 0.57% of load (502 systems) Goal: 4% of load by 2023 Achieved: 1.94% of load (1,081 systems) Energy Efficiency Goal: 0.63% avg. annual load savings; 4.8% cumulative savings (2014-2023) Achieved: 0.68% of avg. annual load; 4.2% cumulative 6-year savings (2007-2012) Goal: 0.75% avg. annual load savings; 5.7% cumulative savings (2018-2027) Achieved: 0.73% of avg. annual load; 4.4%1 cumulative 6-year savings (2013-2018) Energy Storage Goal: No explicit goal. Goal: No explicit goal or rebates as not yet cost-effective. Facilitate customer adoption in coordination with Building department. Transportation Electrification Goal: Support California State goal Achieved: approx. 200 EVs registered in Palo Alto. Goal: Target 90% EVs by 2030 Achieved: approx. 3,000 EVs registered in Palo Alto; 60 public EV chargers; Incentives for EV charger installation. Annual Energy Load 972 GWh 925 GWh Summer Peak Capacity Load 170 MW 182 MW Average Retail Rate2 11.6 cents/kWh 13.9 cents/kWh 1 Includes savings related to Codes and Standards changes, as well as estimated savings for 2018. Section I: Executive Summary 3 The EIRP planning period is from 2018 to 2030. Through 2028, the City of Palo Alto Utilities (CPAU) has sufficient renewable contracts to supply over 50% of the City’s needs. The City’s first long-term renewable contract—for wind power—expires at the end of 2021 and the other wind contract and all five landfill-gas-to energy contracts expire in the late 2020’s or early 2030’s, while the solar contracts all extend beyond 2040. The City’s contract with the Western Area Power Administration (WAPA) for hydroelectric resources, which supplies nearly 40% of the City’s energy needs in a normal hydro year, expires at the end of 2024. A major consideration for the EIRP is whether to renew the contract with WAPA (and if so, at what participation level) and/or seek other renewable supplies. CPAU expects to continue operating within the Northern California Power Agency’s (NCPA) Metered Sub-System Aggregation (MSSA) Agreement with the California Independent System Operator (CAISO). Under this agreement, NCPA balances CPAU’s loads and resources to comply with CAISO planning and operating protocols. With resources available under the NCPA MSSA Agreement, Palo Alto has access to sufficient system, local, and flexible capacity, as well as resources to provide ancillary services to reliably meet City loads. Costs are projected to increase through 2030, primarily due to system upgrade costs, increasing environmental regulations, and renewable integration costs (which are part of the tradeoff between pursuing sustainable electricity supplies and reducing overall supply costs). Costs are increasing, but retail energy sales are decreasing due to increases in energy efficiency and local solar installations, and are further expected to decline in 2020 and beyond due to building codes mandating new homes be net zero annual energy. Part of this reduction in electrical energy use is expected to be offset by higher penetration of electric vehicles and electrification of natural gas appliances. CPAU staff will provide public updates on the progress, successes, and new challenges over the implementation period of this IRP. CEC IRP Guidelines & Required Elements The schedule and structure of the EIRP process is being guided in large part by requirements imposed by SB 350,3 which states that Palo Alto’s IRP must be adopted by Council by January 1, 2019, submitted to the CEC by April 30, 2019, and updated at least once every five years thereafter. At a minimum, Sections 9621 and 454.52 of the State Public Utilities Code require that the City’s IRP will need to: • Ensure procurement of at least 50% renewable resources by 2030 (see EIRP Sections II.B, II.C.iii, V.A, X.A) • Meet Palo Alto’s share of the greenhouse gas emission reduction targets established by the California Air Resources Board (CARB) for the electricity sector, to enable California to 2 Retail rate and energy efficiency values are for Fiscal Years 2012 and 2018; the rest of the values in Table 2 are for Calendar Years 2012 and 2018. 3 SB 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable Portfolio Standard (RPS) to meet 50% of the City’s load from applicable renewable supplies by 2030. The 10-Year Energy Efficiency Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements and the City expects to achieve an RPS of 58% in 2018. Section I: Executive Summary 4 achieve the economy wide greenhouse gas emissions reductions of 40% from 1990 levels by 2030 (Sections II.B, II.C.ii, X.B) • Minimize impacts to customer bills (Section VI) • Ensure system and local reliability, including in the hour of peak net demand (Sections III.B.vii, IV.E, IV.F, VII) • Strengthen the diversity, sustainability, and resilience of the bulk transmission, distribution systems and local communities (Sections II.B, IV.A.ii, IV.E, IV.F, VII, VIII) • Enhance distribution systems and demand-side energy management (Sections IV.A.i, VII.B) • Minimize localized air pollutants and other greenhouse gas emissions with early priority to disadvantaged communities (Sections II.B, IV.A.ii, IX) • Address the following procurement topics: o Energy efficiency and demand resources that are cost effective, reliable and feasible (Sections II.B, II.C.iv, III.B.i, IV.A.i) o Energy storage (Section III.B.iv) o Transportation electrification (Section II.B, III.B.iii) o A diversified procurement portfolio of short term electricity, long term electricity, and demand response products (Section III.B.v) o Resource adequacy (Sections IV.G, V.A) The City currently has the resources and systems in place needed to achieve all of the objectives addressed by these IRP requirements. In addition, CPAU is submitting the following four Standardized Tables as part of the EIRP: • Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each year and the contribution of each energy resource (capacity) in the POU’s portfolio to meet that demand. • Energy Balance Table (EBT): Annual total energy demand and annual estimates for energy supply from various resources. • RPS Procurement Table (RPT): A detailed summary of a POU resource plan to meet the RPS requirements. • GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each resource in the POU’s portfolio to demonstrate compliance with the GHG emissions reduction targets established by the California Air Resources Board (CARB). This EIRP along with the four aforementioned Standardized Tables and the materials listed in the Supporting Information section satisfy the IRP filing guidelines listed in Chapter 2 of the CEC guidelines. Public Process Summary Palo Alto staff has provided numerous reports and presentation related to various facets of the EIRP to the Utilities Advisory Commission (UAC) over the past 15 months. The current EIRP report was reviewed by the UAC on September 5, 2018 and October 3, 2018, before being presented to the Finance Committee and City Council for approval in October and November 2018. Table 3 below lists all public presentations related to the EIRP, with links to the associated reports. Section I: Executive Summary 5 Table 3: Public Process Summary for Development of the 2018 EIRP Forum Date Topic Link UAC 6/7/2017 Overview of CPAU’s EIRP Development Process Report UAC 8/2/2017 Discussion of DER Plan Development Report UAC 8/2/2017 Discussion of California Wholesale Energy Market and Electric Portfolio Cost Drivers Report UAC 9/6/2017 Discussion of Hydroelectric Resources and Carbon Neutral Portfolio Alternatives Report UAC 11/1/2017 Discussion of Proposed DER Plan Report UAC 12/6/2017 Discussion of Renewable and Carbon Neutral Portfolio Strategy Report UAC 4/12/2018 Assessment of CPAU’s Distribution System to Integrate DERs Report UAC & Council 5/2/18 & 5/21/2018 CPAU Demand Side Management Annual Report – FY 17 UAC, Council UAC 6/6/2018 Long-term Electric Portfolio Analysis Results and Options for Rebalancing Portfolio in the Next Five to Ten Years Report UAC 9/5/2018 Discussion of 2018 EIRP Executive Summary, Objective & Strategies, and Work Plan Report UAC 10/3/2018 Recommendation to Approve CPAU’s 2018 EIRP TBD Finance 10/16/2018 Recommendation to Approve CPAU’s 2018 EIRP TBD Council Nov 2018 Approval of CPAU’s 2018 EIRP TBD An IRP represents a snapshot of a continuous process that evolves and transforms over time. The conditions and circumstances in which utilities must make decisions about how to meet customers’ future electric energy needs are ever-changing. The IRP process utilizes a methodology and framework for assessing a utility’s ever-changing business and operating requirements and adapting to factors such as changing technology, regulations, and customer behavior. Assumptions, scenarios, and results are all reviewed and updated as information and events unfold, and the process is continually revisited under formal or informal resource planning efforts. Section II: Background & Achievements to Date 6 Background & Achievements to Date CPAU History and Mission Statement The City of Palo Alto Utilities' (CPAU) history began over one hundred years ago, in 1896, when the water supply system was first installed. Two years later, the wastewater or sewer collection system came online. In 1900, the municipal electric power system began operation, followed in 1917 by a natural gas distribution system. While CPAU and the utilities industry have evolved dramatically over 118 years, the City has nonetheless maintained a consistent set of core values: Quality, Courtesy, Efficiency, Integrity, and Innovation. Palo Alto’s 2018 EIRP is a comprehensive planning document to guide long-term power planning aligned with CPAU’s Mission Statement, which is “to provide safe, reliable, environmentally sustainable and cost effective services.”4 Previous IRPs & Recent Accomplishments Palo Alto regularly engages in long-term planning efforts related to its electric supply portfolio – previously under the auspices of the Long-term Electric Acquisition Plan (LEAP) and in the future under the EIRP.5 The last time the City completed a LEAP update was on April 16, 2012 (Staff Report 2710, Resolution 9241). A few years later, in 2015, Senate Bill 350 (SB 350) was signed into law, and it includes a requirement that publicly-owned utilities (POUs) serving loads greater than 700,000 megawatt-hours per year, such as Palo Alto, develop and adopt an IRP by January 1, 2019 and submit it to the CEC by April 30, 2019 and every five years thereafter.6 As part of the 2012 LEAP update, the City Council approved a set of electric portfolio decision-making Objectives and Strategies. At the outset of the current EIRP development process, staff developed an updated Objective and Strategies. The current version, which aligns with the Utilities 2018 Strategic Plan, is very similar to the ones adopted in 2012, with the new Objective and Strategies placing greater emphasis on managing uncertainty related to resource availability and costs, regulatory uncertainty, and the increased penetration of DERs. The 2012 LEAP update included an Implementation Plan describing a set of ongoing tasks and new initiatives for the City to undertake in order to satisfy the LEAP Objectives and Strategies. In carrying out this Implementation Plan and other initiatives, Palo Alto has accomplished the following over the past six years: 4 See the City of Palo Alto Utilities 2018 Strategic Plan, which includes the Mission Statement and Strategic Direction, here: https://www.cityofpaloalto.org/civicax/filebank/documents/64505. 5 Staff will hereafter discontinue using the term LEAP and in the future use the term EIRP when seeking long-term electric portfolio plan approvals from the Council. 6 The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s renewable portfolio standard (RPS) to 50% by 2030 and required a doubling of energy efficiency savings by 2030. The primary objective of the IRP requirement in SB 350 is to ensure that the state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its overall target of reducing GHG emissions to 40% below 1990 levels by 2030. Section II: Background & Achievements to Date 7 • Developed a Carbon Neutral Electric Supply Plan and implemented it every year, beginning in 2013; • Increased the renewable energy supply from 21% of total load to 57% of total load; • Reduced GHG emissions related to electricity by 109,000 MT CO2e, helping reduce community- wide emissions by 43% compared to 1990 levels; • Developed and launched a Feed-in Tariff program (Palo Alto CLEAN) for local renewable energy projects, which currently has 1.6 MW of operating solar PV projects and an additional 1.3 MW of solar projects in development; • Executed six new utility-scale solar contracts (totaling 153 MW of capacity), of which five projects (127 MW capacity) are currently operational; • Achieved cumulative energy efficiency savings of 4.4%7 since 2012; • Coordinated with other departments on the installation of 60 public EV charger ports owned and maintained by the City; • Approved a Local Solar Plan setting a goal of producing 4% of the community’s power supply with local solar resources by 2023; • Approved an Electrification Work Plan to facilitate the electrification of natural gas loads in buildings and facilitate adoption of electric vehicles; • Adopted aggressive energy efficiency goals which are 20% greater than a business as usual approach and require new and innovative programs; • Adopted a Sustainability and Climate Action Plan with a goal of reducing community emissions to 80% below 1990 levels by 2030; • Approved a new CPAU Strategic Plan; and • Continued to balance our own loads and resources under the CAISO-NCPA Metered Subsystem Agreement. Changing Planning Environment Across the industry, integrated resource planning has undergone significant changes in recent years. Traditionally, an IRP was an opportunity for a utility to evaluate the steady growth of its customer loads over a 10+ year planning horizon, and develop a plan for meeting that load growth through staged additions of new centralized thermal generation resources. Today’s IRPs, however, have to consider how to integrate increasing volumes of variable and/or distributed generation in an environment of declining loads and increasing regulatory mandates, all while maintaining reliability and controlling costs. Accordingly, the objective of this IRP is to evaluate Palo Alto’s portfolio of resources against the changing utility landscape and California’s environmental requirements, while recommending strategies to ensure Palo Alto continues to meet the Council’s goals for affordability and sustainability. The following is a description of some of the primary changes to the utilities planning environment over the past several years. Increasing DER Penetration & Load Profile Uncertainty California’s resource mix has changed considerably as a result of its ambitious renewable mandates and the rapidly declining costs of solar and wind resources. The shift to renewables has led to lower (sometimes negative) market prices for power at certain times of the day, but has changed the daily 7 Includes savings related to Codes and Standards changes, as well as estimated savings for 2018. Section II: Background & Achievements to Date 8 load shape, which traditionally had a single peak lasting a few hours each day. The changing load shape means new resources will be needed, and existing resources will need to be used differently, while maintaining affordability for customers. Solar and wind resources, unless paired with multi-hour energy storage systems, are intermittent sources of generation, where energy output is a function of fuel availability (i.e., sunlight and wind). In order to accommodate large volumes of intermittent resources, the system must include a sufficient supply of highly responsive resources (or load) to follow this new demand profile, which is referred to as net load (i.e., gross electricity consumption less intermittent generation). Recent capacity additions for RPS compliance have largely been solar resources, which are introducing a surplus of energy supply in the daytime hours, particularly in the spring and fall when renewable resources maintain higher levels of output and customer loads are at seasonal lows. Figure 1: The Duck Curve – Net Load in California with Penetration of Intermittent Generation (Source: CAISO) Figure 1 is a visual representation of the difference in load vs net load, highlighted by the beige area. This is commonly referred to in the industry as the “duck curve.” As seen in Figure 1, solar contributes to meeting load in the middle of the day, but rapidly trails off in the evening when load is still at or near its daily peak. For reliability, this creates the added capacity challenge of being able to meet the ramp, in addition to meeting peak demand. The resource fleet must be able to ramp down in the morning to accommodate increases in solar output, then ramp back up very rapidly to meet peak demand as solar generation diminishes with the setting sun. And while utility-scale solar is a challenge for grid operators to integrate, the growing amounts of distributed solar are an even more vexing, as these resources are essentially invisible to grid operators – thus they add a significant amount of uncertainty to net load projections. Section II: Background & Achievements to Date 9 GHG Emission Reductions In 2006, California passed Assembly Bill (AB) 32, the California Global Warming Solutions Act. AB 32 is a mandate for several sectors, including the electricity sector, to reduce GHG emissions to 1990 levels by 2020. In 2016, AB 32 was augmented by Senate Bill (SB) 32, which mandated a GHG emissions reduction target of 40% below 1990 levels by 2030. California’s goal of reducing GHG emissions will be achieved through a combination of market mechanisms (Cap and Trade) and prescriptive mandates (RPS) to retire and replace high emitting resources with cleaner resources. In order to achieve the SB 32 targets, many sectors of the economy – including industry, transportation, and electricity – will need to reduce their GHG emissions. The state’s electric sector GHG emissions in 1990 were 108 MMT CO2e. Reducing this amount by 40% creates a target of 64 MMT CO2e; however, CARB’s proposed range of 30-53 MMT CO2e for the electricity sector is a 51% to 72% reduction, well in excess of the sector’s pro-rata share of the overall reduction target.8 The electricity sector is expected to surpass its pro-rata emission reduction share due primarily to the 50% RPS goal and aggressive energy efficiency requirements. SB 350 requires that POU IRPs not only describe how they will meet their 2030 50% RPS target, but also how they will contribute to the electricity sector's share of GHG emissions reductions by 2030. For benchmarking in this IRP and for portfolio planning purposes, Palo Alto used the mid-range value of 42 MMT CO2e as the 2030 target for the electricity sector (of which Palo Alto’s load-based pro rata share is 73,013 MT CO2e). These goals are for planning purposes and not compulsory; however, if changes to the regulations occur, Palo Alto will reflect those updates in its future resource planning efforts. Renewable Portfolio Standards (RPS) One of the primary mechanisms for reducing GHG emissions in the electricity sector is the state’s RPS. The state’s RPS program mandates that an increasing percentage of retail sales be served by qualifying renewable generation. An RPS mandate was first imposed on Palo Alto by SB X1-2 in 2011, and subsequently expanded by SB 350 in 2015. Currently, the major targets are 33% renewables by 2020, and 50% by 2030. In addition to the minimum renewable generation procurement requirements, the RPS program also includes portfolio balancing requirements and long-term contract requirements, as described in Palo Alto’s RPS Procurement Plan (included as Supplementary Information). Palo Alto satisfies its RPS requirements through a diverse portfolio of qualifying renewable resources – wind, solar, bioenergy (landfill gas), and small hydro. In addition, approximately half of Palo Alto's load is served by large hydro, a carbon-free resource that helps reduce GHG emissions, yet cannot be counted for RPS compliance. Figure 2 illustrates Palo Alto’s actual and projected power supply mix for 2012 and 2018. (Note that 2012 was a slightly dry year, so the hydroelectric supply was a bit lower than average. Also, about 1% of the overall hydro supply is RPS-eligible “small hydro.”) If the City 8 The two other major sectors in the economy are the industrial and transportation sectors. In the Scoping Plan, CARB estimates the industrial sector can reduce GHG emissions between 8% and 15%, while the transportation sector can reduce GHG emissions between 27% and 32%. Much of the transportation sector’s emissions reduction burden is expected to be shifted to the electricity sector via transportation electrification, which was not accounted for in CARB’s Scoping Plan. This means the electricity sector’s GHG emissions reduction burden will be even greater than it appears. Section II: Background & Achievements to Date 10 renews its contract with the Western Area Power Administration after 2024, the 2030 power supply mix is projected to be similar to the 2018 mix, but with less wind and landfill gas and more solar. Figure 2: Palo Alto Power Supply in 2012 and 2018 Energy Efficiency California has continually increased the energy efficiency of its new buildings and appliances since the Warren Alquist Act of 1974. These efficiency standards (Title 24) were updated to mandate Zero Net Energy (ZNE) residential new construction starting in 2020. ZNE homes require energy efficiency that will be achieved through implementing a high-efficiency envelope (insulation, windows, etc.), and efficient heating, ventilation, and air conditioning units. The remaining energy consumption must be offset by on-site generation, sized so that the annual building electricity consumption is equal to the building’s electricity generation. By 2030, staff anticipates that the CEC will incorporate a carbon metric as part of the Title 24 building standards. Overview of EIRP methodology Integrated resource planning is the process that utilities undertake to determine a long-term plan to ensure generation resources are adequate to meet projected future peak capacity and energy needs, while achieving other utility goals such as maintaining an adequate capacity reserve margin for system reliability. Resource plans must ensure generation reliability is maintained at or above industry- standard levels. IRPs should also forecast long-term costs and potential rate impacts to customers to ensure that the utility can monitor and track trends with sufficient time to implement solutions to ensure reliability, compliance, and affordable electric service. An effective resource plan should also Section II: Background & Achievements to Date 11 provide a reasonable degree of flexibility for the utility to deal with uncertainty in technological change and future regulations. IRPs require the use of sophisticated analytical tools capable of evaluating and comparing the costs and benefits of a comprehensive set of alternative supply and demand resources. Supply options typically include the evaluation of new conventional generation resources, renewable energy technologies, and distributed energy resources. Demand options typically include consideration of demand response programs, energy efficiency programs, and other “behind the meter” options which may reduce the overall load that the utility must be prepared to supply. IRPs utilize various economic analyses and methodologies to assess alternative scenarios (e.g., different combinations of supply and demand resources) and sensitivities to key assumptions to arrive at an economically optimal resource plan (subject to various constraints, such as regulatory mandates and local policies). The key steps in the resource planning process are outlined below. Step 1: EXAMINE PLANNING FRAMEWORK AND RISKS: Identify and assess challenges the utility faces in the current business and regulatory environment. Step 2: ASSESS NEEDS: Develop forecasts of load changes (incorporating impacts of cost- effective demand-side resources), existing plant conditions, contract terms, and operational constraints to determine resource needs over the planning period. Step 3: CONSIDER RESOURCE OPTIONS: Evaluate available generation resources, including centralized and distributed renewables and long-term market power purchases to identify the role each will play in meeting customer needs and regulatory and policy goals. Step 4: DEVELOP RESOURCE PORTFOLIOS: Develop resource portfolios, and evaluate them quantitatively and qualitatively to determine a preferred portfolio. Evaluation relies upon GHG emission requirements, needs assessment, and planning data specified in previous steps. Step 5: PERFORM SCENARIO AND RISK ANALYSIS: Perform detailed evaluations of preferred resource portfolios through scenario and risk analysis, to assess performance under a range of potential market and regulatory conditions. Step 6: IDENTIFY PLAN: Identify a “Preferred Plan” based on the resource portfolio expected to reliably serve demand at a reasonable long-term cost, while achieving regulatory compliance, accounting for inherent risks, and allowing for flexibility to respond to future policy changes. Section III: Forecast Methodology for Energy and Peak Demand 12 Forecast Methodology for Energy and Peak Demand Palo Alto’s forecasted energy and demand were generated by creating an econometric model for monthly energy and peak demand and then combining them with separate forecasts for new distributed energy resources (DERs) expected to be deployed. This approach was used since the econometric models do not accurately capture new expected growth in these DERs. Separate models were used to forecast DERs of highest impact. After energy and peak demand profiles for these DERs were generated, these exogenous forecasts were then applied to the energy forecast as out-of-model adjustments. Equation 1: Methodology Energy and Peak Demand Forecast Total Forecast Energy OR Peak Demand =Econometric Forecast Energy OR Peak Demand +New DER Forecasts Energy OR Peak Demand More details on the DER forecasts and load shape profiles that were generated are available in the Proposed Distributed Energy Resources Plan, which was presented to the UAC in November 2017. The DERs modeled for the purpose of this analysis were: - Energy Efficiency (EE) - Solar Photovolatics (PV) - Electric Vehicles (EV) - Demand Response (DR) - Energy Storage (ES) - Heat-pump Water Heaters (HPWH) - Heat-pump Space Heaters (HPSH) The base case annual energy forecast is shown in Figure 3. The projected change in hourly load shape on a peak day in 2030 is shown in Figure 4. Section III: Forecast Methodology for Energy and Peak Demand 13 Figure 3: Annual Energy Forecast including DERs (2018-2030) Figure 4: Impact of DERs on Hourly Summer Load Shape in 2030 Section III: Forecast Methodology for Energy and Peak Demand 14 Description of Econometric Forecast Models The econometric model inputs (i.e. independent variables) have been selected based on the availability of data, economic theory, and tests to validate the forecasts with actual energy (or demand) data. The coefficients of the models were obtained via statistical estimation on historical (in-sample) data where the Yule-Walker Generalized Least Squares method was employed to take into account the autocorrelation structure of the residuals so as to obtain valid standard error estimates. The coefficients were then combined with forecasts of each driver (independent variable) to produce the forecasted energy (or peak demand). Forecasts of the economic driver variable were provided by the Bureau of Economic Analysis and the forecasted values provided by the UCLA Anderson Forecast group. Weather variables were obtained from NOAA, and the forecasted weather conditions were set to reflect normal weather based on average temperatures across the training data set. Energy Econometric Model The Energy forecast is an econometric model that maps a set of calendar variables, weather variables, and an economic driver variable onto Palo Alto’s monthly energy consumption measured at its California Independent System Operator (CAISO) meter at the Palo Alto City Gate. The monthly calendar variables are used in the model to capture underlying changes in Palo Alto customers’ electric consumption caused by changing daylight hours and seasonal electricity usage. Monthly Heating Degree Days and Cooling Degree Days are used to explain the variation in energy due to the weather. Investment in non-residential equipment and software as reported by the Bureau of Economic Analysis was used as the economic driver. This variable represents business activity in the computer software and equipment sector of the economy, which directly affects Palo Alto’s utility customers’ energy consumption. Peak Demand Econometric Model The Peak Demand forecast is also an econometric model that maps a set of calendar variables, weather variables, and the energy forecast onto Palo Alto’s monthly peak demand measured at its CAISO meter. Similar to the Energy Forecast, monthly dummy variables are used in the model to capture underlying changes in Palo Alto customers’ electric consumption throughout the year. Daily heating and cooling degree days corresponding to the peak day of the month is used as the weather driver. Monthly historical energy usage is added as the final variable explaining peak demand. Description of Distributed Energy Resources Forecasts Distributed Energy Resource forecasts for a number of technologies were developed and presented to the Palo Alto UAC in the proposed Distributed Energy Resources Plan in November 2017. The distributed energy resources considered for the purposes of these analyses were: - Energy Efficiency (EE) - Solar Photovolatics (PV) - Electric Vehicles (EV) - Demand Response (DR) - Energy Storage (ES) - Heat-pump Water Heaters (HPWH) - Heat-pump Space Heaters (HPSH) Section III: Forecast Methodology for Energy and Peak Demand 15 DER penetration forecasts and load shape models were developed to address three main areas: 1. DER Adoption Projections: Adoption forecasts for each DER technology. 2. DER Load Impact Projections: Energy used or delivered to the system on an hourly and seasonal basis to determine the impact of DERs on electric sales and load shape. 3. DER Financial Impact Projections: Financial impact to the utility of DER adoption based on the adoption and load impact projections. This analysis considered only the impact to wholesale electric supply costs, and did not include the impact of changes to current rate structures. The detailed assumptions and limitations of each of these projections are discussed in their following respective sections. The forecasts of the number of distributed energy resources in Palo Alto are shown in Table 4. The impact that these DER systems will have on CPAU’s net electricity sales is shown in Table 5, and previously in Figure 4. Table 4: Projected Number of DER Systems (2017-2030) Projected Number of Systems DER Technology 2017 (current) 2020 2030 PV 1,000 1,300 2,500 EV9 2,500 5,900 18,700 EE 40,880 45,000 60,000 DR 8 25 75 ES 11 85 580 HPWH 10 200 2,700 Table 5: Projected Contribution to Energy Sales of DER Systems (2017-2030) Contribution to Energy Sales 2017 (current) 2020 2030 DER Technology MWh % MWh % MWh % PV -15,000 -1.6% -18,800 -2.0% -45,200 -4.9% EV 7,100 0.8% 14,300 1.6% 54,800 6.0% EE -55,300 -6.0% -78,800 -8.6% -139,200 -15.2% DR 7 - 23 - 200 0.02% ES10 - - - - - - HPWH 9 - 190 0.02% 2,500 0.3% HPSH - - 90 0.01% 2,800 0.3% 9 This is the total number of residential EVs currently registered in Palo Alto. There are also EVs which commute into Palo Alto, some of which charge while in Palo Alto and add to CPAU electricity sales. In addition to the residential EVs shown here, there are estimated to be approximately 3,100, 5,900 and 20,000 commuter EVs in 2017, 2020 and 2030 respectively. 10 Batteries and other ES devices may result in either net increased energy retail sales (due to battery losses where commercial customers use batteries to avoid CPAU demand charges) or net decreased energy retail sales (due to increased onsite consumption of behind the meter solar). For the purpose of these analyses these two effects are assumed to be roughly the same magnitude and therefore ES systems are not currently considered to have any net effect on energy sales. Section III: Forecast Methodology for Energy and Peak Demand 16 Contribution to Energy Sales 2017 (current) 2020 2030 DER Technology MWh % MWh % MWh % Combined DER Impact: from 2007 -63,200 -6.9% -83,000 -9.1% -124,000 -13.6% Combined DER Impact: from 2017 - - -19,700 -2.2% -60,900 -6.6% CPAU Overall System Load Growth from 201711 - - -3,200 -0.3% -6,900 -0.8% Energy Efficiency Forecast a. Committed Energy Efficiency AB 2021 (2006) required POUs to identify all potentially achievable cost-effective electric efficiency savings and to establish annual targets for energy efficiency savings over ten years, with the first set of EE targets to be reported to the CEC by June 1, 2007, and updated every three years thereafter. AB 2227 (2012) amended this target-setting schedule to every four years. Palo Alto adopted its first Ten- Year Energy Efficiency Portfolio Plan in April 2007, which included annual electric and gas efficiency targets between 2008 and 2017, with a ten-year cumulative savings goal of 3.5% of forecasted energy use. In accordance with California law, the electric efficiency targets were updated in 2010, with the ten-year cumulative savings goal doubling to 7.2% between 2011 and 2020. Since then, increasingly stringent statewide building code and appliance standards have resulted in substantial energy savings. However, these “codes and standards” energy savings cannot be counted toward meeting the utility’s EE goals. The ten-year electric efficiency targets were updated again in 2012, with the ten-year cumulative electric efficiency savings being revised downwards to 4.8% between 2014 and 2023. For fiscal year (FY) 2017, CPAU achieved electric savings of 0.7% of load through its customer efficiency programs as shown in the most recent Demand Side Management Report. Cumulative electric efficiency savings since 2006 are about 6% of the FY 2017 electric usage. Adoption rates for EE are based on the 10-year Energy Efficiency Goals for 2018-2027 which were updated in 2017. The ten-year cumulative electric efficiency savings target was updated to 5.7% between 2018 and 2027. These adopted goals are ambitious goals which include new programs in order to achieve a 20% increase over the last goals adopted. For the years 2028 through 2030 the assumed savings are the average of the savings in 2026 and 2027, which is the methodology suggested by the CEC for estimating savings beyond the ten-year energy efficiency goals.12 More details on the EE methodology for market potential can be found in Staff Report 7718 from March 6, 2017. 11 Going forward from 2017 the total CPAU load is forecasted to grow at roughly 0.4% per year if no more DERs were added to the system. With the addition of new DERs, the total CPAU load is projected to decrease by roughly 0.8% from 2017 electricity sales by the year 2030. 12 The extension of savings through 2030 is based on the methodology put forth in the CEC presentation by Mike Jaske from September 7, 2017, which can be found here: CEC presentation on Energy Efficiency Savings from Utility Programs. Section III: Forecast Methodology for Energy and Peak Demand 17 Although CPAU established its EE goals based on net savings, the energy efficiency savings shown in the tables and graphs here include EE savings due to free-ridership as well as savings from statewide codes and standards. b. Additional Achievable Energy Efficiency There is no additional achievable energy efficiency assumed in this EIRP forecast because the additional achievable energy efficiency is already included in the ambitious adopted energy efficiency goals for 2018 to 2027. These ambitious energy efficiency goals are 20% higher than a business-as- usual case and will require new innovative programs. Solar Photovoltaic Forecast Solar PV projections are based on technical and economic potential; they indicate that adoption will grow steadily, with the growth rate itself plateauing as is typically seen in a maturing market. These projections include behind-the-meter installations in residential and commercial sectors, but do not include a potential Community Solar installation that has recently been discussed by the Palo Alto UAC. In April 2014, the Palo Alto City Council approved the Local Solar Plan, which sets a community-wide goal of meeting 4% of the City’s energy needs through local solar by 2023 and identifies a number of strategies to help achieve that goal. These strategies include the development of several solar programs to encourage installation of roof-top solar such as existing incentives like the feed-in tariff program and the PV Partners solar rebate program. As of the end of 2017 all solar installations within the City generate 1.94% of the City’s electricity from about 10 MW of installed local solar capacity. Transportation Electrification Forecast To date, Palo Alto has observed residential EV adoption rates approximately three times greater than the California statewide average, and this residential adoption rate relative to statewide average projections is assumed to continue to 2030. To estimate the EV adoption rates of commuters into Palo Alto, the observed adoption rate from 2017 census data for the entire Bay Area was extended to 2030. In addition to the number of residential EVs shown in Table 4 above, there are projected to be approximately 3,100, 5,900, and 20,000 commuter EVs in 2017, 2020 and 2030, respectively. Energy Storage Forecast This forecast is based on statewide projections for batteries and CPAU electricity rate structures. CPAU, in coordination with the Palo Alto Development Services Department, is facilitating the adoption of energy storage systems by customers by streamlining the process for permitting and interconnecting such systems. Detailed analysis in 2017 showed that batteries are currently not cost effective within CPAU’s service territory or at our remote renewable generation sites and therefore Palo Alto currently does not provide any rebates for energy storage systems and is not currently planning to install storage at any of our renewable resources. In August 2017, the Palo Alto City Council adopted a resolution determining not to set a target for CPAU to procure energy storage systems at the wholesale level (or Section III: Forecast Methodology for Energy and Peak Demand 18 to establish a rebate program for behind-the-meter installations) due to a current lack of cost-effective applications for Palo Alto. The City plans to revisit the analysis by 2020.13 Demand Response Forecast CPAU has been running a voluntary summer demand response program for large commercial and industrial customers since 2013, with an average of 4-5 DR events per year resulting in 0.5-1 MW of peak load reduction. For the 2018 demand response program there are a total of 7 commercial customers enrolled, with 525 kW of projected peak load reduction. The EIRP Energy and Peak Demand forecasts are based on modest growth projections for the current voluntary large commercial demand response program. Somewhat more robust growth is expected after the implementation of Palo Alto’s Advanced Metering Infrastructure (AMI) program in 2023. Electrification of Space and Water Heating Forecast The Energy and Peak Demand forecasts use historical solar PV penetration rates as a proxy for adoption rates of heat-pump water heaters and space heaters. Based on this analysis, staff projects a natural gas load reduction of up to 1% from HPWH adoption, and an additional 1% load reduction from HPSH adoption, by 2030. SB 338 Requirements On September 30, 2017, SB 338 was signed into law by Governor Brown, including additional provisions for the POU IRPs, which were effective January 1, 2018. This included revisions to Public Utilities Code section 9621(c), requiring the POU’s governing board to “consider the role of existing renewable generation, grid operational efficiencies, energy storage, and distributed energy resources, including energy efficiency, in helping to ensure each utility meets energy needs and reliability needs in hours to encompass the hour of peak demand of electricity, excluding demand met by variable renewable generation directly connected to a California balancing authority, as defined in Section 399.12, while reducing the need for new electricity generation resources and new transmission resources in achieving the state’s energy goals at the least cost to ratepayers.” The development of this IRP began well in advance of the effective date of these provisions. However, as part of the comprehensive process undertaken to develop this EIRP, the City reviewed and considered resource options that included all of the technologically feasible and cost-effective options available to it, including what options would be best utilized to meet energy needs and reliability requirements during hours of peak demand for the utility. This includes a review of the best available options considering both new and existing preferred resources, as would necessarily be assessed in order to ensure that Palo Alto provides its customers with the cleanest and most cost-effective generation resources, while also ensuring that the City meets all of the statutory requirements of not only Section 9621, but other procurement and resources mandates, as well. As previously mentioned, in November 2017 staff presented to the Palo Alto UAC an assessment of the future impact of distributed energy resources (Distributed Energy Resources Plan). This assessment 13 The analysis that led to the City Council’s determination not to adopt a wholesale energy storage target can be found in this report to the Palo Alto UAC: https://www.cityofpaloalto.org/civicax/filebank/documents/57435. Section III: Forecast Methodology for Energy and Peak Demand 19 included guidelines for facilitating customer adoption as well forecasts of their potential to mitigate peak demand for CPAU. The aggressive forecasts and programs for solar PV, energy efficiency, and demand response have great potential to mitigate CPAU’s peak demand. Section IV: Existing Resource Portfolio 20 Existing Resource Portfolio The City’s current electric supply portfolio comprises the following major types of resources: • Energy efficiency and distributed generation; • Federal hydro (Western contract); • Owned hydro (Calaveras); • Long-term, in-state, RPS-eligible power purchase agreements (PPAs), which include solar, wind, and landfill-gas resources; and • Market power purchases, matched with RECs, for monthly/hourly portfolio balancing. For calendar year 2020, the projected contribution of each of these five resource types to the City’s overall electric supply portfolio is represented in Figure 5 below. Figure 5: Projected Palo Alto Electric Supply Mix in CY 2020 by Resource Type * Estimated Average Annual Unit Cost of 6 ¢/kWh * Section IV: Existing Resource Portfolio 21 Energy Efficiency & Local Renewable Generation Energy Efficiency Palo Alto has long recognized cost-effective energy efficiency (EE) as the highest priority energy resource, given that EE typically displaces relatively expensive electricity generation and lowers energy bills for customers. Palo Alto places such emphasis on energy efficiency and demand side management programs that each year we prepare a detailed Demand Side Management Annual Report describing and reporting on efficiency savings from electricity, gas, and water. Highlights of Energy Efficiency Programs from 2017 • Multifamily Residence Plus+ Program - This program, which focuses on a hard-to-reach customer segment, was expanded in FY 2016 to include LED lighting measures, as the cost and quality of LED lighting had improved. In September 2016, the contract with the vendor was amended to add $500,000 to accommodate demand for the upgrades. As a result, the program saw an increase in savings of over 950%. • The Home Efficiency Genie Program - The Genie was launched in the summer of 2015 as a home efficiency assessment program. The licensed energy auditors still do house calls, but the program has expanded its focus to include more phone-based customer service on energy and water-related topics. The Genie now provides information not only about efficiency but also about the City’s sustainability programs, such as heat pump water heaters (HPWHs) and the solar group-buy program (SunShares). Staff also changed the program guidelines to allow the Genie to discuss and advise residents on available rebates. • Heat-Pump Water Heater Pilot Program - The goal of this program is reduction of greenhouse gas (GHG) emissions through switching from natural gas appliances to high-efficiency electric appliances. Installation of heat pump water heaters (HPWHs) has been identified as a good starting candidate for a pilot program. The pilot program—launched in the spring of 2016—was designed to facilitate the installation of HPWHs in single-family homes. In April 2017, the City hosted its first HPWH workshop to educate the community, including contractors, on the technology and installation of HPWHs. • Green Building Ordinance – The Green Building Ordinance (GBO) is Palo Alto’s local building reach code that is more stringent than the state Title 24 standard. This ordinance applies to both residential and commercial buildings. CPAU previously assisted in the development of this code, but FY 2017 is the first year for which savings associated with the GBO have been reported in this report. • Building Operators Certification (BOC) Course - CPAU hosted a Building Operators Certification Course taught by Northwest Energy Efficiency Commission (NEEC) from Seattle. BOC is an eight- class certification course covering all aspects of building management and efficiency. Some Section IV: Existing Resource Portfolio 22 topics covered were: HVAC, electrical systems, comfort control and lighting. Upon passing an end-of-class exam, graduates could become Certified Building Operators (CBOs). • Residential Energy Assistance Program (REAP) - This program provides qualifying low-income residents with free energy efficiency measures and access to the Rate Assistance Program (RAP) rate discount. For qualifying customers, a Home Assessment, an application to the RAP, and an on-site customer evaluation for weatherization and energy efficiency measure installation, including insulation and lighting, is provided. Customers may have refrigerators and/or furnaces replaced if the need is found. Local Renewable Generation Local renewable energy programs are critical to lowering emissions of local air pollutants and CPAU has enacted a number of initiatives and programs to facilitate customer adoption. In addition, in 2014 the Palo Alto City Council adopted the Local Solar Plan with the goal of having local solar photovoltaic facilities provide 4% of the City’s total energy needs by 2023. The following is a description of Palo Alto’s current customer-side renewable generation programs: • Solar PV Group-buy - Every year since 2015 Palo Alto has been an active partner in promoting the Bay Area SunShares PV Group-buy program which pre-screens solar installers and negotiates lower rates for customers. In both 2015 and 2017 Palo Alto was the top “Outreach Partner,” both in terms of the number of solar contracts signed and the kilowatts of rooftop solar capacity that will be installed through the program. From 2015 to 2017 Palo Alto residents have signed 88 solar contracts through the SunShares PV Group-buy program for a total of 421 kW of installed rooftop solar capacity. • PV Partners - The PV Partners Program encourages photovoltaic or solar electric (PV) installations on Palo Alto homes and businesses by providing a rebate based on the capacity, measured in watts, of newly installed PV systems. The PV Partners Program continues to be one of the most successful in the State. Rebate funds were fully reserved in April 2016. The effect of the PV Partners program can be seen in the cumulative total of PV installations. As of June 30, 2017, there were 1,003 PV installations with the total capacity of 8.617 MW (5.04% of Palo Alto’s system peak load). • Net-Energy Metering Successor Program - Prior to January 1, 2018 residential and commercial customers in Palo Alto who installed approved PV systems were able to sign up for the CPAU Net Energy Metering (NEM) program. CPAU reached the NEM cap of 10.8 MW in January 2018 and CPAU is now offering a NEM Successor Program instead. The NEM Successor process is integrated with the permitting process, and customers receive a credit for electricity exported to the grid based on CPAU’s avoided costs. • Palo Alto CLEAN (Clean Local Energy Accessible Now) - This feed-in tariff program purchases electricity generated by renewable energy resources located in Palo Alto’s service territory and interconnected on the utility-side of the electric meter. The electricity is purchased by Palo Alto for the electric renewable portfolio standard. The program was launched in 2012 and has been modified over the past few years. On February 3, 2014 the Palo Alto City Council approved a total program capacity of 3 MW at a price of 16.5 cents per kilowatt hour (kWh) fixed for 20 Section IV: Existing Resource Portfolio 23 years. On May 8, 2017 the Palo Alto City Council approved minor changes to Palo Alto CLEAN. The program no longer has a total participation cap for either solar or non-solar eligible renewable energy resources. CPAU is currently offering to purchase the output of eligible renewable electric generation systems located in Palo Alto at the following prices: o For solar energy resources: 16.5 cents per kilowatt hour (¢/kWh) for a 15-, 20- or 25- year contract term until the subscribed capacity reaches 3 MW – after that the price will drop to 8.8 ¢/kWh for a 15-year contract term, 8.9 ¢/kWh for a 20-year contract term, or 9.1 ¢/kWh for a 25-year contract term; and o For non-solar eligible renewable energy resources: 8.3 ¢/kWh for a 15-year contract term, 8.4 ¢/kWh for a 20-year contract term, or 8.5 ¢/kWh for a 25-year contract term. There is no minimum or maximum project size, but the program is best suited for commercial property owners with available roof-tops or parking lots. Palo Alto’s Public Works Department recently solicited proposals to install solar PV systems and electric vehicle chargers at four City- owned parking structures. All four of these parking garage solar PV systems are operational as of March 2018. As of August 2018, there are a total of six solar PV systems participating in the Palo Alto CLEAN program, including the four aforementioned systems on City-owned parking garages. These six projects account for 2.915 MW of the capacity available at the 16.5 ¢/kWh contract rate, with contract terms ranging from 15 to 25-years; five of them projects are now operational, and the sixth is expected to be online by the end of 2018. Hydroelectric Resources Western Base Resource Since the 1960s, CPAU’s participation as a power customer of the Central Valley Project (CVP) has been an instrumental factor in its ability to deliver low-carbon electricity to Palo Altans at low rates. The U.S. Bureau of Reclamation (BOR) built the CVP in the 1930s and is charged with the operation, maintenance, and stewardship of the project. The CVP was constructed primarily for flood control of the Sacramento Valley area; however, it is also used to provide water for irrigation and municipal use and for navigation and recreational purposes. Hydroelectric generation is a lower priority function of the CVP, relative to the aforementioned purposes. The BOR is legally required to first provide power to “Project Use” for operations and pumping water through the CVP project, and then to “First Preference Customers,” those customers whose livelihood and/or property/land was impacted by the construction of the CVP. The remaining hydroelectricity (“Base Resource”) is then made available for marketing under long-term contracts with not-for-profit entities such as municipal utilities and special districts. The Western Area Power Administration (WAPA) is the federal Power Marketing Agency charged with marketing and contracting with customers for the electric output associated with the CVP, and collecting funds to meet allocated revenue requirements on behalf of the BOR. In 2000, the City executed a new 20-year contract with WAPA for CVP power deliveries starting in 2005. Under this contract the City receives 12.3% of all the Base Resource product output and is Section IV: Existing Resource Portfolio 24 obligated to pay 12.3% of all the CVP’s revenue requirements as allocated to power customers, regardless of the amount of energy received. Under normal precipitation and hydrological conditions, this resource provides nearly 40% of CPAU’s electricity needs. However, since 2005 the amount has varied from a low of 22% to a high of 64%. The corresponding cost per MWh has ranged from $22 to $61/MWh. The current Base Resource contract is set to expire at the end of 2024. Western’s proposed 2025 Power Marketing Plan, submitted to the United States Federal Register Notification (U.S. FRN No 27433), if approved by the Department of Energy, would allow existing Base Resource power customers to renew up to 98% of their existing allocation for a thirty-year term (2025-2054) under similar contract terms and conditions to their existing contracts. The process for extending this contract is well underway and is expected to take five to seven years to complete (Western's 2025 Power Marketing Plan Tentative Schedule). CPAU staff has been actively involved in the process by providing informal and formal comments in response to the 2025 Western Power Marketing Plan and by working with WAPA staff and other Base Resource contract customers to develop a better model of long-term generation and cost projections. Pending approval of the 2025 Power Marketing Plan, Western will seek commitments through execution of the new Base Resource contract in 2020 – although participants are expected to have an option to reduce participation and/or terminate their contract in 2024. A key topic for consideration in the EIRP is whether or not the City should renew its Base Resource contract – and if so, at what level. The analysis necessary to aid Council in its decision will need to consider the cost and the value of the resource going forward, which are both highly uncertain. This is due in large part to the nature of the CVP and supply availability, which is dependent on unpredictable precipitation conditions, the long-term effects of climate change, and the potential for new environmental policies and/or projects which threaten to erode generation value. The costs associated with participating in the Base Resource are also highly uncertain. First, the BOR has yet to update the cost allocation study necessary to establish rates for CVP power under the existing contract, and it is unclear when such rates will be published for the post-2024 period. Additionally, funding requirements under the Central Valley Project Improvement Act (CVPIA)14 and the appropriateness of the allocation of Restoration Fund collections between water and power customers is of serious concern to CPAU and other power customers, who have been actively encouraging BOR and Congress to adjust this allocation. Lastly, the potential for changes to local and state RPS requirements – such as portfolio mandates or carve-outs for baseload renewables and/or not providing consideration for supply variability associated with large hydroelectric resources – as well as the potential for loss of load due to distributed energy resources or load defection, increase the risk of a renewed Base Resource contract becoming a 14 The Central Valley Project Improvement Act was passed by the U.S. Congress in 1992 to establish the Restoration Fund, funding requirements and goals to restore the habitat of the area impacted by the CVP. Water and power customers are obligated to pay into the Restoration Fund. https://www.usbr.gov/mp/cvpia/docs/public-law-102-575.pdf Section IV: Existing Resource Portfolio 25 stranded resource, unless clear and reasonable termination provisions are included in the new contract. NCPA staff and CPAU staff are in the process of assessing the impact magnitude and likelihood of several issues which threaten to dilute the future value of Base Resource, as well as NCPA’s and CPAU’s ability to influence these issues. These issues are in addition to highly variable hydrological and precipitation conditions which create year-to-year variations in value. Staff and NCPA will work towards refining the analysis of these risk factors, to aid in the decision of how much Base Resource to renew for the post-2024 period. Calaveras Calaveras was bond-funded and built as a joint project between members15 of the Northern California Power Agency (NCPA) and the Calaveras County Water District (CCWD) in 1983. CCWD holds the Federal Energy Regulatory Commission (FERC) license and NCPA is the project operator. The project resides on the North Fork of the Stanislaus River in Calaveras, Alpine and Tuolumne Counties. Calaveras was built primarily for hydroelectric generation purposes and as such water is stored and managed to optimize generation value and to meet member owners’ energy needs. Palo Alto’s share in the project is 22.92%, which serves approximately 14% of the City’s annual load in an average hydro year. Calaveras’ project capacity is about 253 MW and can generate 575 gigawatt-hours (GWh) of energy annually under average hydroelectric conditions. Palo Alto’s corresponding share of the output is 58 MW of capacity and 132 GWh of annual energy. As of January 2019, the City’s outstanding debt on the project is approximately $89 million, of which a large portion will be maturing in 2024 and the remainder will mature in 2032. Annually through fiscal year 2024, the City’s debt related to this project is on average about $9 million. For the remaining years until 2032, the debt is about $5 million. Historically, debt and other costs associated with Calaveras have resulted in the overall value of the project being below market.16 For FY 2018, Palo Alto’s share of the project cost, including debt, is $12.5 million and the value is expected to be $5.7 million, resulting in a net cost of $6.8 million. However, because Calaveras’ variable operating and maintenance costs are relatively low, the project is dispatched regularly for the purpose of generating energy. Additionally, Calaveras has the ability to meet several CAISO compliance and operating requirements, including: following variations in the City’s load in real-time (load following), ancillary services related to regulation energy and spinning reserves; and meeting some of the City’s Resource Adequacy 15 NCPA members participating in the Calaveras Project via the Calaveras Third Phase Agreement with NCPA include the cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Roseville, Santa Clara, and Ukiah, and the Plumas- Sierra Rural Electric Cooperative. 16 In anticipation of Direct Access and the possibility for load to leave CPAU, in 1996 Council approved a competitive- transition-charge (CTC) to be added as a non-by-passable fee on all CPAU customers electricity bills. This was done to collect the above market cost (stranded cost) associated with Calaveras debt and the funds were held in the Calaveras Reserve, which had been established in 1983 to help defray cost associated with Calaveras. The Calaveras Reserve was repurposed in 2011 and is now the Electric Special Project Reserve (see Staff Report 2160). Section IV: Existing Resource Portfolio 26 requirements, including flexible capacity and system capacity. Calaveras also serves as an energy storage asset, since water is stored in the main reservoir, New Spicer Meadow, and released at optimal times to meet energy and capacity needs. Long-term it is expected that the value of Calaveras will increase, assuming average or above average hydroelectric conditions and favorable regulatory requirements. While there are no imminent decisions associated with Calaveras, a few issues may be worth evaluating in the context of the EIRP, including: 1. Assessment of Calaveras value and operating strategies, given the City’s commitment to other large hydroelectric resources, RPS resources, and hydro risk management objectives; 2. How to best optimize Calaveras given its potential value to meet intermittent resource integration requirements; and 3. The value of the City’s long-term stake in Calaveras, including the post-2032 period, when the current FERC license expires. Renewable Energy Resources Wind PPAs Palo Alto currently has two long-term contracts for the output of wind power projects. Under separate contracts with Avangrid Renewables (formerly Iberdrola Renewables), the City receives a 25 MW share of the output of the Shiloh I project, and a 20 MW share of the output of the High Winds I project in Solano County, both of which are located in Solano County. The terms of these two contracts end in 2021 and 2028, respectively. Together, the two resources typically supply about 12% of Palo Alto’s total electric supply needs. Both projects are considered fully deliverable, and are located in the Bay Area local reliability area. Landfill Gas (LFG) PPAs Palo Alto currently has five long-term contracts with Ameresco for the output of landfill gas electricity projects. The five contracts include a 1.5 MW share of a project located in Watsonville, a 5.1 MW share of a project located in Half Moon Bay, a 1.9 MW share of a project located in Pittsburg, and the entire output of a 1.4 MW project located in Gonzales and a 4.1 MW project located in Linden. The terms of these agreements are all 20 years, with contract expiration dates between 2025 and 2034. Together, the five resources currently supply about 11% of Palo Alto’s total electric supply needs. All five projects are also considered fully deliverable, with two of them located in the Bay Area local capacity area. Solar PPAs Since the beginning of 2012, Palo Alto has executed six long-term contracts for utility-scale solar PV projects. These six contracts include three with sPower (the 26.7 MW Hayworth Solar project located in Bakersfield, and the 20 MW Western Antelope Blue Sky Ranch B project and the 40 MW Elevation Solar C project – both of which are located in Lancaster), two with Clēnera (the 20 MW EE Kettleman Land project in Kettleman City and the 20 MW Frontier Solar project located in Newman), and one with Hecate Energy (the 26 MW Wilsona Solar project, which is slated to be built near Palmdale). The first five of these projects are currently operational, and they provide roughly 33% of Palo Alto’s total electricity needs; meanwhile, the Wilsona project is scheduled to begin energy deliveries in mid-2021. The terms of these agreements are all at least 25 years, with contract expiration dates starting in 2040. Section IV: Existing Resource Portfolio 27 The three projects operated by sPower are considered fully deliverable, with the Hayworth project located in the Kern local capacity area, and the other two located in the Big Creek-Ventura local capacity area. Market Purchases & RECs Palo Alto has nine active Master Agreements (with BP Energy, Shell Energy North America, Powerex Corp, Cargill Power Markets, Exelon Generation, Iberdrola Renewables, NextEra Energy Power Marketing, Turlock Irrigation District, and PacifiCorp) to facilitate competitive forward market purchases and sales to meet Palo Alto’s loads in the short- to medium-term. As of June 30, 2018, Palo Alto had outstanding electricity purchase commitments for the period July 2018 to June 2020 totaling 79 GWh, and sales commitments for this period totaling 161 GWh. These market based purchases and sales are made within the parameters of Palo Alto’s Energy Risk Management Program. In FY 2018, gross market-based purchases (including both forward transactions and spot-market transactions) provided approximately 14% of Palo Alto’s electricity needs, while gross market-based sales were equivalent to 23% of Palo Alto's needs (i.e., the City was a net seller of market-based energy). The volume of market purchases and sales however is highly dependent on hydro conditions and long-term commitments to renewable resource-based supplies. During normal hydro conditions, gross market purchases are expected to meet approximately 15% of energy needs, while gross market sales will amount to approximately 25% of energy needs. NCPA serves as Palo Alto’s scheduling and billing agent for all transactions, and acts as the interface with the CAISO under a Metered Subsystem Aggregation Agreement (MSSA). Since 2013, Palo Alto has operated under a Carbon Neutral Plan for its electric supply portfolio, ensuring that all electrical generation that serves the City’s needs produces zero GHG emissions on a net annual basis. To implement the Carbon Neutral Plan, in years when the City has been a net purchaser of market power (e.g., in very dry hydro years, or before the City’s long-term solar contracts had started delivering power to Palo Alto), it has purchased Renewable Energy Certificates (RECs) in volumes equivalent to its net market power purchase volumes. COBUG In 2002, shortly after experiencing a series of rolling blackouts during the California energy crisis, the City decided to invest in a set of locally-sited natural gas-fired back-up generators in order to stave off such events in the future. These four generators, together known as the Cooperatively Owned Back-Up Generator (COBUG), total 5 MW in capacity but are seldom operated (generally only for maintenance purposes). They do, however, serve as an important source of local system reliability in the Bay Area local capacity area. California-Oregon Transmission Project (COTP) Fourteen Northern California cities and districts and one rural electric cooperative, including Palo Alto, are members or associate members of a California joint powers agency known as the Transmission Agency of Northern California (TANC). TANC, together with the City of Redding, WAPA, two California water districts, and Pacific Gas and Electric (PG&E) own the California-Oregon Transmission Project (COTP), a 339-mile long, 1,600 MW, 500 kV transmission power project between Southern Oregon and Section IV: Existing Resource Portfolio 28 Central California. Palo Alto is entitled to 4.0% of TANC's share of COTP transfer capability (50 MW). As a result of low utilization of the transmission capacity and therefore low value relative to costs (in addition to a focus on acquiring in-state renewable resources), in August 2008 Palo Alto effected a long-term assignment of its full share and obligations in COTP to the Sacramento Municipal Utility District (SMUD), Turlock Irrigation District (TID), and Modesto Irrigation District (MID). The long-term assignment is for 15 years (through 2023), with an option to extend the assignment for an additional five years. Resource Adequacy Capacity As described above, the majority of Palo Alto’s long-term generation contracts (and its one owned thermal generating asset) are deemed fully deliverable and provide the City with Resource Adequacy (RA) capacity to satisfy its CAISO regulatory requirements. The amounts of RA capacity provided by each resource are detailed in the CRAT standardized table in the appendices of this report, and a high- level overview is provided in Table 6 below. Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio Project Resource Type Local Area Flexible RA? Average NQC (MW) Western Base Resource Hydroelectric CAISO System No 147.0 Calaveras Hydroelectric CAISO System Yes 58.0 High Winds Wind Bay Area No 4.5 Shiloh I Wind Bay Area No 5.7 Santa Cruz LFG Landfill Gas CAISO System No 1.5 Ox Mountain LFG Landfill Gas Bay Area No 5.1 Keller Canyon LFG Landfill Gas Bay Area No 1.9 Johnson Canyon LFG Landfill Gas CAISO System No 1.4 San Joaquin LFG Landfill Gas CAISO System No 4.1 Hayworth Solar Solar PV Kern No 14.2 Elevation Solar C Solar PV Big Creek-Ventura No 21.9 Western Antelope Solar PV Big Creek-Ventura No 11.0 COBUG Natural Gas Bay Area No 4.5 Section V: Future Procurement Needs and Portfolio Rebalancing 29 Future Procurement Needs and Portfolio Rebalancing Needs Assessment: Energy, RPS, Resource Adequacy Capacity Overall, Palo Alto’s resource portfolio has a surplus of energy, and a surplus of RPS generation (relative to its RPS procurement requirements under SB 350), as detailed in the Standardized Tables presented in Appendix D. Figure 6 below depicts the City’s projected supplies17 of eligible renewable generation for the period 2003 to 2038, as well as the City’s annual RPS generation procurement requirements under SB 350, based on its actual and forecasted retail sales volumes. Note that this figure presents only currently contracted resources; no additional resources are assumed to be procured, and no existing contracts are assumed to be extended. Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements In terms of capacity, the City has a surplus of system RA capacity, but deficit positions in local and flexible RA capacity.18 The City makes up these deficits each year via bilateral RA capacity purchases. One of the challenges that CPAU faces over the IRP planning period is ensuring that it can continue to 17 Note that renewable energy supplies shown in Figure xx which are surplus to the City’s RPS procurement requirements may ultimately be sold or banked for use in future compliance periods. 18 For additional details on Palo Alto’s projected needs and supplies of electrical generation, RPS generation, and RA capacity, please see the EBT, RPT, and CRAT standardized tables in Appendix D to this report. Section V: Future Procurement Needs and Portfolio Rebalancing 30 procure adequate supplies of local and flexible RA capacity – both to satisfy its regulatory compliance obligations, and to ensure the overall reliability of the CAISO bulk transmission system.19 However, during the IRP planning period, CPAU staff’s primary focus will be on determining whether to renew its Western Base Resource contract for a new 30-year term starting in 2025 – and if so, at what capacity share. As such, staff will be heavily focused on negotiating contract terms that provide the City with protection and flexibility, while also closely monitoring the many issues that are currently creating uncertainty around this resource’s long-term costs and generation levels. The remainder of this section of the EIRP will focus on exactly this question: whether to renew the Western Base Resource contract at the maximum possible level, or whether to “rebalance” the City’s electric supply portfolio by scaling back (or eliminating) the City’s Base Resource allocation and replacing it with a different generation resource. Portfolio Rebalancing Analysis As noted in the September 2017 report to the Palo Alto UAC, CPAU staff evaluated a very large number of potential new supply-side and demand-side resources in the portfolio analysis it performed related to the Western Base Resource contract renewal decision. However, as the analysis progressed, due to reasons of feasibility/availability and cost/uncertainty, staff narrowed the focus of the analysis to the following resources: • A renewed Western Base Resource (Western) contract, • In-state solar, • Out-of-state wind, • Geothermal, • Local (Palo Alto) solar, and • Market power purchases matched with renewable energy certificates (RECs). The Western hydro resource and in-state solar resource characteristics are well understood, given the large role they each play in Palo Alto’s current resource portfolio. Western is a relatively low-cost, flexible resource – at least in average years – but it features a large amount of seasonal variability, as well as year-to-year uncertainty around its cost and level of output. In addition, there are several major issues currently pending that have the potential to significantly impact the cost and/or operation of the resource.20 Solar also involves a great deal of seasonal variability and contributes towards the seasonal 19 Also, if Palo Alto opts not to renew its Western Base Resource contract in 2025 – or significantly scales back its share of this resource – then the City will face the additional challenge of ensuring it has adequate system RA capacity to meet its planning reserve margin requirements. As Table 6 indicates, the Western Base Resource contract is by far the City’s largest source of system RA capacity. 20 For example: The State Water Resources Control Board has several proceedings underway that may have very significant impacts on Western operations, including the consideration of an “unimpaired flow” criteria as part of its Bay Delta Plan that could result in significantly less generation from Western, particularly in the summer months. There are also long-term risks associated with an increase in “Aid to Irrigation” payments that Power customers may be required to make to Water customers, litigation related to the Central Valley Project Improvement Act (CVPIA) Restoration Fund payments that Power customers make, potential cost impacts to Power customers related to the “Twin Tunnels” project, and the impacts of climate change on the resource. Staff hopes that many of these uncertainties will be better understood by 2024; however it is likely that a number of them will remain unresolved. These risks must be more closely examined before making a final contract commitment in 2024. Section V: Future Procurement Needs and Portfolio Rebalancing 31 imbalance of the supply portfolio, but with far less uncertainty around its cost or annual output amount. And while its costs have decreased dramatically in recent years, the huge volume of recent capacity additions – which have been concentrated in areas with the best solar potential – have driven down the market value of this energy at least as much, leading to a sharp increase in negative market prices and curtailments. The rise of solar generation in the state has also led to the Duck Curve phenomenon21, which has in turn resulted in new regulatory requirements for each load-serving entity (LSE) to procure sufficient flexible generation capacity to maintain transmission grid reliability. Out-of-state wind resources – e.g., from the Pacific Northwest or New Mexico – have also become very low-cost in recent years, in some cases even lower priced than solar.22 Wind resources from these areas typically have a generation profile that is a good fit for the City’s portfolio, producing somewhat more energy in the fall and winter months than in the spring and summer months. However, the cost of obtaining transmission access for them into the state significantly raises their total cost.23 Geothermal resources have also experienced a price decline in recent years, although they are still less valuable compared with solar or out-of-state wind. New binary cycle geothermal technology also produces no GHG emissions and can be more flexibly dispatched compared to prior generations of geothermal technologies. This technology bears further consideration in the coming years as the City considers options to rebalance the portfolio. Local solar is the only local supply resource considered in the portfolio analysis. While it would have a higher value than solar located in the central San Joaquin Valley24 it is unlikely to be available in sufficient quantities to make a significant contribution to the City’s overall electric supply needs. The cost of such local systems would also be relatively high. For example, under the Palo Alto CLEAN program, even with a contract price of 16.5 cents/kWh, the program existed for several years before finally securing about 3 MW of participating capacity within the last two years. And the cost of solar energy from a 500 kW project at the Palo Alto golf course was estimated at 10 to 14 cents/kWh in 21 The Duck Curve refers to the graph shown in Figure 1, illustrating the impact of the increasing adoption of solar PV on CAISO’s net load (i.e., total load less generation from variable energy resources like wind and solar). Over time, as more solar generation came online, the CAISO net load curve went from having a slight mid-day peak to having a deep mid-day trough, bracketed by a steep downward ramp in the morning, as solar plants begins generating, and an even steeper upward ramp in the evening, as solar generation trails off with the sunset. For more information, see: https://www.caiso.com/documents/flexibleresourceshelprenewables_fastfacts.pdf. 22 Staff has received numerous proposals for out-of-state wind resources over the past several years, but such resources were found to be uneconomical compared to in-state solar when Palo Alto made long-term commitments for solar resources between 2012 and 2016. 23 The availability of transmission pathways to bring this generation into CAISO on a reliable basis is also not assured. However, for Pacific Northwest wind resources, the City’s allocation of capacity on the California-Oregon Transmission Project (COTP) could prove very useful. The City laid off this transmission capacity for a 15-year period, but this layoff will end at the end of 2023. 24 Local solar is currently at least 3 ¢/kWh more valuable than remote solar, given that it would provide enhanced local resiliency, would not be subject to transmission charges, would reduce the City’s resource adequacy capacity requirements, and would have a high locational value, due to its mitigating effect on Bay Area transmission congestion. Section V: Future Procurement Needs and Portfolio Rebalancing 32 2017, which is more costly compared to other resource options, even with the greater value (primarily due to avoided transmission charges) inherent in local generation. Finally, market energy purchases combined with unbundled RECs could present an attractive option in the short-term if the City wishes to reduce its Western contract allocation and seek a different low-cost solution. In the long-term, however, many forecasts indicate that as the state’s GHG reduction requirements ratchet up, the cost of carbon allowances will likewise climb, which in turn would raise market power prices and make this option uneconomic. In addition, this approach would perpetuate the City’s reliance on traditional GHG-emitting generators. On the other hand, shorter-term market purchases would provide the City with a great deal of flexibility in terms of contract duration and volume, and lower the risk of stranded energy resources if the electric loads available to be served by the City decline significantly. Table 7 below summarizes the various resource types that staff considered most closely in its portfolio analysis and their relative merits. The key indicators used for comparing the different portfolio options are: • Value: The net value of a resource; the projected revenue from selling the resource’s energy into the CAISO market less the resource’s bi-lateral contract cost; • Portfolio Fit: Lower reliance on the grid for hourly load balancing; • Diversification: Geographic and resource diversity; • Term Flexibility: Flexibility in length of contract and termination provisions; and • Cost Certainty: Degree of certainty of future resource costs. Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio * Ratings reflect relative changes from current portfolio of resources * Section V: Future Procurement Needs and Portfolio Rebalancing 33 Portfolio Expected Net Value First, as far as the net value of a resource contract for the 2025 to 2030 period, Western has the potential to be a relatively valuable resource, but also has the most uncertainty when it comes to costs, for the reasons described above. The expected net value of Western and several potential new contracts, as determined by a scenario-based spreadsheet analysis, is shown in Figure 7. The net value of each resource is calculated based on its energy values (from each resource’s LMP forecast), along with the ancillary services value provided by Western, the value of the RECs generated by the renewable resources, and each resource’s RA capacity. Note that the expected net value of some resources is negative (less valuable than projected market value), due to the fact that the cost of all of the renewable resources includes the cost of renewable attributes in addition to energy, and because a primary goal of a long-term agreement such as a PPA is to hedge and manage exposure to future price volatility. Figure 7: Expected Net Value of New Resources and Western Relative to Market Value * Very High Cost Uncertainty around Western * One of the primary messages of Figure 7 is that there is a tremendous amount of uncertainty around the net value of Western, as indicated by the large uncertainty bars featured on that data series.25 It should be noted that the uncertainty shown in Figure 7 is based on staff’s best estimate of the 25 Figure C-6 does not include market price uncertainty or hydrological uncertainty; the uncertainty range shown for Western represents purely regulatory and litigation-related cost uncertainty. Section V: Future Procurement Needs and Portfolio Rebalancing 34 potential range of future Western contract costs. It should also be noted that this uncertainty is heavily biased toward the negative direction: there is limited “upside” uncertainty while there is a great deal of “downside” uncertainty, largely related to pending environmental regulatory issues. Portfolio Fit Another key indicator is hourly portfolio fit, which will determine how reliant the portfolio is on grid power (and, as a result, how exposed it is to market prices). Figure 8 displays average hourly generation profiles for each month (one average day per month is shown) for Western and other potential new resources relative to the City’s average load. Although total resource supplies from long- term contracts exceed the City’s load in the spring and summer months, the opposite is true during the fall and winter months. Thus Figure 8 indicates that out-of-state wind, which produces more energy in the fall and winter months, would be a good complement to the City’s existing portfolio. In-state wind (in the Solano hills) and solar, on the other hand, exacerbate the City’s portfolio fit problem, as they produce more energy in the spring and summer months. Figure 8: Average Hourly Load and Generation Profiles for Each Month for Western and Potential New Resources (Normalized to Average Hourly Load) * New Mexico Wind Resource Profile Complements Palo Alto Portfolio * Section V: Future Procurement Needs and Portfolio Rebalancing 35 Portfolio Cost Uncertainty and Management The cost uncertainty of the electric supply portfolio in the short-term is primarily driven by the water available for hydroelectric production, and is estimated at $10 to $15 million per year at prevailing market prices. Palo Alto is well positioned to manage this cost uncertainty through its hydro rate adjustment mechanism26 and by maintaining sufficient cash reserves. The cost uncertainty related to seasonally balancing the portfolio27 is minimal since market price variability between seasons is highly correlated and because staff executes seasonal buy-sell transactions at the same time. As noted above, in the long-term, there are a number of issues that could dramatically affect the value of the Western resource in the coming years. As such, a large focus of staff efforts in the next five years will be to better understand the long-term economics of the Western resource and mitigate the risks associated with it through flexible contractual terms. There are also proceedings underway to investigate market restructuring to deal with issues related to the integration of variable renewable resources, such as over-generation, very steep evening ramp periods, and the appropriate valuation of dispatchable generation capacity. Volatility in market prices, as the CAISO and the CEC determine how to send price signals to ensure a reliable grid, could leave a seasonally unbalanced portfolio such as the City’s current portfolio exposed. Increases in transmission charges could also make remote resources compare less favorably to local resources and demand-side management in the future. 26 For additional detail on the hydro rate adjustment mechanism, please see Staff Report ID 8962 (March 2018): https://www.cityofpaloalto.org/civicax/filebank/documents/63851. 27 Revenues received from the sale of surplus energy during the spring and summer periods are utilized to purchase electricity needs for the fall and winter periods. Section IV: Supply Costs & Retail Rates 36 Supply Costs & Retail Rates Critical to the success of an IRP, in addition to ensuring that the adopted plan leads to compliance with all regulatory requirements, is ensuring that it also results in supply cost minimization and (ideally) low and stable customer retail rates. As described in the FY 2019 Electric Utility Financial Plan and Rate Proposal to the Palo Alto City Council, CPAU staff projects supply costs to rise substantially for the next several years, largely driven by increases in transmission costs and new renewable energy projects coming online. Retail rates are also projected to rise due to substantial additional capital investment in the electric distribution system, and operational cost increases. In order to ensure adequate revenue recovery, the Palo Alto City Council recently approved a 6% retail rate increase for FY 2019 (taking effect July 1, 2018), and adopted a Financial Plan that calls for an additional 3% rate increase for FY 2020 with 0-2% annual rate increases projected thereafter. However, it should be noted that the City’s current electric rates are far lower than the statewide average electric retail rates, and, under the recommended portfolio presented in Section X of this report, staff projects that they will remain so. In fact, even under the worst-case scenarios staff evaluated the recommended portfolio against, as described in Section X.C of this report, the City’s retail electric rates remain lower than the projected statewide average rates. Section VII: Transmission & Distribution Systems 37 Transmission & Distribution Systems Transmission System At the transmission level, CPAU staff has two main focuses during the EIRP planning period: (1) determining the optimal utilization of the COTP asset when Palo Alto’s long-term layoff of this resource ends on January 1, 2024, as discussed above in the Existing Resource Portfolio section; and (2) pursuing an additional interconnection point with PG&E’s transmission system. The new interconnection point with PG&E is being sought in order to provide redundancy, and therefore increased local reliability, in the event that an outage affects the three current interconnection lines – as happened in February 2010.28 To minimize the possibility of a City-wide outage caused by an interconnection line outage, it is in the City’s interest to find a physically diverse connection to the PG&E transmission system for power supply to the City. Staff has been investigating options for an alternative connection to the transmission grid for numerous years.29 Distribution System Palo Alto’s electric distribution system is directly interconnected with the transmission system of Pacific Gas and Electric Company (PG&E) by three 115 kV lines, which have a delivery point at Palo Alto’s Colorado substation. Palo Alto’s distribution system consists of the 115 kV to 60 kV delivery point, two 60 kV switching stations, nine distribution substations, approximately 12 miles of 60 kV sub transmission lines, and approximately 469 miles of 12 kV and 4kV distribution lines – including 223 miles of overhead lines and 245 miles of underground lines. In 2018 CPAU staff completed a distribution system assessment report to begin the process of understanding the distribution system upgrades that will be required to integrate increasing penetration levels of distributed energy resources, particularly electric vehicles. Staff’s conclusion from this assessment was that at the system level, there is sufficient capacity to accommodate DER growth for the next five years. However, there are some subcomponents of the system that require further assessment and monitoring (e.g. residential distribution transformers). The City-wide implementation of Advanced Metering Infrastructure (AMI), which is planned to occur by 2022, will greatly enhance the visibility into distribution system operational characteristics and further enable the integration of DERs by offering new customer programs (such as, time varying rates). Palo Alto’s current five-year capital plan for electric distribution facilities contemplates spending approximately $16.5 million per year over this five-year period, primarily to fund infrastructure replacement and new customer connections. 28 Although three lines would normally provide redundancy and back-up power delivery to the City, all three lines run in a common corridor on the bay side of the City, a corridor that is in close proximity to the Palo Alto Airport. The common corridor and proximity to an airport means that the City’s power supply is susceptible to single events that can affect all three lines, as happened in February of 2010 when a small aircraft hit the power lines resulting in a city-wide power outage for over 10 hours. 29 See this January 2016 staff report for additional background on the efforts to secure an additional transmission interconnection point: https://www.cityofpaloalto.org/civicax/filebank/documents/50608. Section VIII: Low-income Assistance Programs 38 Low-income Assistance Programs CPAU has three programs to provide financial assistance to low-income customers: • Residential Energy Assistance Program (REAP): This program provides qualifying low-income residents with free energy efficiency measures and access to the Rate Assistance Program (RAP) rate discount. For qualifying customers, a Home Assessment, an application to the RAP, and an on-site customer evaluation for weatherization and energy efficiency measure installation, including insulation and lighting, is provided. Customers may have refrigerators and/or furnaces replaced if the need is found. • Rate Assistance Program (RAP): This program provides a 25% discount for electric and gas charges for qualified customers. Applicants can qualify based on medical or financial need. • ProjectPLEDGE: This program provides a one-time contribution of up to $750 applied to the utilities bill of qualifying residential customers. Eligibility criteria include experiencing recent employment and/or health emergency events. Administered by CPAU, this program is funded by voluntary customer contributions. Section IX: Localized Air Pollutants 39 Localized Air Pollutants Electric Vehicle Programs Given that Palo Alto’s electricity supply is derived entirely from clean, carbon neutral generation resources, the most important thing that the City can do at this point to improve local air quality is to reduce the combustion of fossil fuels in the transportation sector – primarily through electrification of vehicles. The City of Palo Alto Utilities has a number of programs to promote the adoption of electric vehicles, a summary of which can be found in the 2017 Demand Side Management Annual Report. Two of the current programs are listed below. EV Charger Rebate Program - In early 2017 CPAU launched an EV Charger Rebate program using funds from monetizing Low Carbon Fuel Standard (LCFS) credits. Rebates are targeted towards multifamily and mixed-use properties, schools and non-profits. Along with the launch, new online resources were created, including the EV calculator tool. Online EV/PV Calculator - CPAU launched an online calculator tool for residents to evaluate the costs and benefits of installing rooftop solar. In addition, residents can now evaluate different electric vehicles and see the financial impacts and environmental benefits of charging vehicles using Palo Alto’s carbon neutral electricity. The online calculator uses satellite imagery of Palo Alto homes as well as current CPAU electricity rates to produce rooftop solar system designs and cost estimates tailored to Palo Alto. Local Renewable Energy Programs In addition to the local renewable electricity generation programs previously mentioned, Palo Alto also has a Solar Hot Water Program which can replace natural gas combustion and thereby improve local air quality. Solar Hot Water Program - Palo Alto launched the solar water heating (SWH) program in May 2008, in advance of a State law requiring natural gas utilities to offer incentives. This program offers rebates of up to $2,719 for residential systems and up to $100,000 for commercial and industrial systems. A sample of these installations is inspected for quality and program compliance by an independent contractor. The program was recently extended through 2020. A total of 60 systems have been installed as of June 30, 2017; 54 of these are residential. From 2008 to 2017 $337,911.37 in rebates were disbursed. In the fiscal year 2017 this program resulted in annual energy savings of 19,826 therms and 13,387 kWh. Electrification of Space and Water Heating Programs The Electrification Work Plan highlighted the potential of lowering carbon emissions and improving local air quality by electrification of building water and space heating loads thereby removing local combustion of natural gas. A description of more programs to promote electrification of space and water heating can be found in the 2017 Demand Side Management Report. Two of the current electrification programs are listed below. Section IX: Localized Air Pollutants 40 Heat Pump Water Heater Pilot Program - The goal of this program is reduction of greenhouse gas (GHG) emissions through switching from natural gas appliances to high-efficiency electric appliances. Installation of heat pump water heaters (HPWHs) has been identified as a good starting candidate for a pilot program. The pilot program—launched in the spring of 2016—was designed to facilitate the installation of HPWHs in single-family homes. In April 2017, the City hosted its first HPWH workshop to educate the community, including contractors, on the technology and installation of HPWHs. Multifamily Gas Furnace Retrofit Pilot Program - CPAU has been awarded a 2018 Climate Protection Grant Program from the Bay Area Air Quality Management District (BAAQMD) for a Multifamily Gas Furnace Pilot Program. The grant period is two years from 2019-2020. The Multifamily Gas Furnace Retrofit Pilot targets apartment buildings to replace existing in-unit gas wall furnaces with high efficiency air source heat pumps. Heat pump systems are far more energy efficient than gas furnaces, eliminate GHG emissions associated with gas-fired space heaters, while improving air quality within the dwelling units. However, many questions still exist regarding cost- effectiveness, building electrical capacity and other technological and logistical hurdles for replacing gas furnace to heat pump systems in multifamily buildings. This pilot will identify the technical and logistical hurdles as well as potential solutions, and will document the retrofit cost, energy savings, avoided GHG emissions as well as other indoor air pollutants from the gas furnace. Refrigerant Recycling Program Ensuring that refrigerants are properly disposed of also improves local air quality. CPAU has also been awarded a 2018 Climate Protection Grant Program from the BAAQMD for a Refrigerator Recycling Program. The grant period is two years from 2019-2020. Although the City’s GreenWaste contractor can pick up and remove old refrigerators from customer houses, they are not certified to recycle the foams and refrigerant chemicals to the level that the US EPA Responsible Appliance Disposal (RAD) program requires. RAD requirements go above and beyond the State of California minimum recycling requirements. This BAAQMD grant will to cover a portion of the cost of recycling in order to enable us to both claim EE savings as well as meet the RAD standards in a cost-effective manner. Section X: Path Forward & Next Steps 41 Path Forward & Next Steps Recommended Portfolio Because almost six years remain before Palo Alto must make its major planning decision of the EIRP planning period (the Western contract renewal decision), it is difficult to definitively identify a single recommended portfolio at this time. The base case in this IRP assumes that Palo Alto will renew the Western contract at the maximum allocation level. However, given the substantial amount of uncertainty related to the cost and output levels of this resource (as described in the Future Procurement Needs and Portfolio Rebalancing section of this report), staff is actively reviewing attractive alternatives which could replace the entire Western contract when it expires in 2024. If, in fact, Palo Alto determines that the costs associated with a renewed Western contract are too high, or too uncertain, CPAU staff would immediately begin working to replace this resource (which currently supplies nearly 40% of the City’s electric load) with a different carbon neutral supply resource. As such, the City would continue on its path to meeting or exceeding both the state’s RPS procurement requirements and GHG emission reduction targets. Figure 9 below depicts Palo Alto’s projected electric resource supply mix in 2030 where a large portion of this mix currently consists of undetermined carbon-neutral resources. Given the City’s current policies and the state’s RPS and GHG emissions mandates, staff can confidently say that these resources will either be hydroelectric or renewable. Figure 9: Palo Alto’s Projected Resource Supply Mix in 2030 Section X: Path Forward & Next Steps 42 GHG Emissions CARB’s 2017 Scoping Plan identified GHG emissions targets for the entire state, as well as individual economic sectors, including the electricity industry. The Scoping Plan established an overall electric sector GHG target for 2030 of 30 to 53 million metric tonnes (MMT) of CO2e, of which Palo Alto’s pro rata share (based on load) is 0.174%, or 52,049 to 92,103 MT CO2e. As Figure 10 indicates, given its electric supply portfolio consisting entirely of carbon-free resources (hydroelectric, wind, solar, and biogas), Palo Alto is on track to emit far less than even the most aggressive end of the target range identified in the CARB Scoping Plan. Scenario Analysis As described in Section II.D of this report, an important element of integrated resource planning is to put the recommended portfolio through scenario and risk analysis, to assess its performance under a range of potential conditions. Staff has performed such a scenario analysis around the recommended portfolio presented in this report, evaluating its performance while varying the following factors: market prices, hydrological conditions, environmental regulations affecting hydro resource operations, DER adoption rates, and natural customer load growth rates. Under all cases examined, however, the City’s supply portfolio remained in compliance with the RPS and GHG emissions targets set forth in SB 350, all while keeping Palo Alto customers’ retail rates lower than the statewide average retail rates. Figure 10: CPAU Electric Supply GHG Emissions (2005-2030) Section X: Path Forward & Next Steps 43 Next Steps As there is so much uncertainty regarding the Western resource, and because the decision is such a consequential one, it merits a follow-up analysis closer to the contract renewal date, which is currently scheduled for mid-2020. Even after that, WAPA’s 2025 Power Marketing Plan indicates that the City will have until July 2024 to make a decision to reduce or reject its allocated share of the future Western contract, which is expected to be approximately as large as its current share. The additional analysis regarding this decision should include: 1. An examination of the City’s net load forecast and associated uncertainties, in line with the Draft DER Plan discussed with the UAC in November 2017, with particular emphasis on how it may be affected by customer adoption of DERs (EVs, Demand Response, Energy Efficiency, Solar PV, storage, and building electrification) in order to avoid stranding assets. 2. An update and extension of CPAU’s supply portfolio analysis, including updates to the hourly LMP forecasts and the costs, assumptions, and uncertainties associated with all resource options. 3. Analysis of the projected costs, output, and flexibility of the renewed Western contract, to reduce the amount of outstanding uncertainty around this resource. 4. Advocating for flexible contractual provisions in the new Western contract, and examining the legal and economic merits and risks associated with committing to the Western resource for 30 more years. Aside from the Western contract decision, staff will be actively following state regulators’ activities related to electric supply portfolio GHG emissions accounting and allocation of statewide GHG emissions reduction targets. While the City’s current GHG emissions accounting methodology (adopted by the City Council in 2013 with the Carbon Neutral Plan) for electric supplies is based on a net annual accounting of the City’s market power purchases (which are assumed to have the statewide average GHG emissions intensity), staff is aware that state regulators are evaluating alternative GHG emissions accounting methodologies, including various types of hourly accounting approaches. And of course, staff will continue its activities in pursuit of lowering the overall cost to serve customer loads. These include continuing to optimize the use of the City’s Calaveras resource, evaluating the benefits of the NCPA pool, and/or the procurement of alternative scheduling services for its renewable resources. Key Issues to Monitor & Attempt to Influence In the course of developing this EIRP, CPAU staff has identified a number of important issues and sources of uncertainty to closely monitor and attempt to positively influence over the course of the planning period. Some of the primary issues and uncertainties that staff will be focused on include: • Cost and operations of Western hydroelectric resource: environmental restoration cost, water delivery timing and priorities, Western transmission upgrade needs, environmental regulations affecting water releases, and long-term climate change • Frequency and magnitude of economic curtailment of solar PV resources • Renewing the FERC license of the Calaveras hydroelectric project Section X: Path Forward & Next Steps 44 • Seasonal variation in CAISO energy market prices, given the overall generation profile of CPAU’s resource portfolio • Changes in overall energy market price and changes in carbon allowance prices associated with State's cap-and-trade program • Increased market prices related to load-following capacity and ancillary services • Customer load profiles change and loss of customer loads available for the City to serve • New legislative and regulatory mandates Section XI: Appendices XI—1 Appendices Key Supplemental Reports and Documents 1. NCPA-CAISO Metered Sub-System Agreement 2. Ten-Year Electric Energy Efficiency Goals (2017) 3. Energy Storage Assessment Report (2017) 4. Proposed Distributed Energy Resources Plan (2017) 5. Distribution System Assessment Report (2018) 6. Demand Side Management Annual Report (2018) Section XI: Appendices XI—2 RPS Procurement Plan CITY OF PALO ALTO’S RENEWABLE PORTFOLIO STANDARD PROCUREMENT PLAN Version 3 December 2018 REVISION HISTORY Version Date Resolution Description 3 12/3/18 Updated to reflect Senate Bill 350 (2015) requirements 2 11/12/13 9381 Updated to reflect adoption of final CEC regulations, effective 10/1/13, permitting the City to adopt rules for Excess Procurement, Compliance Delay, Cost Limitations, Portfolio Balancing Reductions, and Historic Carryover. Other non-substantive clean up. 1 12/12/11 9215 Original version per Senate Bill X1 2 (2011) requirements Section XI: Appendices XI—3 TABLE OF CONTENTS INTRODUCTION ....................................................................................................................... XI—4 A. PURPOSE OF THE PLAN (PUC § 399.30(A)) ................................................................... XI—4 B. PLAN ELEMENTS ............................................................................................................... XI—5 1. Compliance Period Definitions ........................................................................................... XI—5 2. Procurement Requirements ................................................................................................ XI—5 3. Portfolio Content Categories (PCC) ................................................................................... XI—6 4. Portfolio Balancing Requirements ..................................................................................... XI—6 5. Long-Term Contract Requirement ..................................................................................... XI—7 6. Reasonable Progress ............................................................................................................. XI—7 C. OPTIONAL COMPLIANCE MEASURES ............................................................................. XI—7 1. Excess Procurement (PUC §399.13(a)(4)(B)) ................................................................... XI—7 2. Delay of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5)) .................................... XI—8 3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c)) .......................... XI—10 4. Portfolio Balance Requirement Reduction (PUC § 399.16(e)) .................................. XI—11 5. Historic Carryover ................................................................................................................ XI—11 6. Large Hydro Exemption (PUC § 399.30(l)) ..................................................................... XI—13 D. ADDITIONAL PLAN COMPONENTS ............................................................................... XI—14 1. Exclusive Control (PUC § 399.30(n))................................................................................ XI—14 2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f)) ........................................ XI—14 3. Annual Review ................................................................................................................. XI—15 4. Plan Modifications/Amendments ..................................................................................... XI—15 Section XI: Appendices XI—4 INTRODUCTION This document presents the City of Palo Alto Utilities’ (CPAU) Renewable Portfolio Standard Procurement Plan (RPS Procurement Plan), as required for compliance with Senate Bill (SB) 350.30 This legislation, which was signed into law in the 2015 Session of the Legislature, modified the state’s renewable portfolio standard (RPS) program and set forth RPS requirements applicable to all load- serving entities in the state. Pursuant to Public Utility Code § 399.30(a) and Section 3205 of the California Energy Commission’s (CEC) “Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric Utilities”31 (RPS Regulations), each POU must adopt and implement a renewable energy resources procurement plan (RPS Procurement Plan). SB X1 2, signed into law in 2011, directed the CEC to adopt regulations specifying procedures for enforcement of the RPS for Publicly Owned Utilities. This RPS Procurement Plan replaces the RPS Procurement Plan approved by the Palo Alto City Council (City Council) on November 12, 2013 (Resolution No. 9381, Staff Report No. 4168) and is consistent with the provisions set forth in the CEC’s RPS Regulations, which have been adopted by the CEC and approved by the Office of Administrative Law, with an effective date of April 12, 2016.32 CPAU’s RPS Procurement Plan consists of: A. Purpose of the plan; B. Plan Elements; C. Measures that address each of the optional provisions set forth in §399.30(d) and RPS Regulations Section 3206; and D. Additional provisions. Where appropriate, this RPS Procurement Plan includes section citations to the Public Utilities Code (PUC) and the CEC’s RPS Regulations. A. PURPOSE OF THE PLAN (PUC § 399.30(A)) In order to fulfill unmet long-term generation resource needs, the City Council adopts and implements this RPS Procurement Plan. This Plan requires the utility to procure a minimum quantity of electricity 30 SB 350 (2015) was signed by California’s Governor on October 7, 2015, and made significant revisions to Public Utilities Code sections 399.11-399.32, the California Renewable Portfolio Standard Program. 31 California Code of Regulations, Title 20, Division 2, Chapter 13, Sections 3200 ‐ 3208 and Title 20, Division 2, Chapter 2, Section 1240. 32 At the time of writing for this edition of CPAU’s RPS Procurement Plan, the RPS Regulations had not been updated with SB 350 and subsequent legislative requirements. Where both Public Utility Codes and RPS Regulations are cited but the RPS Regulations are outdated, CPAU’s RPS Procurement Plan will reflect the more current Public Utility Codes. Section XI: Appendices XI—5 products from eligible renewable energy resources, including renewable energy credits (RECs), as a specified percentage of CPAU’s total kilowatt-hours of electrical energy sold to its retail end-use customers, during each compliance period, to achieve the targets specified in SB 350 and the RPS Regulations. This RPS Procurement Plan establishes the framework for achieving the minimum requirements under SB 350 and the RPS Regulations, and does not include or preclude actions taken by CPAU to achieve the City Council’s goals. B. PLAN ELEMENTS CPAU will comply with the requirements for renewables procurement targets set forth in SB 350 and the applicable enforcement procedures codified in the CEC’s RPS Regulations, including implementation of the following Plan Elements: 1. Compliance Period Definitions CPAU has adopted the relevant compliance period definitions identified in PUC § 399.30(b). 2. Procurement Requirements CPAU shall meet or exceed the following procurement targets of renewable energy resources for each compliance period per PUC §§ 399.30(c)(1) and (2) and the CEC’s RPS Regulations: Compliance Period 1 Target ≥ 20% × (CPAU Retail Sales2011_+ CPAU Retail Sales2012 + CPAU Retail Sales2013). Compliance Period 2 Target ≥ 20% × CPAU Retail Sales2014 + 20% × CPAU Retail Sales2015 + 25% × CPAU Retail Sales2016 Compliance Period 3 Target ≥ 27% × CPAU Retail Sales2017 + 29% × CPAU Retail Sales2018 + 31% × CPAU Retail Sales2019 + 33% × CPAU Retail Sales2020 Compliance Period 4 Target ≥ 34.75% × CPAU Retail Sales2021 + 36.5% × CPAU Retail Sales2022 + 38.25% × CPAU Retail Sales2023 + 40% × CPAU Retail Sales2024 Compliance Period 5 Target ≥ 41.67% × CPAU Retail Sales2025 + 43.33% × CPAU Retail Sales2026 + 45% × CPAU Retail Sales2027 Compliance Period 6 Target ≥ 46.67% × CPAU Retail Sales2028 + 48.33% × CPAU Retail Sales2029 + 50% × CPAU Retail Sales2030 Annually thereafter, CPAU shall procure renewable energy resources equivalent to at least fifty percent (50%) of retail kilowatt-hour sales. Section XI: Appendices XI—6 The procurement targets listed for each individual year above are soft targets. That is, by the end of each Compliance Period, CPAU’s RPS total for the period has to equal the sum of the annual targets, but the targets do not have to be achieved in any one year. 3. Portfolio Content Categories (PCC) CPAU adopts the definitions for qualifying electric products and Portfolio Content Categories (PCC) per Sections 3202 and 3203 of the CEC’s RPS Regulations. a. How CPAU Plans to Achieve its RPS Requirements per Section 3205(a)(1) of the CEC’s RPS Regulations CPAU’s RPS portfolio will include grandfathered contracts (commonly referred to as “PCC 0”), which are executed prior to June 1, 2010, and PCC 1 eligible resources, which are typically directly or dynamically connected to a California balancing authority. CPAU’s RPS portfolio may also include PCC 2 eligible resources that are scheduled into a California balancing authority, and PCC 3 eligible resources, which are typically unbundled renewable energy credits (RECs). PCC 0 resources are defined in Section 3202(a)(2) of the CEC’s RPS Regulations, while PCC 1, 2, and 3 resources are defined in Section 3203 of the CEC’s RPS Regulations. CPAU shall determine the category to which each procured resource belongs. In its 2011 through 2017 RPS Compliance Reports, CPAU listed a total of five PCC 0 contracts. All five of these contracts extend through the end of Compliance Period 3, and all have achieved commercial operation. On their own, these PCC 0 contracts were sufficient to enable CPAU to meet its Compliance Period 1 and 2 RPS targets. CPAU has currently executed six contracts for PCC 1 resources. The first five of these, executed between 2012 and 2014, have all commenced operation, between 2014 and 2016. The sixth PCC 1 contract, executed in 2016, is contracted to commence operation in 2021. With these six PCC 1 resources, along with its five PCC 0 contracts, CPAU forecasts that its renewable energy supplies will be well in excess of its procurement requirements through at least Compliance Period 6. 4. Portfolio Balancing Requirements In satisfying the procurement requirements listed in section B.3 of this RPS Procurement Plan, CPAU shall also satisfy the legally-required portfolio balancing requirements specifying the limits on quantities for PCC 1 and PCC 3 per PUC § 399.30(c)(3), §§ 399.16(c)(1) and (2). CPAU shall apply the formulae specified in Section 3204(c) of the CEC’s RPS Regulations to determine these portfolio balance requirements. Renewable energy procured from PCC 0 contracts shall be excluded from these portfolio balancing requirement formulae. Section XI: Appendices XI—7 5. Long-Term Contract Requirement In meeting the RPS procurement requirements identified in section B.3 of this RPS Procurement Plan, CPAU is subject to long-term contract requirements. Consistent with Public Resources Code § 399.13(b), CPAU may enter into a combination of long- and short-term contracts for electricity and associated renewable energy credits. Beginning January 1, 2021, at least 65 percent of CPAU’s procurement that counts toward the RPS requirement of each compliance period shall be from its contracts of 10 years or longer or in its ownership or ownership agreements for eligible renewable energy resources. 6. Reasonable Progress CPAU shall demonstrate that it is making reasonable progress towards ensuring that it shall meet its compliance period targets during intervening years per PUC §§ 399.30(c)(2). C. OPTIONAL COMPLIANCE MEASURES As permitted by Section 3206(a) of the CEC’s RPS Regulations, the City Council hereby adopts rules permitting the use of each of the following five optional compliance measures included in the CEC’s RPS Regulations: Excess Procurement, Delay of Timely Compliance, Cost Limitations, Portfolio Balance Requirement Reduction, and Historic Carryover. The City Council also hereby adopts rules permitting the use of the Large Hydro Exemption as described in PUC § 399.30(l). 1. Excess Procurement (PUC §399.13(a)(4)(B)) a. Adoption of Excess Procurement Rules The City Council has elected to adopt rules permitting CPAU to apply excess procurement in one compliance period to a subsequent compliance period, as described in Section 3206(a)(1) of the CEC’s RPS Regulations. b. Limitations on CPAU’s Use of Excess Procurement CPAU shall be allowed to apply Excess Procurement from one compliance period to subsequent compliance periods as long as the following conditions are met: 1. Excess Procurement shall only include generation from January 1, 2011 or later. 2. In calculating the quantity of Excess Procurement, CPAU shall deduct from actual procurement quantities, the total amount of procurement associated with contracts of less than ten (10) years in duration. Section XI: Appendices XI—8 3. Eligible resources must be from Content Category 1 or Content Category 2 or Grandfathered Resources to be Excess Procurement. Resources from Content Category 3 will not count towards Excess Procurement. c. Excess Procurement Calculation CPAU shall calculate its Excess Procurement according to formulae in section 3206 (a)(1)(D) of the CEC’s RPS Regulations. d. City Council Review CPAU’s use of the Excess Procurement to apply towards CPAU’s RPS procurement target in any compliance period will be reviewed by the City Council during its annual review as per section D.3 of this RPS Procurement Plan. 2. Delay of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5)) a. Adoption of Delay of Timely Compliance Rules The City Council has elected to adopt rules permitting it to make a finding that conditions beyond CPAU’s control exist to delay timely compliance with RPS procurement requirements, as described in Section 3206(a)(2) of the CEC’s RPS Regulations. b. Delay of Timely Compliance Findings The City Council may make a finding, based on sufficient evidence presented by CPAU staff, and as described in this Section C.2, that is limited to one or more of the following causes of delay, and shall demonstrate that CPAU would have met its RPS procurement requirements but for the cause of the delay: (1) Inadequate Transmission i. There is inadequate transmission capacity to allow for sufficient electricity to be delivered from CPAU’s proposed eligible renewable energy resource projects using the current operational protocols of the California Independent System Operator’s Balancing Authority Area. ii. If the City Council’s delay finding rests on circumstances related to CPAU’s transmission resources or transmission rights, the City Council may find that: a.) CPAU has undertaken, in a timely fashion, reasonable measures under its control and consistent with its obligations under local, state, and federal laws and regulations, to develop and construct new transmission lines or upgrades to existing lines intended to transmit Section XI: Appendices XI—9 electricity generated by eligible renewable energy resources, in light of its expectation for cost recovery. b.) CPAU has taken all reasonable operational measures to maximize cost-effective purchases of electricity from eligible renewable energy resources in advance of transmission availability. (2) Permitting, interconnection, or other factors that delayed procurement or insufficient supply. i. Permitting, interconnection, or other circumstances have delayed procured eligible renewable energy resource projects, or there is an insufficient supply of eligible renewable energy resources available to CPAU. ii. In making its findings relative to the existence of this condition, the City Council’s deliberations shall include, but not be limited to the following: a) Whether CPAU prudently managed portfolio risks, including, but not limited to, holding solicitations for RPS-eligible resources with outreach to market participants and relying on a sufficient number of viable projects; b) Whether CPAU sought to develop its own eligible renewable energy resources, transmission to interconnect to eligible renewable energy resources, or energy storage used to integrate eligible renewable energy resources. c) Whether CPAU procured an appropriate minimum margin of procurement above the minimum procurement level necessary to comply with the renewables portfolio standard to compensate for foreseeable delays or insufficient supply; d) Whether CPAU has taken reasonable measures, under its control to procure cost-effective distributed generation and allowable unbundled renewable energy credits; (3) Unanticipated curtailment to address needs of the balancing authority. c. Procedures upon Approving Waiver: In the event of a Waiver of Timely Compliance due to any of the factors set forth above, CPAU shall implement the following procedures: (1) Establish additional reporting for intervening years to demonstrate that reasonable actions under the CPAU’s control are being taken (§399.15(b)(6)). Section XI: Appendices XI—10 (2) Require a demonstration that all reasonable actions within the CPAU’s control have been taken to ensure compliance in order to grant the waiver (§ 399.15(b)(7)). 3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c)) a. Cost Limitations for Expenditures The City Council has elected to adopt rules for cost limitations on the procurement expenditures used to comply with CPAU’s procurement requirements, as described in Section 3206(a)(3) of the CEC’s RPS Regulations. These cost limitation rules are intended to be consistent with PUC §399.15(c). b. Considerations in Development of Cost Limitation Rules In adopting cost limitation rules, the City Council has relied on the following: 1) This Procurement Plan; 2) Procurement expenditures that approximate the expected cost of building, owning, and operating eligible renewable energy resources; 3) The potential that some planned resource additions may be delayed or canceled; and 4) Local and regional economic conditions and the ability of CPAU’s customers to afford produced or procured energy products. These economic conditions may include but are not limited to unemployment, wages, cost of living expenses, the housing market, and cost burden of other utility rates on the same customers. The City Council may also consider cost disparities between customer classes within Palo Alto, and between Palo Alto customers and other Publicly Owned Utility and Investor Owned Utility customers in the region. c. Cost Limitations The City of Palo Alto’s current RPS policy requires that CPAU pursue a target level of renewable purchases of 33% while “[e]nsuring that the retail rate impact for renewable purchases does not exceed 0.5 ¢/kWh on average,” i.e., the cumulative incremental cost of all renewable resources over and above the estimated cost of an equivalent volume and shape of alternative non-RPS resources shall not cause a retail rate impact in excess of 0.5 ¢/kWh on average. This limit was first established by the City Council in October 2002 based on public input, and the goal of balancing resource reliability and cost considerations in the consideration of investment in renewable and energy efficiency resources. Section XI: Appendices XI—11 d. Actions to be Taken if Costs Exceed Adopted Cost Limitation If costs are anticipated to exceed the cost limitations set by the City Council, staff will present proposals to the City of Palo Alto’s Utilities Advisory Commission to either reduce the RPS requirements or increase the cost limitation. Staff and the Commission’s recommendations will then be taken to the City Council for action. 4. Portfolio Balance Requirement Reduction (PUC § 399.16(e)) a. Adoption of Portfolio Balance Requirement Reduction Rules The City Council has elected to adopt rules that allow for the reduction of the portfolio balance requirement for PCC 1 for a specific compliance period, consistent with PUC §399.16(e), as described in Section 3206(a)(4) of the CEC’s RPS Regulations. b. Portfolio Balance Requirement Reduction Rules CPAU may reduce the portfolio balance requirement for PCC1 for a specific compliance period, consistent with PUC §399.16 (e) and the following: 1. The need to reduce the portfolio balance requirements for PCC 1 must have resulted because of conditions beyond CPAU’s control, as provided in Section 3206(a)(2) of the CEC’s RPS Regulations. 2. CPAU may not reduce its portfolio balance requirement for PCC 1 below 65 percent for any compliance period after December 31, 2016. 3. Any reduction in portfolio balance requirements for PCC 1 must be adopted at a publicly noticed meeting, providing at least 10 calendar days’ notice to the CEC, and include an updated renewable energy resources procurement plan detailing the portfolio balance requirement changes. 5. Historic Carryover a. Adoption of Historic Carryover Rules The City Council has elected to adopt rules to permit its use of Historic Carryover, as defined in Section 3206(a)(5) of the RPS Regulations, to meet its RPS procurement targets. Current calculations indicate that CPAU has Historic Carryover due to CPAU’s early investment in renewable energy resources. Section XI: Appendices XI—12 b. Historic Carryover Procurement Criteria CPAU’s use of Historic Carryover is subject to section 3206 (a)(5) of the CEC’s RPS Regulations, including the following: 1) Procurement generated before January 1, 2011 may be applied to CPAU’s RPS procurement target for the compliance period ending December 31, 2013, or for any subsequent compliance period; and 2) The procurement must also meet the criteria of Section 3202 (a)(2) of the CEC’s RPS Regulations; and 3) The procurement must be in excess of the sum of the 2004-2010 annual procurement targets defined in Section 3206(a)(5)(D) of the CEC’s RPS Regulations; and 4) The procurement cannot have been applied to the RPS of another state or to a voluntary claim. 5) The Historic Carryover must be procured pursuant to a contract or ownership agreement executed before June 1, 2010. 6) Both the Historic Carryover and the procurement applied to CPAU’s annual procurement targets must be from eligible renewable energy resources that were RPS-eligible under the rules in place for retail sellers at the time of execution of the contract or ownership agreement, except that the generation from such resources need not be tracked in the Western Renewable Energy Generation Information System. c. Historic Carryover Formula CPAU will calculate its Historic Carryover according to formulae in section 3206 (a)(5)C) and (D) of the CEC’s RPS Regulations. d. Historic Carryover Claims The number of RECs qualifying for Historic Carryover is dependent upon the acceptance by the CEC of CPAU’s applicable procurement claims for January 1, 2004 – December 31, 2010, which are due to the CEC within 90 calendar days after the effective date of the CEC’s RPS Regulations (October 30, 2013). The Historic Carryover submittal shall also include baseline calculations, annual procurement target calculations, and any other pertinent data. e. Council Review CPAU’s use of the Historic Carryover to apply towards CPAU’s RPS procurement target in any compliance period will be reviewed by the City Council during its annual review as per section D.3 of this RPS Procurement Plan. Section XI: Appendices XI—13 6. Large Hydro Exemption (PUC § 399.30(l)) a. Adoption of Large Hydro Exemption Rules The City Council has elected to adopt rules permitting CPAU to reduce its annual RPS procurement requirements, as described in PUC §399.30(l). b. Limitations on CPAU’s Use of the Large Hydro Exemption CPAU shall be allowed to invoke the Large Hydro Exemption as long as the following conditions are met: 1. During a year with in a compliance period, CPAU shall have received greater than 50% of its retail sales from large hydroelectric generation, which is defined as electricity generated from a hydroelectric facility that is not an eligible renewable energy resource. 2. The large hydroelectric generation is produced at a facility owned by the federal government as a part of the federal Central Valley Project or a joint powers agency. 3. Only large hydroelectric generation that is procured under an existing agreement effective as of January 1, 2015, or an extension or renewal of that agreement, shall counted in the determination that CPAU has received more than 50 percent of its retail sales from large hydroelectric generation in any year. c. Large Hydro Exemption Calculation CPAU’s annual RPS procurement target for a year in which the Large Hydro Exemption is invoked shall equal the lesser of (a) the portion of CPAU’s retail sales unsatisfied by its large hydroelectric generation or (b) the annual RPS procurement soft target for that year, as listed in section B.2 of this RPS Procurement Plan. CPAU’s RPS procurement requirement for the compliance period that includes said year shall be adjusted to reflect any reduction in CPAU’s annual RPS procurement target pursuant to this section. d. City Council Review CPAU’s use of the Large Hydro Exemption to reduce its annual RPS procurement target in any compliance period will be reviewed by the City Council during its annual review as per section D.3 of this RPS Procurement Plan. Section XI: Appendices XI—14 D. ADDITIONAL PLAN COMPONENTS 1. Exclusive Control (PUC § 399.30(n)) In all matters regarding compliance with the RPS Procurement Plan, CPAU shall retain exclusive control and discretion over the following: a. The mix of eligible renewable energy resources procured by CPAU and those additional generation resources procured by CPAU for purposes of ensuring resource adequacy and reliability. b. The reasonable costs incurred by CPAU for eligible renewable energy resources owned by it. 2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f)) a. Deliberations on Procurement Plan (§399.30(f)): (1) Public Notice: Annually, CPAU shall post notice of meetings if the CPA Council will deliberate in public regarding this RPS Procurement Plan. (2) Notice to the California Energy Commission (CEC): Contemporaneous with the posting of a notice for such a meeting, CPAU shall notify the CEC of the date, time and location of the meeting in order to enable the CEC to post the information on its Internet website. (3) Documents and Materials Related to Procurement Status and Plans: When CPAU provides information to the CPA Council related to its renewable energy resources procurement status and future plans, for the City Council’s consideration at a noticed public meeting, CPAU shall make that information available to the public and shall provide the CEC with an electronic copy of the documents for posting on the CEC’s website. b. Compliance Reporting (Section 3207 of the CEC RPS Regulations) (1) CPAU shall submit an annual report to the CEC by July 1. The annual reports shall include the information specified in Section 3207(c) of the CEC RPS Regulations. (2) By July 1, 2021; July 1, 2025; July 1, 2028; July 1, 2031; and by July 1 of each year thereafter, CPAU shall submit to the CEC a compliance report that addresses the annual reporting requirements of the previous section, and information for the preceding compliance period as specified in Section 3207(d) of the CEC RPS Regulations. Section XI: Appendices XI—15 3. Annual Review CPAU’s RPS Procurement Plan shall be reviewed annually by the City Council in accordance with CPAU’s RPS Enforcement Program. 4. Plan Modifications/Amendments This RPS Procurement Plan may be modified or amended by an affirmative vote of the City Council during a public meeting. Any City Council action to modify or amend the plan must be publicly noticed in accordance with Section D.2.a. Effective Date: This plan shall be effective on _______________, 2018. APPROVED AND ADOPTED this _________ day of __________________, 2018. Section XI: Appendices XI—16 RPS Enforcement Program CITY OF PALO ALTO’s RENEWABLE PORTFOLIO STANDARD ENFORCEMENT PROGRAM Version 2 December 2018 REVISION HISTORY Version Date Resolution Description 2 12/3/18 Updated to reflect Senate Bill 350 (2015) requirements 1 12/12/11 9215 Original version per Senate Bill X1 2 (2011) requirements Section XI: Appendices XI—17 1. The City shall have a program for the enforcement of a Renewable Portfolio Standard (RPS) program, which shall include all of the provisions set forth herein and shall be known as the City’s RPS Enforcement Program; 2. The RPS Enforcement Program shall be effective on January 1, 2012; 3. Not less than ten (10) days advance notice shall be given to the public before any meeting is held to make a substantive change to the RPS Enforcement Program; 4. Annually, the City Manager or his designee, the Utilities General Manager, shall cause to be reviewed the City’s RPS Procurement Plan to determine compliance with the RPS Enforcement Program; 5. Annual review of the RPS Procurement Plan shall include consideration of each of the following elements: A. By December 31, 2017, December 31, 2018, and December 31, 2019: 1. Ensure that the City is making reasonable progress toward meeting the December 31, 2020 compliance obligation of 33% renewable resources electricity, consistent with the RPS Procurement Plan. B. December 31, 2020 (end of Compliance Period 3), 1. Verify that that the City procured sufficient electricity products to meet the sum of 27% of its 2017, 29% of its 2018, 31% of its 2019, and 33% of its 2020 retail sales with eligible renewable resources from the specified Content Categories, consistent with the RPS Procurement Plan; C. By December 31, 2021, December 31, 2022, and December 31, 2023: 1. Ensure that the City is making reasonable progress toward meeting the December 31, 2024 compliance obligation of 40% renewable resources electricity, consistent with the RPS Procurement Plan. D. December 31, 2024 (end of Compliance Period 4), 1. Verify that that the City procured sufficient electricity products to meet the sum of 34.75% of its 2021, 36.5% of its 2022, 38.25% of its 2023, and 40% of its 2024 retail sales with eligible renewable resources from the specified Content Categories, consistent with the RPS Procurement Plan; Section XI: Appendices XI—18 E. By December 31, 2025 and December 31, 2026: 1. Ensure that the City is making reasonable progress toward meeting the December 31, 2027 compliance obligation of 45% renewable resources electricity, consistent with the RPS Procurement Plan. F. December 31, 2027 (end of Compliance Period 5), 1. Verify that that the City procured sufficient electricity products to meet the sum of 41.67% of its 2025, 43.33% of its 2026, and 45% of its 2027 retail sales with eligible renewable resources from the specified Content Categories, consistent with the RPS Procurement Plan; G. By December 31, 2028 and December 31, 2029: 1. Ensure that the City is making reasonable progress toward meeting the December 31, 2030 compliance obligation of 50% renewable resources electricity, consistent with the RPS Procurement Plan. H. December 31, 2030 (end of Compliance Period 6), 1. Verify that that the City procured sufficient electricity products to meet the sum of 46.67% of its 2028, 48.33% of its 2029, and 50% of its 2030 retail sales with eligible renewable resources from the specified Content Categories, consistent with the RPS Procurement Plan; I. December 31, 2031 and annually thereafter, 1. Verify that that the City procured sufficient electricity products to meet 50% of its retail sales with eligible renewable resources from the specified Content Categories, consistent with the RPS Procurement Plan; J. If targets in any compliance period are not met, the City must: 1. Review the applicability of applying Excess Procurement from a previous Compliance Period or Historic Carryover consistent with the provisions of the RPS Procurement Plan; 2. Ensure that any Waiver of Timely Compliance was compliant with the provisions in the RPS Procurement Plan; 3. Ensure that any Portfolio Balance Requirement Reduction was compliant with the provisions in the RPS Procurement Plan; and 4. Review applicability and appropriateness of excusing performance based on the Cost Limitations on Expenditures or the Large Hydro Exemption provisions of the RPS Procurement Plan. Section XI: Appendices XI—19 6. If it is determined that the City has failed to comply with the provisions of its RPS Procurement Plan, the City Council shall take steps to correct any untimely compliance, including requiring the City Manager or his designee, the Utilities General Manager to: A. review the City’s RPS Procurement Plan to determine what changes, if any, are necessary to ensure compliance in the next Compliance Period; B. report quarterly to the City Council regarding the progress being made toward meeting the compliance obligation for the next Compliance Period; and C. report to the City Council regarding the status of meeting subsequent compliance targets, and all steps being taken to ensure that the obligation is timely met. Section XI: Appendices XI—20 Standardized IRP Tables Capacity Resource Adequacy Table (CRAT) St a t e o f C a l i f o r n i a Ca l i f o r n i a E n e r g y C o m m i s s i o n St a n d a r d i z e d R e p o r t i n g T a b l e s f o r P u b l i c O w n e d U t i l i t y I R P F i l i n g C a p a c i t y R e s o u r c e A c c o u n t i n g T a b l e Fo r m C E C 1 0 9 ( M a y 2 0 1 7 ) Sc e n a r i o N a m e : E x p e c t e d Ye l l o w f i l l r e l a t e s t o a n a p p l i c a t i o n f o r c o n f i d e n t i a l i t y . Un i t s = M W Da t a i n p u t b y U s e r a r e i n d a r k g r e e n f o n t . PE A K L O A D C A L C U L A T I O N S 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 1 Fo r e c a s t T o t a l P e a k - H o u r 1 - i n - 2 D e m a n d 18 5 15 5 16 6 16 5 16 4 16 3 16 2 16 1 16 0 15 8 15 6 15 5 15 3 15 1 2 [ C u s t o m e r - s i d e s o l a r : n a m e p l a t e c a p a c i t y ] 15 17 19 21 22 24 25 27 29 32 34 37 41 44 2a [ C u s t o m e r - s i d e s o l a r : p e a k h o u r o u t p u t ] 12 14 15 16 17 18 20 21 23 25 27 29 32 34 3 [ P e a k l o a d r e d u c t i o n d u e t o t h e r m a l e n e r g y s t o r a g e ] 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4 [ L i g h t D u t y P E V c o n s u m p t i o n i n p e a k h o u r ] 1 1 1 2 2 3 4 5 6 7 8 9 10 11 5 Ad d i t i o n a l A c h i e v a b l e E n e r g y E f f i c i e n c y S a v i n g s o n P e a k 0 0 0 0 0 0 0 0 0 0 0 0 6 De m a n d R e s p o n s e / I n t e r r u p t i b l e P r o g r a m s o n P e a k 0 0 0 0 1 2 2 3 4 5 6 7 7 Ma n a g e d P e a k D e m a n d ( 1 - 5 - 6 ) 18 5 15 5 16 6 16 5 16 4 16 3 16 1 16 0 15 8 15 5 15 2 15 0 14 7 14 4 8 Pl a n n i n g R e s e r v e M a r g i n 15 % 25 25 25 25 24 24 24 23 23 22 22 22 9 Fir m S a l e s O b l i g a t i o n s 10 To t a l P e a k P r o c u r e m e n t R e q u i r e m e n t ( 7 + 8 + 9 ) 18 5 15 5 19 0 19 0 18 9 18 8 18 6 18 4 18 2 17 9 17 5 17 2 16 9 16 6 EX I S T I N G A N D P L A N N E D C A P A C I T Y S U P P L Y R E S O U R C E S Ut i l i t y - O w n e d G e n e r a t i o n a n d S t o r a g e ( n o t R P S - e l i g i b l e ) : [l i s t r e s o u r c e b y n a m e ] Fu e l 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 11 a Co l l i e r v i l l e Hy d r o e l e c t r i c 57 57 57 57 57 57 57 57 57 57 57 57 11 g Lo n g - T e r m C o n t r a c t s ( n o t R P S - e l i g i b l e ) : [l i s t c o n t r a c t s b y n a m e ] Fu e l 11 h We s t e r n B a s e R e s o u r c e G e n e r a t i o n Hy d r o e l e c t r i c 19 1 18 3 17 5 17 5 17 5 17 5 17 5 17 5 17 5 17 5 17 5 17 5 11 To t a l p e a k d e p e n d a b l e c a p a c i t y o f e x i s t i n g a n d p l a n n e d s u p p l y r e s o u r c e s (n o t R P S - e l i g i b l e ) ( s u m o f 1 1 a … 1 1 n ) 0 0 24 7 24 0 23 2 23 2 23 2 23 2 23 2 23 2 23 2 23 2 23 2 23 2 Ut i l i t y - O w n e d R P S - e l i g i b l e R e s o u r c e s : [l i s t r e s o u r c e b y p l a n t o r u n i t ] Fu e l 12 a Ne w S p i c e r H y d r o e l e c t r i c Hy d r o e l e c t r i c 1 1 1 1 1 1 1 1 1 1 1 1 1 1 12 n Lo n g - T e r m C o n t r a c t s ( R P S - e l i g i b l e ) : [l i s t c o n t r a c t s b y n a m e ] Fu e l 12 o PR O J E C T # 1 - H I G H W I N D S Win d 10 10 12 10 10 10 10 10 10 0 0 0 12 p PR O J E C T # 2 - S H I L O H # 1 Win d 12 12 10 0 0 0 0 0 0 0 0 0 12 q Sa n t a C r u z ( B u e n a V i s t L a n d f i l l ) La n d f i l l G a s 2 2 2 2 2 2 2 0 0 0 0 0 12 r Ox M o u n t a i n ( H a l f M o o n B a y ) La n d f i l l G a s 5 5 5 5 5 5 5 5 5 5 0 0 12 … Ke l l e r C a n y o n La n d f i l l G a s 2 2 2 2 2 2 2 2 2 2 2 0 12 … Jo h n s o n C a n y o n ( A m e r e s c o ) La n d f i l l G a s 1 1 1 1 1 1 1 1 1 1 1 1 12 … Sa n J o a q u i n ( A m e r e s c o ) La n d f i l l G a s 4 4 4 4 4 4 4 4 4 4 4 4 12 … EE K e t t l e m a n L a n d So l a r 0 0 0 0 0 0 0 0 0 0 0 0 12 … Ele v a t i o n S o l a r C So l a r 34 34 34 34 34 34 0 0 0 0 0 0 12 … We s t e r n A n t e l o p e B l u e S k y R a n c h B So l a r 17 17 17 17 17 17 17 17 17 17 17 17 12 … Fro n t i e r S o l a r So l a r 0 0 0 0 0 0 0 0 0 0 0 0 12 … Ha y w o r t h S o l a r So l a r 22 22 22 22 22 22 22 22 22 22 22 22 12 … Wil s o n a S o l a r So l a r 0 0 0 0 0 0 0 0 0 0 0 0 12 … Pa l o A l t o C L E A N P r o j e c t s So l a r 1 1 1 1 1 1 1 1 1 1 1 1 12 To t a l p e a k d e p e n d a b l e c a p a c i t y o f e x i s t i n g a n d p l a n n e d R P S - e l i g i b l e re s o u r c e s ( s u m o f 1 2 a … 1 2 n ) 1 1 29 29 29 17 17 17 17 16 16 6 1 1 13 To t a l p e a k d e p e n d a b l e c a p a c i t y o f e x i s t i n g a n d p l a n n e d s u p p l y r e s o u r c e s ( 1 1 + 1 2 ) 1 1 27 7 26 9 26 1 24 9 24 9 24 9 24 9 24 8 24 8 23 8 23 3 23 3 GE N E R I C A D D I T I O N S NO N - R P S E L I G I B L E R E S O U R C E S : [l i s t r e s o u r c e b y n a m e o r d e s c r i p t i o n ] Fu e l 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 14 a No n e 14 To t a l p e a k d e p e n d a b l e c a p a c i t y o f g e n e r i c s u p p l y r e s o u r c e s ( n o t R P S - el i g i b l e ) 0 0 0 0 0 0 0 0 0 0 0 0 RP S - E L I G I B L E R E S O U R C E S : [l i s t r e s o u r c e b y n a m e o r d e s c r i p t i o n ] Fu e l 15 a 15 To t a l p e a k d e p e n d a b l e c a p a c i t y o f g e n e r i c R P S - e l i g i b l e r e s o u r c e s 0 0 0 0 0 0 0 0 0 0 0 0 16 To t a l p e a k d e p e n d a b l e c a p a c i t y o f g e n e r i c s u p p l y r e s o u r c e s ( 1 4 + 1 5 ) 0 0 0 0 0 0 0 0 0 0 0 0 CA P A C I T Y B A L A N C E S U M M A R Y 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 17 To t a l p e a k p r o c u r e m e n t r e q u i r e m e n t ( f r o m l i n e 1 0 ) 18 5 15 5 19 0 19 0 18 9 18 8 18 6 18 4 18 2 17 9 17 5 17 2 16 9 16 6 18 To t a l p e a k d e p e n d a b l e c a p a c i t y o f e x i s t i n g a n d p l a n n e d s u p p l y r e s o u r c e s (f r o m l i n e 1 3 ) 1 1 27 7 26 9 26 1 24 9 24 9 24 9 24 9 24 8 24 8 23 8 23 3 23 3 19 Cu r r e n t c a p a c i t y s u r p l u s ( s h o r t f a l l ) (1 8 - 1 7 ) (1 8 4 ) (1 5 4 ) 86 79 72 61 64 66 68 69 73 66 64 67 20 To t a l p e a k d e p e n d a b l e c a p a c i t y o f g e n e r i c s u p p l y r e s o u r c e s ( f r o m l i n e 1 6 ) 0 0 0 0 0 0 0 0 0 0 0 0 21 Pl a n n e d c a p a c i t y s u r p l u s / s h o r t f a l l ( s h o r t f a l l s a s s u m e d t o b e m e t w i t h sh o r t - t e r m c a p a c i t y p u r c h a s e s ) ( 1 9 + 2 0 ) (1 8 4 ) (1 5 4 ) 86 79 72 61 64 66 68 69 73 66 64 67 Section XI: Appendices XI—21 Energy Balance Table (EBT) State of California California Energy Commission Standardized Reporting Tables for Public Owned Utility IRP Filing Energy Balance Table Form CEC 110 (May 2017) Scenario Name: Expected Units = MWh Yellow fill relates to an application for confidentiality. NET ENERGY FOR LOAD CALCULATIONS 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Retail sales to end-use customers 3%913,986 911,077 907,555 904,572 903,149 902,329 902,293 902,447 902,638 903,238 903,835 905,452 2 Other loads 600 27,438 27,332 27,227 27,960 27,914 27,887 27,908 27,911 27,916 27,934 27,952 28,001 3 Unmanaged net energy for load 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453 4 Managed retail sales to end-use customers No AAEE 0%913,986 913,986 913,986 911,077 907,555 904,572 903,149 902,329 902,293 902,447 902,638 903,238 903,835 905,452 5 Managed net energy for load 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453 6 Firm Sales Obligations 0 0 0 0 0 0 0 0 0 0 0 0 0 7 Total net energy for load (5+6)941,423 941,423 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453 8 [Customer-side solar generation]18,005 20,277 22,674 24,065 25,620 27,360 29,304 31,474 33,897 36,599 39,614 42,975 46,719 50,890 9 [Light Duty PEV electricity procurement requirement]7,316 9,510 11,967 14,704 17,685 20,933 24,444 28,246 32,275 36,579 41,144 46,008 51,073 56,406 10 [Other transportation electricity consumption/procurement requirement]0 0 0 0 0 0 0 0 0 0 0 0 11 [Other electrification/fuel substitution; consumption/procurement requirement]HPWH& HPSH 146 288 476 730 1,049 1,423 1,876 2,431 3,083 3,831 4,639 5,507 EXISTING AND PLANNED GENERATION RESOURCES Utility-Owned Generation Resources (not RPS-eligible): [list resource by name]2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 12a Collierville Hydroelectric 241,017 92,779 115,701 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 Long-Term Contracts (not RPS-eligible): [list contracts by name] 12h Western Base Resource Generation Is auto-updating 541,539 411,405 409,511 385,814 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289 12 Total energy from existing and planned supply resources (not RPS-eligible) (sum of 12a…12n)782,556 504,184 525,212 517,482 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 Utility-Owned RPS-eligible Generation Resources: [list resource by plant or unit] 13a New Spicer Hydroelectric Hydroelectric 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 Long-Term Contracts (RPS-eligible): [list contracts by name] 13i PROJECT #1 - HIGHWINDS Wind 48,207 42,664 42,668 42,754 42,721 42,708 42,672 42,711 42,671 42,709 42,722 12,615 0 0 13j PROJECT #2 - SHILOH #1 Wind 64,513 57,281 57,290 57,425 57,366 0 0 0 0 0 0 0 0 0 13k Santa Cruz (Buena Vist Landfill)Landfill Gas 9,853 8,961 8,961 8,986 8,961 8,961 8,961 8,985 8,961 1,449 0 0 0 0 13l Ox Mountain (Half Moon Bay)Landfill Gas 43,880 42,459 42,459 42,575 42,459 42,459 42,459 42,570 42,459 42,459 42,459 42,575 13,959 0 13m Keller Canyon Landfill Gas 14,894 13,827 13,827 13,865 13,827 13,827 13,827 13,863 13,827 13,827 13,827 13,865 9,205 0 13n Johnson Canyon (Ameresco)Landfill Gas 10,433 9,200 9,200 9,225 9,200 9,200 9,200 9,224 9,200 9,200 9,200 9,225 9,200 9,200 13…San Joaquin (Ameresco)Landfill Gas 30,283 27,468 27,468 27,544 27,468 27,468 27,468 27,540 27,468 27,468 27,468 27,544 27,468 27,468 13…EE Kettleman Land Solar 53,056 52,791 52,527 52,264 52,003 51,743 51,484 51,227 50,971 50,716 50,462 50,210 49,959 49,709 13…Elevation Solar C Solar 100,695 100,191 99,690 99,192 98,696 98,203 97,712 97,223 96,737 96,253 95,772 95,293 94,817 94,343 13…Western Antelope Blue Sky Ranch B Solar 50,367 50,115 49,864 49,615 49,367 49,120 48,874 48,630 48,387 48,145 47,904 47,665 47,426 47,189 13…Frontier Solar Solar 52,338 52,077 51,816 51,557 51,299 51,043 50,788 50,534 50,281 50,030 49,780 49,531 49,283 49,037 13…Hayworth Solar Solar 63,402 63,085 62,770 62,456 62,144 61,833 61,524 61,216 60,910 60,606 60,302 60,001 59,701 59,402 13…Wilsona Solar Solar 0 0 0 0 45,136 74,774 74,400 74,028 73,658 73,290 72,924 72,559 72,196 71,835 13…Palo Alto CLEAN Projects Solar 2,062 2,052 2,042 2,031 2,021 2,011 2,001 1,991 1,981 1,971 1,961 1,951 1,942 1,932 13…Small Part of Western Area Power Association Hydroelectric 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 13 Total energy from RPS-eligible resources (sum of 13a…13n, and 13z)553,984 532,171 530,582 529,489 572,668 543,350 541,370 539,743 537,511 528,123 524,782 493,034 445,156 420,115 13z Undelivered RPS energy 279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885 14 Total energy from existing and planned supply resources (12+13)1,336,540 1,036,355 1,055,794 1,046,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073 GENERIC ADDITIONS NON-RPS ELIGIBLE RESOURCES: [list resource by name or description]2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 15a 15 Total energy from generic supply resources (not RPS-eligible)0 0 0 0 0 0 0 0 0 0 0 0 RPS-ELIGIBLE RESOURCES: [list resource by name or description] 16a 16e 16 Total energy from generic RPS-eligible resources 0 0 0 0 0 0 0 0 0 0 0 0 17 Total energy from generic supply resources (15+16)0 0 0 0 0 0 0 0 0 0 0 0 17z Total energy from RPS-eligible short-term contracts ENERGY FROM SHORT-TERM PURCHASES 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 18 Short term and spot market purchases:81,940 79,524 154,110 182,370 160,888 170,642 172,094 173,495 177,953 184,029 188,028 207,719 239,323 258,553 ENERGY BALANCE SUMMARY 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 19 Total energy from supply resources (14+17+17z)1,336,540 1,036,355 1,055,794 1,046,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073 19a Undelivered RPS energy (from 13z)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885 20 Short term and spot market purchases (from 18)81,940 79,524 154,110 182,370 160,888 170,642 172,094 173,495 177,953 184,029 188,028 207,719 239,323 258,553 21 Total delivered energy (19-19a+20)1,138,833 935,349 923,253 949,255 945,624 942,548 941,081 940,236 947,485 947,643 947,840 948,459 949,074 950,741 22 Total net energy for load (from 7)941,423 941,423 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453 23 Surplus/Shortfall (21-22)197,409 (6,075)(18,170)10,845 10,842 10,016 10,018 10,020 17,284 17,286 17,287 17,287 17,287 17,288 Historical Data Section XI: Appendices XI—22 GHG Emissions Accounting Table (GEAT) State of California California Energy Commission Standardized Reporting Tables for Public Owned Utility IRP Filing GHG Emissions Accounting Table Form CEC 111 (May 2017) Scenario Name: Expected Yellow fill relates to an application for confidentiality. Emissions Intensity Units = mt CO2e/MWhGHG EMISSIONS FROM EXISTING AND PLANNED SUPPLY RESOURCES Yearly Emissions Total Units = Mmt CO2e Utility-Owned Generation (not RPS-eligible): [list resource by name]Emissions Intensity 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 1a #REF!0 0 0 0 0 0 0 0 0 0 0 0 0 Long-Term Contracts (not RPS-eligible): [list contracts by name]Emissions Intensity 1h Western Base Resource Generation 0 0 0 0 0 0 0 0 0 0 0 0 0 1n 1 Total GHG emissions of existing and planned supply resources (not RPS- eligible) (sum of 1a…1n)0 0 0 0 0 0 0 0 0 0 0 0 0 0 Utility-Owned RPS-eligible Generation Resources: [list resource by plant or unit]Emissions Intensity 2a New Spicer Hydroelectric 0 0 0 0 0 0 0 0 0 0 0 0 0 Long-Term Contracts (RPS-eligible): [list contracts by name]Emissions Intensity 2h PROJECT #1 - HIGHWINDS 0 2i PROJECT #2 - SHILOH #1 0 2j Santa Cruz (Buena Vist Landfill)0 2k Ox Mountain (Half Moon Bay)0 2l Keller Canyon 0 2m Johnson Canyon (Ameresco)0 2n San Joaquin (Ameresco)0 2…EE Kettleman Land 0 2…Elevation Solar C 0 2…Western Antelope Blue Sky Ranch B 0 2…Frontier Solar 0 2…Hayworth Solar 0 2…Wilsona Solar 0 2…Palo Alto CLEAN Projects 0 2…Small Part of Western Area Power Association 0 2 Total GHG emissions from RPS-eligible resources (sum of 2a…2n)0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 Total GHG emissions from existing and planned supply resources (1+2)0 0 0 0 0 0 0 0 0 0 0 0 0 0 EMISSIONS FROM GENERIC ADDITIONS NON-RPS ELIGIBLE RESOURCES: [list resource by name or description]Emissions Intensity 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 4a 4b 4 Total GHG emissions from generic supply resources (not RPS-eligible)0 0 0 0 0 0 0 0 0 0 0 0 RPS-ELIGIBLE RESOURCES: [list resource by name or description]Emissions Intensity 5a 5b 5 Total GHG emissions from generic RPS-eligible resources 0 0 0 0 0 0 0 0 0 0 0 0 6 Total GHG emissions from generic supply resources (4+5)0 0 0 0 0 0 0 0 0 0 0 0 GHG EMISSIONS OF SHORT TERM PURCHASES Emissions Intensity 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 7 Short term and spot market purchases:0.428 35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661 TOTAL GHG EMISSIONS 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Total GHG emissions to meet net energy for load (3+6+7)35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661 EMISSIONS ADJUSTMENTS 8a Undelivered RPS energy (MWh from EBT)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885 8b Firm Sales Obligations (MWh from EBT)0 0 0 0 0 0 0 0 0 0 0 0 0 0 8c Total energy for emissions adjustment (8a+8b)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885 8d Emissions intensity (portfolio gas/short-term and spot market purchases)0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 8e Emissions adjustment (8Cx8D)119,689 77,267 122,687 119,877 121,505 114,448 114,850 115,114 112,965 111,479 111,677 106,251 99,023 95,823 PORTFOLIO GHG EMISSIONS 8f Portfolio emissions (8-8e)-84,619 -43,231 -56,728 -41,822 -52,645 -41,413 -41,193 -40,859 -36,801 -32,715 -31,201 -17,348 3,407 14,838 GHG EMISSIONS IMPACT OF TRANSPORTATION ELECTRIFICATION 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 9 GHG emissions reduction due to gasoline vehicle displacement by LD PEVs 0.02 0.03 0.04 0.04 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 10 GHG emissions increase due to LD PEV electricity loads 0 0 0 0 0 0 0 0 0 0 0 0 0 0 11 GHG emissions reduction due to fuel displacement - other transportation electrification -------------- 12 GHG emissions increase due to increased electricity loads - other transportation electrification 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Section XI: Appendices XI—23 RPS Procurement Table (RPT) Sta t e o f C a l i f o r n i a Ca l i f o r n i a E n e r g y C o m m i s s i o n Sta n d a r d i z e d R e p o r t i n g T a b l e s f o r P u b l i c O w n e d U t i l i t y I R P F i l i n g R P S P r o c u r e m e n t T a b l e Fo r m C E C 1 1 2 ( M a y 2 0 1 7 ) Be g i n n i n g b a l a n c e s Un i t s = M W h Sta r t o f 2 0 1 7 RP S E N E R G Y R E Q U I R E M E N T C A L C U L A T I O N S 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 1 (M a n a g e d ) R e t a i l s a l e s t o e n d - u s e c u s t o m e r s ( F r o m E B T ) 91 3 , 9 8 6 91 3 , 9 8 6 91 3 , 9 8 6 91 1 , 0 7 7 90 7 , 5 5 5 90 4 , 5 7 2 90 3 , 1 4 9 90 2 , 3 2 9 90 2 , 2 9 3 90 2 , 4 4 7 90 2 , 6 3 8 90 3 , 2 3 8 90 3 , 8 3 5 90 5 , 4 5 2 2 Gre e n p r i c i n g p r o g r a m / h y d r o e x c l u s i o n 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 28 , 2 0 1 3 So f t t a r g e t ( % ) 27 . 0 0 % 29 . 0 0 % 31 . 0 0 % 33 . 0 0 % 34 . 7 5 % 36 . 5 0 % 38 . 2 5 % 40 . 0 0 % 41 . 6 7 % 43 . 3 3 % 45 . 0 0 % 46 . 6 7 % 48 . 3 3 % 50 . 0 0 % 4 Re q u i r e d p r o c u r e m e n t f o r c o m p l i a n c e p e r i o d Ca t e g o r y 0 , 1 a n d 2 R E C s 5 Ex c e s s b a l a n c e / h i s t o r i c c a r r y o v e r a t b e g i n n i n g / e n d o f c o m p l i a n c e pe r i o d 62 6 , 3 7 6 75 6 , 7 4 6 0 0 43 8 , 6 2 5 0 6 RP S - e l i g i b l e e n e r g y p r o c u r e d ( c o p i e d f r o m E B T ) 55 3 , 9 8 4 53 2 , 1 7 1 53 0 , 5 8 2 52 9 , 4 8 9 57 2 , 6 6 8 54 3 , 3 5 0 54 1 , 3 7 0 53 9 , 7 4 3 53 7 , 5 1 1 52 8 , 1 2 3 52 4 , 7 8 2 49 3 , 0 3 4 44 5 , 1 5 6 42 0 , 1 1 5 6A A m o u n t o f e n e r g y a p p l i e d t o p r o c u r e m e n t o b l i g a t i o n 23 9 , 1 6 2 25 6 , 8 7 8 0 0 0 0 10 5 , 1 3 9 31 6 , 9 0 7 33 1 , 4 9 1 34 6 , 0 6 7 36 0 , 7 5 2 37 5 , 6 3 6 39 0 , 4 5 0 40 5 , 8 8 1 7 Ne t p u r c h a s e s o f C a t e g o r y 0 , 1 a n d 2 R E C s 0 0 (5 3 0 , 5 8 2 ) (5 2 9 , 4 8 9 ) (5 7 2 , 6 6 8 ) (5 4 3 , 3 5 0 ) (4 3 6 , 2 3 1 ) (2 2 2 , 8 3 6 ) (2 0 6 , 0 2 0 ) (1 8 2 , 0 5 6 ) (1 6 4 , 0 2 9 ) (1 1 7 , 3 9 8 ) (5 4 , 7 0 7 ) (1 4 , 2 3 4 ) 7A C a r r y o v e r a n d R E C p u r c h a s e s a p p l i e d t o p r o c u r e m e n t o b l i g a t i o n 0 0 31 4 , 8 2 2 14 4 , 9 2 2 27 2 , 8 3 1 28 7 , 1 3 1 19 6 , 7 8 4 0 0 0 0 0 0 0 8 Ne t c h a n g e i n b a l a n c e / c a r r y o v e r ( 6 + 7 - 6 A - 7 A ) 31 4 , 8 2 2 27 5 , 2 9 3 (3 1 4 , 8 2 2 ) (1 4 4 , 9 2 2 ) (2 7 2 , 8 3 1 ) (2 8 7 , 1 3 1 ) (1 9 6 , 7 8 4 ) 0 0 0 0 0 0 0 Ca t e g o r y 3 R E C s 9 Ex c e s s b a l a n c e / h i s t o r i c c a r r y o v e r a t b e g i n n i n g / e n d o f c o m p l i a n c e pe r i o d 0 0 0 0 0 10 Ne t p u r c h a s e s o f C a t e g o r y 3 R E C s 0 0 10 6 1 9 8 0 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 11 Ca r r y o v e r a n d R E C p u r c h a s e s a p p l i e d t o p r o c u r e m e n t o b l i g a t i o n 0 0 10 6 1 9 8 0 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 32 7 4 4 12 Ne t c h a n g e i n R E C b a l a n c e / c a r r y o v e r 0 0 0 0 0 0 0 0 0 0 0 0 0 0 13 To t a l g e n e r a t i o n p l u s R E C s ( a l l C a t e g o r i e s ) a p p l i e d t o p r o c u r e m e n t re q u i r e m e n t ( 6 A + 7 A + 1 1 ) 14 Ov e r / u n d e r p r o c u r e m e n t f o r c o m p l i a n c e p e r i o d ( 1 1 - 4 ) 1,2 7 0 , 1 9 9 0 Co m p l i a n c e P e r i o d 3 Co m p l i a n c e P e r i o d 4 Co m p l i a n c e P e r i o d 5 Co m p l i a n c e P e r i o d 6 1,0 6 1 , 9 8 2 1,0 6 1 , 9 8 2 1,3 0 9 , 7 7 0 1,1 3 6 , 5 4 1 1,2 7 0 , 1 9 9 - 1,3 0 9 , 7 7 0 - 1,1 3 6 , 5 4 2 1 6055046 Electric Integrated Resource Plan (EIRP) Objective and Strategies EIRP Objective To provide safe, reliable, environmentally sustainable and cost-effective electric resources and services to all customers. EIRP Strategies 1.Pursue an Optimal Mix of Supply-side and Demand-side Resources: When procuring to meet demand, pursue an optimal mix of resources that meets the EIRP Objective, with cost-effective energy efficiency, distributed generation, and demand-side resources as preferred resources. Consider portfolio fit and resource uncertainties when evaluating cost-effectiveness. 2.Maintain a Carbon Neutral Supply: Maintain a carbon neutral electric supply portfolio to meet the community’s greenhouse gas (GHG) emission reduction goals. 3.Actively Manage Portfolio Supply Cost Uncertainties: Structure the portfolio or add mitigations to manage short-term risks (e.g. market price risk and hydroelectric variability) and build flexibility into the portfolio to address long-term risks (e.g. resource availability, customer load profile changes, and regulatory uncertainty) through diversification of suppliers, contract terms, and resource types. 4.Manage Electric Portfolio to Ensure Lowest Possible Ratepayer Bills: Pursue resources in a least-cost, best-fit approach in an effort to ensure ratepayer bills remain as low as possible, while adhering to Council-adopted sustainability, rate, and financial objectives and guidelines. 5.Partner with External Agencies to Implement Optimization Opportunities: Engage and partner with external agencies to maximize resource value and optimize operations. 6.Maintain Flexible Supplies to Effectively Meet Changes in Customer Loads & Load Profiles: Maintain electric supply resource flexibility in anticipation of potential changes in customer loads due to distributed energy resources, efficiency, electrification, or for other reasons. 7.Ensure Reliable and Low-Cost Transmission Services: Work with the transmission system operator to receive reliable service in a least cost manner. 8.Support Local Electric Supply Resiliency: Coordinate supply portfolio planning with utility-wide efforts to support local measures and programs that enhance community electric supply resiliency. 9.Comply with State and Federal Laws and Regulations: Ensure compliance with all statutory and regulatory requirements for energy, capacity, reserves, GHG emissions, distributed energy resources, efficiency goals, resource planning, and related initiatives. ATTACHMENT C EIRP Strategies & Related New Initiatives There are a number of new initiatives and numerous on-going tasks related to implementing the EIRP Strategies. These activities are supported by about six to eight CPAU staff, both from the supply side and demand-side (or customer) programs. In addition, CPAU relies on joint action agencies and external service providers to implement programs and initiatives. Supply and customer program staff also coordinates with retail rate development, distribution system engineering, and operations staff to implement programs and investments in an integrated manner. Described below are the nine strategies and eight new initiatives that are expected to be undertaken in the next three to six years. Work tasks related to on-going activities have not been called out separately. EIRP Strategies & Related New Initiatives 1. Pursue an Optimal Mix of Supply-side and Demand-side Resources: When procuring to meet demand, pursue an optimal mix of resources that meets the EIRP Objective, with cost-effective energy efficiency, distributed generation, and demand-side resources as preferred resources. Consider portfolio fit and resource uncertainties when evaluating cost-effectiveness. a. Initiative #1: Evaluate the merits of committing to a new 30-year contract with Western starting in 2025. [Recommendation on initial commitment to the UAC in early 2020; recommendation on final commitment in early 2024.] b. Initiative #2: Evaluate the merits of rebalancing the electric supply portfolio to lower its seasonal and daily market price exposure, by more closely balancing the City’s long-term supplies with its hourly and monthly electric loads. [Initial scoping assessment report to the UAC by December 2019.] c. Initiative #3: Evaluate how to best utilize the City’s share of the California- Oregon Transmission Project (COTP), when the long-term layoff of this asset ends in 2024. [Initial assessment report to UAC by December 2019, in tandem with Initiative #2 initial scoping assessment report.] d. Continue ongoing evaluation of all cost-effective distributed energy resources (DERs), such as energy efficiency, distributed generation, energy storage, and demand response. Update forecasts of DER impacts on retail sales and load shapes for use in strategic planning, rate-making, and budget forecasting. [Initial assessment to be completed in Distributed Energy Resource (DER) and Customer Program Plan for Council approval by June 2019.] 2. Maintain a Carbon Neutral Supply: Maintain a carbon neutral electric supply portfolio to meet the community’s greenhouse gas (GHG) emission reduction goals. a. Initiative #4: In addition to ensuring 100% of City’s annual electricity energy needs are met with carbon neutral supplies (on a kWh basis), evaluate the carbon content of the electric portfolio on an hourly basis, and recommend the merits of buying carbon offsets to ensure the carbon content of the cumulative Attachment D hourly portfolio is zero on an annual basis. Also evaluate the manner in which the City communicates with customers about the carbon content of the electric portfolio. [Initial staff recommendation to the UAC by December 2019.] 3. Actively Manage Portfolio Supply Cost Uncertainties: Structure the portfolio or add mitigations to manage short-term risks (e.g. market price risk and hydroelectric variability) and build flexibility into the portfolio to address long-term risks (e.g. resource availability, customer load profile changes, and regulatory uncertainty) through diversification of suppliers, contract terms, and resource types. a. This is an on-going active management strategy; no new initiatives are planned. 4. Manage Electric Portfolio to Ensure Lowest Possible Ratepayer Bills: Pursue resources in a least-cost, best-fit approach in an effort to ensure ratepayer bills remain as low as possible, while achieving other Council-adopted sustainability, rate, and financial objectives. a. Initiative #5: Investigate the merits and economics of monetizing excess renewable energy certificates to minimize the cost of maintaining an RPS compliant and carbon neutral electricity supply portfolio. [Initial staff recommendation to the UAC by December 2019.] 5. Partner with External Agencies to Implement Optimization Opportunities: Actively engage and partner with external agencies to maximize resource value and optimize operations. a. Initiative #6: Explore greater synergistic opportunities with NCPA and other agencies – such as newly formed community choice aggregators – to lower Palo Alto’s operating costs and rebalance the supply portfolio. [Initial assessment to UAC by December 2019.] 6. Manage Supplies to Meet Changing Customer Loads and Load Profiles: Maintain electric supply resource flexibility in anticipation of potential changes in customer loads due to distributed energy resources, efficiency, electrification, or for other reasons. At the same time, use retail rates and other available tools to influence customer load changes in a manner that minimizes overall costs and achieves other Council objectives. a. Initiative #7: Implement 2018 Utilities Strategic Plan Priority 4, Strategy 4, Action 2 by undertaking a competitive assessment for the electric utility within the context of the large proliferation of customer-sited DER technologies, electrification initiatives, changing customer expectations, and potential regulatory changes. Develop contingencies to address the potential for large changes in the City’s load level or load profile. [Initial assessment to UAC in December 2020.] 7. Ensure Reliable and Low-cost Transmission Services: Work with the transmission system operator to receive reliable service in a least-cost manner. a. This is an on-going activity; no new initiatives are planned. 8. Support Local Electric Supply Resiliency: Coordinate supply portfolio planning with utility-wide efforts to support local measures and programs that enhance community electric supply resiliency. a. On-going supporting role in utility-wide efforts. 9. Comply with State and Federal Laws and Regulations: Ensure compliance with all statutory and regulatory requirements for energy, capacity, reserves, GHG emissions, distributed energy resources, efficiency goals, resource planning, and related initiatives. a. Ongoing activities in collaboration with NCPA, CMUA and other joint action agencies. Utilities Advisory Commission Minutes Approved on: Page 1 of 3 UTILITIES ADVISORY COMMISSION MEETING EXCERPTED MINUTES OF SEPTEMBER 5, 2018 REGULAR MEETING CALL TO ORDER Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 7:00 p.m. Present: Chair Danaher, Vice Chair Schwartz, Commissioners Ballantine, Forssell, Johnston, and Trumbull Absent: Commissioner Segal NEW BUSINESS ITEM 1: DISCUSSION: Discussion of the 2018 Electric Integrated Resource Plan (EIRP) and Related Documents. Jim Stack, Senior Resource Planner, reported the EIRP needs to be approved by the City Council by the end of the year and submitted to the State. In October, staff will present the full EIRP to the UAC and request the UAC recommend the City Council approve it. The EIRP objectives, strategies, and work plan will guide staff over the next few years during implementation of the EIRP. Integrated resource planning is the process used to develop a roadmap for meeting energy needs over a specific planning horizon while achieving objectives for cost, sustainability, and reliability. SB 350 revised all the requirements for the Renewable Portfolio Standard (RPS) and energy efficiency; established formal greenhouse gas reduction targets for the electric sector; and requires all larger utilities to submit a periodic EIRP to State regulators. Since June 2017, staff has presented components of the EIRP every few months to the UAC. Previously, staff performed integrated resource planning under the framework of the Long-Term Electric Acquisition Plan (LEAP), which was last updated in 2012. Since 2012, targets for greenhouse gas emission reduction, RPS, and energy efficiency have increased, and distributed generation has proliferated along with growth in energy storage markets and electric vehicles. CPAU has adopted a carbon-neutral supply plan, almost tripled its RPS level, reduced greenhouse gas emissions, initiated a feed-in tariff program, signed six new solar Power Purchase Agreements, realized major energy efficiency savings, installed electric vehicle chargers on City property, and adopted a new Strategic Plan, a Sustainability and Climate Action Plan (S/CAP), a Local Solar Plan, and an Electrification Work Plan since 2012. CPAU's supply portfolio reflects the growth of solar purchases over the past few years, which places the RPS level far ahead of State requirements. The City's greenhouse gas emissions reached zero in 2013 with adoption of the Carbon Neutral Plan. Discussion of the appropriateness of the current methodology for carbon accounting will continue over the next year. CPAU's target for greenhouse gas emissions is a range because the State has not formally adopted a methodology. Staff expects the portfolio will include supply-side resources such as efficiency and behind-the-meter solar by 2020. By 2030, the amount of landfill gas and wind in the portfolio will decrease as contracts expire. A detailed look at the load forecast between 2018 and 2030 depicts the impacts staff expects on the load from various types of Distributed Energy Resources (DER). Electric vehicles (EV) and heat pump water and space heaters are expected to add to the load while efficiency and behind- the-meter solar are expected to reduce the load by a greater amount. Over all, staff expects the load to decrease slightly from the current level. Jonathan Abendschein, Resource Management Assistant Director, clarified that the 6.6% is not a decrease from the current level but a decrease from where the utility would be in 2030. DRAFT ATTACHMENT E Utilities Advisory Commission Minutes Approved on: Page 2 of 3 Stack further stated that the overall objective for the EIRP is derived from CPAU's Mission Statement. To fulfill the objective, staff proposes nine strategies to pursue an optimal mix of supply side and demand side resources. The strategies are to maintain a carbon neutral supply; to actively manage portfolio supply cost uncertainties; to manage the portfolio to ensure the lowest possible ratepayer bills; to partner with external agencies to implement optimization opportunities; to manage supplies to meet changing customer loads and load profiles; to ensure reliable and low-cost transmission services; to support local electric supply resiliency; and to comply with all State and Federal laws and regulations. The EIRP Work Plan is organized around the nine strategies and lists a description of activities staff plans to pursue. First, staff will evaluate the merits of a new 30-year Western contract. The Western contract is the largest single resource in the portfolio in that it supplies almost 40% of CPAU's energy needs in an average year. The contract expires at the end of 2024. Western has been a good, low-cost resource; however, it is not as attractive now because of the availability of many new renewables and because of uncertainty around its output and cost. Analysis of the net value of a renewed Western contract indicates the Western contract will have the highest expected net value of all resources evaluated, except for new in-state wind resources. However, there are many large uncertainties around the expected value for Western. Staff will attempt to narrow the uncertainties and get a better sense of the actual cost and value of the resource. Staff will also focus on negotiating the Western contract language in the next year to build flexibility into the contract. Second, staff will evaluate the merits of rebalancing the supply portfolio to more closely match load with resources. From season to season, the load profile does not change significantly, but the supply profile does. This is based on the assumption that staff dispatches hydroelectric resources in order to maximize their value based on market price signals rather than matching load with supply. Hydroelectric and solar generation exacerbate the imbalance between load and supply. Other resources, particularly out- of-state wind, may be complementary to the current profile. Staff will continue to examine the issue over the coming year in coordination with analysis of the Western contract. Third, staff will evaluate how best to utilize the City's 50 megawatt (MW) share of the California Oregon Transmission Project (COTP) transmission asset starting in 2024. The COTP Project is a way to import low-cost wind resources. Staff needs a more thorough examination of all potential uses for the resource and decide the best use of the resource. Fourth, staff will evaluate various methods of accounting for the supply portfolio's carbon content and consider updating the definition of carbon neutrality. Currently, calculation of the portfolio's emissions is based on the net annual volumes of market power purchases. However, the carbon content associated with market power on the grid varies significantly over the course of a year and a single day. The State is currently undertaking three initiatives regarding the accounting methodology. Fifth, staff will evaluate the merits of monetizing excess RPS supplies and consider different approaches to achieving RPS compliance. In November 2017, the UAC indicated its preference for a focus on cost minimization by selling excess supplies and potentially swapping some high-value category 1 resources for lower-cost category 3 resources. Staff is planning to return to the UAC with some analysis of different options for pursuing that approach. SB 100, if signed by the Governor, will provide certainty on CPAU's ultimate RPS target for 2030. In response to Commissioner Forssell's query regarding SB 100's definition of clean energy, Stack understood the definition was basically renewables and large hydroelectric, but he would confirm the definition. Stack further reported that staff will explore synergistic opportunities to work with the Northern California Power Agency (NCPA) and other agencies, including transacting with them or operating joint customer programs. Lastly, staff will undertake a competitive assessment of the Electric Utility within the context of the proliferation of customer-side DER technologies and will develop contingencies to address the potential for large changes in load as a result of DER adoption. DERs have the potential to substantially alter the magnitude and shape of the load. Commissioner Johnston remarked that the slides dramatize the problem of matching resources with load and remind him that matching is a major issue. Utilities Advisory Commission Minutes Approved on: Page 3 of 3 Commissioner Ballantine questioned the projections that the load will remain flat or decrease given the electrification of homes and vehicles. It is very possible if not likely that the electric load will increase while the overall energy load decreases. Lena Perkins, Resource Planner, advised that the projections are consistent with statewide projections. The main drivers for the projections are the requirements for increasing energy efficiency and the decrease in manufacturing and industrial loads. The California Energy Commission (CEC) developed a Palo Alto-specific forecast that projects Palo Alto's load will decrease 10- 15%. Abendschein added that CPAU's load is 20% residential and 80% commercial. A large increase in the residential load does not dramatically increase the Citywide load. Commissioner Ballantine commented that an analysis of a scenario wherein all houses and all vehicles are electric would be interesting. Perkins suggested staff could run that scenario as a sensitivity case. Doubling the residential load would total only 15% of the Citywide load. Chair Danaher noted the possibility of more commuters charging their vehicles at work. Perkins advised that the trend is the opposite; approximately 80% of charging happens at home. Stack indicated staff needs to consider the possibility of significant increases as well as decreases in load, build flexibility into the portfolio, and plan for such uncertainty. In reply to Vice Chair Schwartz's query as to whether staff has considered block chain, Perkins reported staff has not considered block chain in any scenarios to date. Vice Chair Schwartz requested staff add some charts regarding coincident and non-coincident demand because everyone needs to understand those terms, as they have implications on whether the electrons they are using are truly carbon neutral. It would be useful to look at bulk storage options and other things that the utility could implement to utilize all the solar power generated in the City. A discussion of storage should include personal storage and the public safety of battery storage. Commissioner Forssell expressed interest in the new average hydroelectric year given the effects of climate change. Stack advised that staff recently updated the long-term forecast for Western, based on recent historical data, and reduced the expected level of hydroelectric by approximately 10%. The updated data is reflected in the graphs. Commissioner Forssell hoped the initiative to rebalance the portfolio did not mean balancing the load just to Palo Alto, but to the wider California grid. Chair Danaher concurred with prior comments about energy storage. Energy storage will become much more cost effective. The water resource will be at risk, which affects geothermal resources as well as hydroelectric resources. Commissioners requested the next presentation include information regarding coincident and non- coincident demand; resources that could fill the voids in supply so that the cost effectiveness and value of storage can be determined; and information about the COTP transmission asset. ACTION: No action 1 of 2 TO: HONORABLE CITY COUNCIL FROM: ED SHIKADA, ASSISTANT CITY MANAGER/UTILITIES GENERAL MANAGER DATE: OCTOBER 16, 2018 SUBJECT: AGENDA ITEM 3 - UTILITIES ADVISORY COMMISSION RECOMMENDATION THAT THE FINANCE COMMITTEE RECOMMEND THAT THE CITY COUNCIL ADOPT A RESOLUTION APPROVING THE 2018 ELECTRIC INTEGRATED RESOURCE PLAN (EIRP), UPDATED RENEWABLE PORTFOLIO STANDARD PROCUREMENT PLAN AND ENFORCEMENT PROGRAM, AND RELATED DOCUMENTS This is an informational item to provide additional context for the discussion of the October 16, 2018 Finance Committee Agenda Item 3 (Utilities Advisory Commission Recommendation That the Finance Committee Recommend That the City Council Adopt a Resolution Approving the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and Related Documents). The Utilities Advisory Commission’s (UAC’s) consideration of the EIRP and related documents occurred on October 3, 2018. The summary below of the UAC’s discussion of this item, along with the attached excerpted minutes from that meeting, are provided in order to inform the Finance Committee’s review and discussion of this material and ensure that Palo Alto can satisfy the statutory requirement to approve its 2018 EIRP by January 1, 2019. COMMISSION REVIEW On October 3, 2018, the UAC reviewed and discussed the full EIRP report and its appendices and related documents. Commissioners noted their appreciation for staff’s work developing the EIRP and work plan. Commissioners also requested confirmation (which staff provided) that the EIRP lays out a series of future policy and strategic decisions that need to be made in the coming years, and that approval of the EIRP does not commit the City to any policy or strategic decisions. Commissioners made a point to note that the Western Base Resource hydroelectric contract is currently the lowest cost resource in the City’s electric supply portfolio. And Commissioners emphasized the need to be realistic in our assumptions and goals (e.g., with 3 Utilities Advisory Commission Minutes Approved on: Page 1 of 3 UTILITIES ADVISORY COMMISSION MEETING EXCERPT OF MINUTES OF OCTOBER 3, 2018 REGULAR MEETING UNFINISHED BUSINESS ITEM 1: ACTION: Utilities Advisory Commission Recommendation that the Finance Committee Recommend that the City Council Adopt a Resolution to Approve the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and Related Documents. Jonathan Abendschein, Assistant Director of Resource Management, recalled that the Commission first heard staff's presentation in September. The Commission will have opportunities to discuss major strategic initiatives in the future. Jim Stack, Senior Resource Planner, reported CPAU has been planning electric integrated resources (EIR) for many years, most recently under the framework of the Long-term Electric Acquisition Plan (LEAP), which was last updated in 2012. In 2015, SB 350 was passed and established new EIR planning requirements for large utilities like CPAU. SB 350 requires CPAU to submit an Electric Integrated Resource Plan (EIRP) to the California Energy Commission (CEC) every five years with the first one due in early 2019. SB 350 also established aggressive statewide targets related to renewables, greenhouse gas emissions, and energy efficiency. Staff is waiting for the CEC to establish regulations for the requirement to double energy efficiency levels by 2030. The CEC requires the completion of four standardized tables that will provide visibility into the actual details of supply and load forecasts to 2030. CPAU is also required to submit an updated version of its Renewable Portfolio Standards (RPS) Procurement Plan that reflects SB 350 changes to the renewables requirement. While CPAU is not required to submit an updated RPS Enforcement Program, staff updated the Enforcement Program and included it in the documentation. The EIRP details the state of the current (2018) supply portfolio, describes expectations for the 2030 portfolio, and discusses the major decisions to be made. The primary decision is whether to renew the Western Base Resource contract in 2025 for an additional 30-year period. The uncertainty around the decision is represented by the unknown carbon-neutral area of the 2025 portfolio. The EIRP does not discuss energy-efficiency program planning. In response to Vice Chair Schwartz's query regarding whether staff was recommending elimination of the Western contract, Stack explained that the EIRP highlights the Western contract as an upcoming discussion. The EIRP's default scenario is contract renewal, but alternative options are explored in the EIRP. Chair Danaher requested staff provide periodic updates on the process, contract issues, and analysis so that the Commission can be educated as the process moves forward. Stack continued with the EIRP objective, strategies, and work plan. The EIRP objective is modeled after the Electric Utility's mission statement. The seven new initiatives listed in the work plan will be undertaken over the next few years. The California-Oregon Transmission Project (COTP) will return to the City’s portfolio in 2024. Within the initiative for carbon accounting, staff is planning to address City communications with customers and the public regarding the portfolio's carbon content. CPAU could partner with external agencies such as Community Choice Aggregation (CCA) organizations. DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 3 Vice Chair Schwartz remarked that she could not imagine a partnership with a CCA that would benefit CPAU and questioned whether partnerships were specific to CCAs. Stack clarified that partnerships could include CCAs or other agencies. Staff could explore partnerships with CCAs for commodities trading or customer programs. Abendschein added that staff will look for opportunities to partner with CCAs. Stack continued with next steps of presenting the EIRP and related documents to the Finance Committee and Council for review; submitting the required documents to the CEC early in 2019; and beginning work on the new initiatives listed in the work plan. Staff will provide periodic updates to the Commission regarding progress. Commissioner Segal appreciated staff including communications to the community in the initiatives. In reply to Commissioner Johnston's inquiry regarding the meaning of fully deliverable resources, Stack stated fully deliverable is not the same as dispatchable. Fully deliverable is a term used by the California Independent System Operator (CAISO) to describe resources that can be delivered reliably to customers during periods of high demand or congestion on the grid. Other resources can be counted as energy but not as capacity towards resource adequacy requirements; whereas, fully deliverable resources can be counted as capacity. In answer to Commissioner Johnston's question regarding the percentage of current supplies designated as fully deliverable, Stack advised that all resources with the exception of two solar projects are designated as fully deliverable. Staff is working with the developer to have the two solar projects qualified as fully deliverable. Commissioner Johnston commented that the supply chart shows the average cost is 5.9¢ per kilowatt hour (kWh) across the portfolio. The only resource below the average is the Western contract. Removing the Western contract from the portfolio will have a big impact on the overall cost. The EIRP does not detail portfolio rebalancing and replacing existing resources with resources that more closely match load. Staff will work on making the Western contract more favorable while concurrently identifying resources to replace the Western contract. Stack recalled that staff analyzed portfolio rebalancing earlier in the year and discussed the analysis with the UAC in more detail than was presented in the EIRP. Staff felt the analysis was not what the CEC wanted in the EIRP and did not include it. Vice Chair Schwartz did not feel a goal of 90% adoption of electric vehicles (EV) was realistic as CPAU cannot control residents' behavior. Ed Shikada, Utilities General Manager, explained that the target came from the Sustainability and Climate Action Plan (S/CAP) and agreed to characterize it as an aspirational goal. Staff's efforts will focus on facilitating market adoption of EVs. Vice Chair Schwartz believed that the cost of incentives would be enormous. Chair Danaher noted the projection for the cost of EVs to decrease by 2025. Vice Chair Schwartz stated the goal is unrealistic even if EV costs decrease. If EV adoption is part of the plan, then staff has to include incentives or set a realistic goal. Chair Danaher clarified that the goal does not indicate whether adoption of EVs pertains to new cars or the City fleet. Charging networks are one component of a plan to incentivize EV adoption. Abendschein advised that the list of goals was taken from other City documents. When the S/CAP returns for discussion, the Commission can discuss the goal of 90% adoption of EVs. Stack added that the EIRP assumes 40% of residential customers will adopt EVs. Chair Danaher commented that 40% was the percentage of new electric and hybrid vehicles in Palo Alto. Schwartz expressed that a goal of 40% is ambitious without providing incentives. In answer to Vice Chair Schwartz's query regarding whether the power supply charts reflect actual purchases, Stack responded no, the charts reflect net purchases, not gross purchases. Vice Chair Schwartz felt the 2018 chart is misleading in that it reflects no thermal purchases. Stack advised that the carbon accounting discussion would include the question of how to accurately reflect purchases. Vice Chair Schwartz suggested the EIRP include a discussion of time-varying rates enabled by advanced metering infrastructure (AMI) because AMI can provide price signals to incentivize desired behaviors, which would justify the Finance Committee's support for investing in AMI. Stack reported a discussion of time-varying rates is included in the Distributed Energy Resources (DER) Plan. Abendschein added that the EIRP pertains Utilities Advisory Commission Minutes Approved on: Page 3 of 3 to supply. The distributed resources needed to substitute for electric supply are acknowledged in the EIRP, but the details are in the DER Plan. Vice Chair Schwartz was referring to varying rates as providing incentives for people to use less energy. A large portion of the population needs a financial reason to use electricity at specific times. In reply to Vice Chair Schwartz's inquiry regarding the percentage of the population participating in the Residential Energy Assistance Program (REAP), Abendschein answered a fairly low percentage. He could provide the exact percentage at a later time. Vice Chair Schwartz suggested CPAU offers electricity at lower rates than PG&E because 40% of PG&E customers participate in PG&E's care plan. She wanted to know the resources that could replace Western hydroelectric power. She wanted staff to explain fully and realistically the idea of carbon-neutral resources so that the City Council and the public can understand the need for investment. In response to Commissioner Forssell's suggestion that the EIRP essentially provides a strategy to answer a set of specified questions, Abendschein concurred that the EIRP is a problem statement, an acknowledgement of the strategic questions for staff to focus on in the next several years. In reply to Commissioner Forssell's question of whether the Western contract projections are placeholders for carbon- neutral energy to be determined rather than a commitment to continue the contract, Stack replied that the projections are placeholders rather than a commitment. The default scenario assumes the continuation of the Western contract. Commissioner Forssell commended staff for identifying key issues and questions and ways to think about them. Chair Danaher related that the EIRP content is meant to comply with regulatory requirements and to identify areas of future work. At some point, staff should integrate some of the issues with the Commission's calendar. Chair Danaher acknowledged Vice Chair Schwartz's point about staff tracking and reporting fossil fuel purchases. ACTION: Vice Chair Schwartz moved that the Utilities Advisory Commission (1) finds that the 2018 EIRP report is not a project as defined in Public Resources Code 21065 and, therefore, California Environmental Quality Act (CEQA) review is not required and (2) recommends that the Finance Committee recommend that the City Council adopt a Resolution to approve the 2018 Electric Integrated Resource Plan (EIRP), Updated Renewable Portfolio Standard Procurement Plan and Enforcement Program, and related documents. Commissioner Johnston seconded the motion. The motion carried 6-0 with Chair Danaher, Vice Chair Schwartz, and Commissioners Forssell, Johnston, Segal, and Trumbull voting yes, and Commissioner Ballantine absent. City of Palo Alto (ID # 9496) Finance Committee Staff Report Report Type: Action Items Meeting Date: 10/16/2018 City of Palo Alto Page 1 Summary Title: Approval of Utilities Smart Grid Assessment Title: Staff and the Utilities Advisory Commission Recommend That Finance Committee Recommend That Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure-based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers From: City Manager Lead Department: Utilities Recommendation Staff and the Utilities Advisory Commission (UAC) request that the Finance Committee recommend that the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan (Utilities Technology Plan), including the estimated timeline and resources for the implementation of an Advanced Metering Infrastructure (AMI)-based smart grid system to more effectively serve electricity, natural gas and water utility customers. Executive Summary City of Palo Alto Utilities Department (CPAU) staff, along with consultants, developed a strategic technology roadmap over a five-year horizon and identified major critical technology investments such as a replacement for the utilities customer information and billing system (CIS), deployment of AMI, and in coordination with the City’s IT department, the implementation of a new citywide enterprise resource planning system (ERP). All of these projects require significant planning, financial and staffing resources and system integration. To ensure a successful AMI deployment, the new CIS system must be stable before integrating with the AMI system. The Utilities Technology Implementation Plan sets out a coordinated implementation approach for these projects. AMI is a foundational technology that will improve customer experience and enable CPAU to operate more effectively, and is becoming a standard in the utilities industry. An AMI-based smart grid system will empower customers to more efficiently utilize utility supplies, facilitate customer adoption of distributed energy resources (DER) such as solar photovoltaics (PV) and electric vehicles (EV), and enable the timely detection of water leaks. AMI will also enable CPAU to optimize operations and improve reliability by reducing restoration time for outages. Given City of Palo Alto Page 2 the large investments required to implement an AMI system, a cost-benefit analysis was undertaken to determine financial viability of AMI, assess staffing requirements, technological dependencies, project risks, and CPAU’s operational readiness. The consultant found that the overall net-present-value (NPV) of the investment over the 18- year life of the system was close to break-even,1 considering only the costs and benefits that can be quantified. This effectively means that there will be little or no impact on utility cost to customers over the 18-year life of the project. Upon including non-quantifiable benefits such as enhanced customer experience, improved system reliability, and better distribution asset utilization, the analysis suggests that this strategic investment would be a net benefit to all utility customers, particularly for the electricity and water utility customers. The estimated capital cost related to the AMI system installation is $16 to 18 million2 with an investment life of 18 years. The evaluation also analyzed the operational impact and found that the investment will require a number of staffing changes to implement and maintain the AMI infrastructure to maximize the value of the investment. The annual operating cost of the AMI system is estimated to be $1.9 million, which would be offset by $3.3 million in benefits estimated to accrue from conservation and current staffing related savings. The result is projected to be a net monetary benefit to of $1.4 million per year on an ongoing basis. Staff conducted additional sensitivity analysis assuming both higher and lower capital investment, operating expenses/savings, and conservation savings. In an unfavorable scenario where projected savings do not materialize and costs become higher than projected, customer bills could potentially increase by 1-2% as a result of the AMI investment. In a favorable scenario where costs are lower and conservation is higher, customer bills could decrease by approximately 0.5%. The allocation of the $19 million in initial capital and staffing costs among the three utility funds is expected to be as follows: Electric Fund ($10M), Water Fund ($5.5M) and Gas Fund ($3.5M). The Electric Special Projects (ESP) is available to fund the electric portion of the investment, which eliminates the need for rate changes in the Electric Fund. The Gas and Water Funds will cover the up-front costs from reserves rates, and may consider financing options as well to minimize rate impacts. 1 See Figure 2. NPV is based on a discount rate of 3.5% over the 18-year life of the project. However, the NPV could range from negative $14.7 million to positive $7.8 million, depending on possible range of outcomes over the life of the project. The NPV value is highly sensitive to operational staffing synergies that could be achieved and customer energy/water conservation that could be spurred by the AMI investments. If such benefits are not achieved, the annual operational savings will diminish, but are still likely to be positive on an annual on-going basis. 2 This include costs to replace all utility customer electric meters, add radio modules on all existing natural gas and water meters, deploy a mesh network to communicate with the meters, integrate the AMI with CPAU’s Customer Information and Billing system (CIS), provide customers with access to hourly utility consumption patterns and enable customers to more efficiently use utility supplies. This investment will also enable CPAU to have visibility into the utility distribution system network to more optimally manage the system. It should be noted that the cost of replacing aging water and gas meters will continue under the ongoing capital improvement project for meter replacement, and is not included under the AMI budget, but efforts will be coordinated with the AMI project. City of Palo Alto Page 3 Given the analysis and findings, staff recommends proceeding with AMI investment and has included the capital costs of the new AMI system in the Electric, Gas, and Water Utility Financial Plans and the Proposed FY 2019 – FY 2023 Capital Budget. Operational costs (consultant costs and staffing requests) needed to begin work on the CIS, ERP, and AMI projects are included in the FY 2019 budget, and additional staffing to continue the project will be included in subsequent year budgets. Staffing and other operational needs in future years are forecasted in the Utilities Technology Implementation Plan and firm proposals will be submitted in future budget years. On September 5, 2018, the UAC voted 6-0 to recommend seeking Finance Committee and City Council acceptance of the Smart Grid Assessment and Utilities Technology Plan. The UAC wanted to convey to the Council that it strongly supported the implementation of the AMI project. Background In 2012, City of Palo Alto Utilities (CPAU) completed an assessment of smart grid applications based on AMI for Palo Alto. The study estimated the capital cost associated with AMI implementation for electric, natural gas and water utility services at $15 million to $20 million, and the cost-benefit assessments found the costs outweighed benefits over the 15 year to 20 year life of such an investment. Based on these findings, the study recommended, and City Council approved, deferring major investments in smart grid for several years until technologies mature and implementation costs decline. While deferring the investment, Council also approved a number of pilot scale smart grid projects to evaluate Palo Alto-specific applications (Staff Report 3330, 12/10/2012) at a cost of $0.45M over five years. In 2013, the Customer Connect pilot project provided electricity, natural gas and water AMI meters to 300 interested single family residential customers and provided time-of-use electric rates to interested customers, including electric vehicle owners. It also provided the capacity to monitor distribution system voltages. The pilot phase of the program ended in 2017 but staff is planning to maintain the program for current participants until full AMI deployment. A report summarizing the lessons learned and findings from the pilot was discussed with the UAC (UAC Report dated 09/06/2017). During the five year period, staff has also extensively engaged with other utilities that have deployed AMI and learned from their experiences. A CPAU staff team, with cross divisional participation, has also closely collaborated with industry experts and stakeholders to learn about the smart grid technologies and their applications in Palo Alto.3 To 3 Palo Alto is a member of Smart Electric Power Association, NCPA Smart Grid Group, Bay Area Water AMI Group, California Electric Transportation Coalition, Building Decarbonization Working group; and participates in forums hosted by EPRI, Emerging Technology Coordinating Council, CEC/EPIC forum, California Energy Storage Alliance, and regional conferences. Through CPAU’s Emerging Technology program and engagement through Stanford, staff also engages with technology vendors to find suitable opportunities for Palo Alto. City of Palo Alto Page 4 implement many of these applications, Palo Alto would need the foundational AMI system in place. Discussion In May 2017, CPAU retained Utiliworks Consulting (UWC) as consultants to re-evaluate the cost and benefits associated with AMI investments and to develop an overarching technology roadmap including an implementation plan (Staff Report 7836, 5/8/2017). The Smart Grid Assessment & Utilities Technology Plan (Attachment A) is the result of the consultant’s efforts. The consultant analysis and findings, and the foundational nature of the AMI technology is guiding staff to recommend proceeding with AMI investments. The roadmap in the plan will guide staff’s activities and proposals to Council over the next five years. Staff is asking that the Finance Committee and Council accept this report and approve its use as a high-level roadmap for AMI-related activities over the next five years, with the understanding that various parts of the plan (such as budgets, vendor contracts, and staffing actions) would require separate and additional approval by Council at the appropriate time, with modification as needed. The financial and staffing impacts are summarized in the Resource Impact section. The content of the report is summarized in the following sections: A. Components of AMI Technology and Associated Capital Investment Cost B. AMI System Operating Benefits C. AMI System Operating Cost D. Summary of Cost-Benefit Analysis & Sensitivity Analysis of AMI Investment E. Policies and Procedures to Implement and Operate AMI based Utility System F. Coordinated Implementation with Technology Projects – Technology Roadmap G. Change Management & Staffing Resource Needs H. Community and UAC Input I. AMI Project Implementation/Operating Risks and Risk Mitigation Strategies A. Components of AMI Technology and Associated Capital Investment Cost Implementation of an AMI-based smart grid system will require a number of major components. These major components and their related costs are tabulated below. The total cost of the project is estimated at $18 million to $19 million, which includes costs related to equipment and software purchases, systems integration, contract services and internal staffing requirements. Table 1 lists these cost categories. All of these costs are included in the FY 2019 Proposed Capital Budget that extends through FY 2023. Table 1: Components of AMI Investment Cost (Equipment, Services, Staffing to Implement) AMI Components Purpose Cost ($M) Electric Meters & Installation To record electricity consumption and voltage at customer premises every 15 minutes and make $5.5 City of Palo Alto Page 5 consumption information available to customers the next day.4 Radios, dials & installation to mount on existing water meters To record water meter consumption every hour and make consumption information available to customers the next day. $4.2 Radios & installation to mount on existing gas meters To record gas meter consumption every hour and make consumption information available to customers the next day. $2.3 Mesh network radios and meter head-end database Mesh radios to receive and transmit meter readings to the head-end database for storage $0.7 Meter data management System (MDMS) & Integration with billing and customer portal MDMS validates the 15-min interval consumption and voltage reads, estimates missing interval reads through a validation process, and stores the information in a database for utility billing and display on customer web portal $2.7 Conservation Voltage Reduction Program Costs associated with implementing Conservation Voltage Reduction program along electricity distribution feeders $0.4 Project management and software integration services Professional AMI project management consultants would be hired to oversee software integration/testing and coordinate the implementation of the project $0.9 TOTAL COST OF EQUIPMENT AND PROJECT IMPLEMENTATION SERVICES $16.7 Internal CPAU staffing Cost 3-4 FTE staff needed over the 2-3 year period to plan and implement the project $1.5M to $2M ESTIMATED TOTAL PROJECT COST $18M to $19M The equipment and software components of the AMI system and their interfaces with the Meter Data Management (MDM) and CIS systems are illustrated in Figure 1. 4 Real time reads could be made available to customer via the meter’s Zigbee wireless radio, if customer owns a compatible in-home-display (IHD). City of Palo Alto Page 6 Figure 1: Illustration of AMI Mesh Network, MDM System, Interface with CIS/Billing System B. AMI System Operating Benefits Electric distribution systems are transitioning away from their original purpose of delivering energy from the utility to the customer. The new distribution system is evolving into a complex network that will allow integration of widely distributed energy generation, storage, and energy management systems owned by customers. The widespread adoption of DER systems5 by electricity consumers and the increasing reliance on intermittent renewable electric supply resources to lower greenhouse gases associated with the state’s electric supply are fundamentally transforming the way electric utilities operate. These changes will require the utility to implement time-dependent electric customer rates, provide more timely and relevant information to customer about electric consumption patterns, and to gain greater visibility of the electricity flows in the distribution system for reliable utility operations. 5 DERs are defined as distributed renewable generation resources such as solar photovoltaics (PV), energy efficiency (EE), energy storage (ES), electric vehicles (EV), and demand response (DR) technologies. The emphasis on customer DER adoption from the State level is because DERs as key enabling technologies to both lower greenhouse gas emissions (GHG) and to help electric grid reliability with increased penetration of intermittent renewable energy supplies. Locally, CPAU considers energy efficiency and demand reduction as the highest priority resource and Palo Alto’s Sustainability and Climate Action Plan (S/CAP) also identified several DERs as key technologies for achieving the community’s greenhouse gas (GHG) emission reduction goals, particularly EVs, high- efficiency heat-pump water heaters (HPWH), and heat-pump space heaters (HPSH) which displace fossil fuel combustion. City of Palo Alto Page 7 In addition to meeting these needs of the electric customer and utility, an AMI system could also provide greater visibility of water and natural gas usage for customers. AMI sensors will enable faster detection and repair of water and natural gas leaks, and provide tools for CPAU and customers to implement additional customer energy efficiency and conservation initiatives. If customers opt to participate in these initiatives, the commensurate reduction in consumption will lower CPAU’s costs to purchase electricity, natural gas and water supplies. Voltage sensing on the electric distribution feeders is estimated to result in 0.5% Conservation Voltage Reduction (CVR) related energy saving. Table 2 provides an estimate of AMI-related conservation savings based on estimates of customer participation after 5 years of AMI implementation. AMI will also largely eliminate the need for manual meter reading function6. The new technology will also largely eliminate the need for manual ‘check-reads’ currently undertaken in the event the manual read is incorrectly entered into the handheld meter reading device. The total AMI related operating benefits are estimated at $3.3 million/year in year 5 after installation. 6 CPAU is engaged with meter reading staff for them to train and transition to other roles with the City in the 2022 timeline. City of Palo Alto Page 8 Table 2: Listing of AMI Related Operating Benefit Estimates ($3.3 million/year) Cost Category Key Assumptions(s)Annual Benefit (M$) Subtotal 95% reduction on staffing load $ 1.26 Subtotal 12.7% reduction on staffing load $ 0.35 Subtotal 0.5% CVR savings $ 0.47 Subtotal $ - Electric Conservation 0.5% conservation for residential customers, ramping up to 1.5% in 5 years; 0.25% for commercial customers $ 0.38 Water Conservation 1.00% conservation, ramping up to 2.5% in 5 years $ 0.55 Gas Conservation 1.00% conservation, ramping up to 2.0% in 5 years $ 0.26 Subtotal $ 1.19 Subtotal $ - Solar Meter Installation Cost Avoidance 100% reduction $ 0.02 Subtotal $ 0.02 GRAND Total $ 3.30 Asset Management Meter Reading Customer Service & Field Service Operations CVR Savings & Operations Improved Meter Accuracy Customer Conservation Savings & Avoided Purchase Cost Avoided CIP C. AMI System Operating Cost Incremental operating costs related to AMI investments are primarily related to new staffing roles needed to: a) monitor and maintain hardware/software associated with the wireless network established to read advanced meters, b) analyze and utilize the large amounts of data that will become available through the AMI system, and c) optimally operate the electric, gas and water distribution systems. These staffing and other O&M costs are estimated at $1.9 million per year, in year 5 after installation. City of Palo Alto Page 9 Table 3: Listing of AMI Related Operating Cost ($1.9 million/year) Cost Category Annual O&M Cost ($ Million) AMI Network Infrastructure, Software, and Professional Services $ 0.12 MDMS and Professional Services $ 0.23 Subtotal $ 0.34 Staffing $ 0.41 Subtotal $ 0.41 Staffing $ 0.41 Subtotal $ 0.41 Staffing $ 0.64 Subtotal $ 0.64 Staffing & Professional Services $ 0 Subtotal $ 0 GRAND Total $ 1.9 AMI Network, MDM Related Cost Electric Deployment/Maintenance Water Deployment/Maintenance Gas Deployment/Maintenance Conservation Voltage Reduction D. Summary of Cost-Benefit Analysis & Sensitivity Analysis of AMI Investment The financial analysis employs a net present value (NPV) methodology to compare the costs with monetized benefits. The NPV approach translates planned capital investments, ongoing annual operations and maintenance expenditures, and ongoing annual benefits into today’s dollars. The analysis computed the net present value (NPV) associated with the AMI investment over an 18 year period and found the investment, based on the cost and benefit assumptions shown in Tables 2 and 3 and described in more detail in the consultant’s full report, to be near break- even over the life of the project. The analysis computed present value (PV) of operating cost and operating benefits over an 18 year period, and compared it with the initial capital cost, as shown in Table 4 below. The annual incremental operating cost in Year 5 after project completion was estimated at $ 1.9 million, and the corresponding PV of this cost over 18 years was estimated at $27 million. Similarly, the annual operating benefits associated with the AMI project were estimated at $3.3 million and PV over 18 years was estimated at $43.8 million. If these assumptions prove to be accurate, the resulting PV of net operating benefit of $16.8 million is close to the capital expenditure, making this project near breakeven on a NPV basis. This result is shown in Table 4 and illustrated in Figure 2. City of Palo Alto Page 10 Table 4: Summary Cost – Benefit Assessment for AMI Investment (NPV Analysis over 18 yrs) Financial Metric Base Case Results ($Million) [A] Capital Expenditure $ (16.74) [B] Annual Operational Expense - Year 5 $ (1.90) [C] Annual CPAU/Customer Operating Benefit - Year 5 $ 3.30 [D] Present Value of Operating Expenses (over 18 years) $ (27.08) [E] Present Value of Operatng Benefits (over 18 years) $ 43.83 [F] Net Present Value (over 18 years) ([F]=[A]+[D]+[E]) $ 0.01 Figure 2: Present Value of Costs & Benefit of AMI Investment is Close to Break Even (PV over 18-years, $M) *staff cost to be shared by water and natural gas funds, but shown here as allocated to gas City of Palo Alto Page 11 The NPV result of $0.01 million is dependent on numerous estimates7 made in the analysis, particularly those related to staffing levels required to operate the AMI system, operational savings related to reduced manual meter reading process, and incremental customer energy/water efficiency and conservations savings achieved. As illustrated in the table 5 the NPV could range from an adverse $14.7 million to favorable $7.8 million over 18 years depending on whether the operational savings and efficiency estimates are achieved over multiple years. The base case estimates staffing synergies are achieved and 100% of the conservation goals (~2% reduction in utility consumption reduction over 5 years) are achieved. Table 5: Sensitivity of NPV of AMI Investment ($M over 18 years) 50%100%150% Achieved ($7.8)$0.0 $7.8 Not Achieved ($14.7)($7.0)$0.8 Conservation Goals Achieved Staffing Synergy Status Additional sensitivity analysis was undertaken to evaluate the impact of favorable and unfavorable financial outcome scenarios on the customer utility bills. Figure 3 below illustrates that switching to AMI based system could result in a range of customer bill impacts. In the event of an unfavorable outcome of where capital and operating costs exceeds estimates, coupled with lower operating cost savings and no conservation related savings, could result in a customer bills increasing by 1 to 2%. In a favorable scenario where costs are lower and conservation is higher, customer bills could decrease by approximately 0.5%. 7 This investment analysis related estimates include the following: discount rate (3.5%), life of project (18 years), operating cost increase (3%), operational savings increase (1%), customer water use conservation (2.5%), customer natural gas use conservation (2%), customer electricity use conservation (1.5% residential, 0.25% commercial), conservation voltage reduction related energy conservation (0.5%), meter reading related staffing reduction (5 to 6 FTE), AMI related staffing increase (3 to 4 FTE). These estimates were based on industry experience and Palo Alto specific situations. City of Palo Alto Page 12 Figure 3: Impact of AMI Investment on Customer Bills - Expected Outcome & Scenario Analysis Analysis also considered the viability of implementing AMI for only the electric utility because the need is greatest for electric customers. However, the analysis found that maintaining two different meter-reading systems would increase operational complexity and increase cost to all three sets of utility customers. Besides offering the potential to provide operational and conservation related financial savings, AMI is a strategic investment that is critical to meet customer expectations, enable new applications, and optimize utility operations. The following benefits were difficult to quantify and were not included in the financial model. ▪ Improved Customer Experience ▪ Improved Reliability ▪ Improved System Planning Capabilities ▪ Improved Asset Utilization ▪ Improved Water Resource Management ▪ Timely and Accurate Meter Reading ▪ New advanced retail rates ▪ Meter Right-Sizing ▪ Natural gas leak detection ▪ Unauthorized Use and Tampering Detection ▪ Improved Safety and Reduced Workman’s Compensation City of Palo Alto Page 13 ▪ Compliance with Future Legislative Requirements ▪ Potential Grants to implement AMI for water Overall, given the strategic nature of the investment, and including these intangible benefits, the analysis suggests that CPAU should plan, prepare and invest in an AMI based smart grid system. E. Policies and Procedures to Implement and Operate AMI based Utility System Implementing AMI will impact many facets of the CPAU organization and customer interactions. In addition to early stage communication and feedback from CPAU staff and customers, operational policies and procedures must be evaluated and updated with UAC and Council input. A brief description of these operational areas and the corresponding sections under the current Rules and Regulations are listed below. 1. Discontinuance, Termination and Restoration of Service (RR 09): Need to include policy and procedure to remotely disconnect for electric meters. These policy changes will coincide with business process changes and the potential for allowing same-day and after-hours disconnects/reconnects. 2. Meter Reading (RR 10): CPAU will need to revisit the billing period of 27-33 days during re-engineering of business processes. If desired, this window can be condensed with AMI reads available daily. Also, abnormal conditions and bill estimation techniques may change with AMI/MDMS systems in place. CPAU must also consider whether the “Customer Reads Own Meter” Program will continue under AMI. New rules and fees related to customers who opt-out of the AMI meter installations on their premises will also have to be developed. In the event meter reads are not available over an extended period of time due to technology malfunction or cyberattack, an alternative customer billing process will also have to be defined. 3. Billing, Adjustments, and Payment of Bills (RR 11): Language related to theft needs to be reviewed and updated to accommodate AMI. Language related to water leaks at customer premises will have to be reviewed given that AMI has the ability to alert customers and CPAU about potential water leaks. 4. Meter Installation (RR 15). Sections related to meter seals, tampering, and meter testing will also have to be reviewed and updated. Some policies may not be fully defined until AMI systems are selected and business process re- engineering are completed. These exercises will help inform which direction the policies will shift. F. Coordinated Implementation with Technology Projects – Technology Roadmap The technology road map is about CPAU’s future technological capabilities and ensures that technology investments are aligned with CPAU’s strategic plan. It sets the expectations for City of Palo Alto Page 14 deliverables, time frames for development, complexity of the system, and the level of integration required. Several large scale technology projects are expected to be implemented in the 2018-2022 period, namely CIS, ERP and AMI. Proper planning and coordinated execution is critical for the successful implementation and operation of these projects. Management focus is required to ensure projects are properly sequenced and sufficient expert resources are made available to effectively execute on projects. In addition to numerous CPAU and IT department staff involvement, the AMI project is expected to outsource meter installation, system integration and project management services to industry experts in their respective areas. The current AMI implementation timeline, developed in coordination with CIS and ERP project implementation timeline, is shown below. • Develop AMI/MDM system specification & issue RFP to select vendor Fall 2018 • AMI/MDM system vendor selection and procurement Spring 2019 • MDM system implementation and integration with CIS completion Spring 2021 • AMI meter installation completion Summer 2022 • System Testing and Going Live with AMI based billing system Fall 2022 • Leverage AMI system to enable other utility and customer programs 2023+ Table 6 provides a coordinated timeline for implementing AMI, along with the CIS and ERP systems implementation. City of Palo Alto Page 15 Table 6: Timelines for Coordinated Implementation of AMI, with CIS and ERP Systems Key: Q4-2017 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Energy Efficiency Program Optimization (EEO) (TBD) Technology Systems (Est. Capital Cost) Year 1 - 2018 Year 2 - 2019 Year 3 - 2020 OMS & AMI Integration Distribution System Optimization, CVR Customer Time-of- Use Rates Expansion New EE Programs, DR programs Utility Strategic Plan Development Re - a s s e s s m e n t P h a s e AMI/MDMS ProcurementAMI/MDMS System Spec Data Cleansing - field checks, master data clean-up CIS Stabilization Issue ERP RFP and Retain Vendor Implement New ERP HR Module Implement New ERP Finance Module Develop Technology Roadmap Note: Early selection of AMI vendor allows meter replacements to resume as planned, ahead of mass installation of AMI meters. Future Programs that are dependent on AMI Dates and $ TBD Integrate CIS to SAP & MUA Data Conversion: Create existing Customers in CIS Implement CIS + Integration with existing SAP/ERP systemCIS Design PhaseIssue CIS RFP and Retain Vendor 300 Home Customer Connect / TOU Rate Pilot Program - Maintenance Phase Full Deployment (by route/cycle) Improvement of Energy Efficiency Program Promotions based on new CIS/AMI - Planning and Pilots, on going Technology Deployment Advanced Metering Infrastructure (AMI) & Meter Data Management System (MDMS) ($17 to $19 M) Future ProjectIn Progress Alpha Phase AMI/MDMS Implementation Beta Phase AMI/MDMS Implementation Integrate MDMS to CIS, MUA, AMI Head End System (HES), OMS & GIS Enterprise Resource Planning (ERP) (UTL share $1 to $2 M) Customer Information System (CIS) ($4-5M) In Planning Flexible Billing & Payment Solution Year 5 - 2022Year 4 - 2021 ERP Design Phase Integrate new ERP with CIS Years 6+ Dependenton CIS Coordination Dependenton CIS/MUA Dependenton AMI Dependenton AMI Dependenton AMI Coordination Dependenton AMI While the mechanics of AMI implementation are well understood8, staff is particularly aware of the workload and coordination challenges related to implementing three major technology projects within five years. The timeline presented would be evaluated by the end of CY 2018 as the CIS project implementation makes progress. G. Change Management & Staffing Resource Needs Since AMI will transform many facets of utility operations and impact the customer communication channels and utility customer programs, proper planning and communication must be undertaken within the organization and with the community. AMI involves advanced applications, complex system integrations, and new business processes. It could impact 8 CPAU’s consultant UWC has served as project manager on behalf of numerous utilities which have successfully implemented AMI. CPAU staff has also gained experience through the implementation of Palo Alto’s AMI pilot project and by learning from the experience of other utilities. City of Palo Alto Page 16 numerous business processes at CPAU and will require staff to perform new tasks and develop different skill sets. Utilities will need to make adjustments to its hiring and training programs to ensure proper staffing with the right knowledge to deploy and operate the AMI network. Communicating the changes and helping staff understand the value of the new system is critical to a successful AMI deployment. During the Utilities Strategic Planning (USP) engagement process in 2017, open conversations took place among staff members and the community which identified the need for an AMI system; hence, there is a high level awareness of the importance of AMI. CPAU and Human Resources have begun the process of identifying new training programs and evaluating alternate career path options within the organization for meter reading staff whose roles may largely be eliminated if AMI is implemented. The analysis also identified the need for new staffing roles. These 3-4 new staffing roles include an AMI system technician, a data analyst, an AMI infrastructure maintenance technician, a CVR program maintenance engineer/tech, and an AMI program manager. Several of these roles are part-time roles that can be combined with other existing roles. The new roles will evolve and be defined at various stages of the project. During the 2-3 year implementation and system stabilization phase, temporary staff will be hired in the Utilities Customer Service center to temporarily backfill customer service reps that will be assisting on the project. Utilities will seek UAC and Council approval for these new positions during the annual budget process. H. Community and UAC Input During the USP development process in 2017, many community members and UAC Commissioners expressed the need for CPAU to invest in an AMI system. The 2018 USP identified the implementation of an AMI system as a key strategy under the Technology Priority to “Invest in and utilize technology to enhance customer experience and maximize operational efficiency.” Staff presented the preliminary findings of UWC analysis at the November 1, 2017 UAC meeting9. The analysis concluded that AMI investment was essential for effective utility operations in the coming decade. In addition, the UAC Commissioners voted 5-1 to proceed with planning an AMI investment. I. AMI Project Implementation/Operating Risks and Risk Mitigation Strategies AMI systems are well proven technologies. They have been operating successfully in most California-based utilities and throughout the United States for about a decade. Hence, with many vendors offering AMI system products, the operating reliability risk associated with AMI technology is relatively low. 9 The preliminary analysis in November 2017 showed a NPV of negative $7 million. The updated analysis outlined here included additional efficiency/conservation benefits and synergies related to staffing AMI operations and maintenance, resulting in the NPV being estimated at $0.01 million. Currently this is the consultant’s and staff’s best estimate, within the uncertainty band outlined. City of Palo Alto Page 17 As of this assessment, 36 risks have been identified and categorized into 8 different types: budget, community, organizational change management, resources, schedule, scope, security, and technology. Each risk is assigned a risk impact (representing the potential impact of the risk, should the risk come to fruition) and a risk probability (representing the likelihood of the risk ever occurring during the course of the project), each of which is rated as “high”, “medium”, or “low”. The combination of these two vectors generates a risk map, illustrating the priority of said risk. Outlined below are five of the top Palo Alto-specific risks, along with the associated mitigation steps: 1. Upcoming technology projects, particularly the CIS project, may compete for resources with the AMI project. Ensure adequate planning and resources so that the AMI project implementation and integration with the CIS happens well after the implementation of the CIS and after the new CIS system begins stable operations. 2. Poor staff engagement and communication, and lack of focused change management plans; external stakeholder communication will also be paramount. Communication will be made key area of focus during implementation. 3. Ill-defined vendor contracts will lead to improper level of configuration or missing integration. Consultant assistance will be sought in this area to minimize the risk. 4. Poor system integration to existing and future utility IT applications such as GIS, CIS, ERP, Asset management, OMS, etc. Organizational requirements gathering, planning and procurement management will be key to mitigate this risk. Clear vision of project milestone and key performance indicators need to be developed and accepted within organization. 5. Lack of Council approved policies and protocols to effectively respond in the new technology environment. Examples include policies covering billing disruption, remote meter turn on/off, and mitigation of impacts caused by cyber-attacks. Ensure such policies are drafted with community input for Council approval. Commission Review and Recommendation UAC reviewed and discussed the consultant report and staff recommendation over two meetings in May and September 2018. The following topics were discussed at the meeting: the financial analysis and sensitivity of the results, impact of investment on customer bills, financial and non-financial benefits to the customers, providing for customers to opt-out of the program, the use of contractors for implementation, reliability and cyber-security aspects of the AMI network, potential use of fiber for AMI back-haul communication, etc. At the September 5, 2018 meeting the Commission voted 6-0 to recommend that the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan. The UAC wanted to convey to the Council that it strongly supported the implementation of the AMI project. City of Palo Alto Page 18 The minutes of the two meetings are provided in Attachments B and C. Next Steps Upon Finance Committee consideration and recommendation, staff expects to seek approval from Council in December. Upon formal approval by Council, staff will begin a concerted effort to engage CPAU staff and the community to identify and address any lingering concerns they may have regarding such investment and resulting changes. If approved, consultants would be retained to assist with AMI system specification development and procurement (2019-20) and AMI implementation (2021-23), which would require subsequent approvals from Council. Resource Impact The costs of these investments have been included in the proposed FY 2019 Capital Budget (Project EL-11014, Smart Grid Installation). The funding and major activities for the five years are outlined below. AMI Budgets & Spending Timeline: A Pause in New Funding Needs in FY 2020 Assumed10 Fiscal Year Funding Major Activities FY 2019 $1,000,000 Consultant assisted development of AMI/MDM system specifications in preparation for an RFP, issue RFP, sign contracts with MDM and AMI vendors for delivery in 2021 and 2022, respectively. In parallel, CIS implementation is beginning. FY 2020 $0 Smart grid implementation on hold pending completion of CIS implementation. Assuming no additional funding needed in FY 2020. Water meter replacement project will be undertaken. FY 2021 $3,000,000 MDMS system and AMI head-end software delivered; begin integration with CIS in January 2021. Alpha and Beta phase of testing with AMI meters. FY 2022 $10,000,000 AMI meters delivered and mass installation begins. Complete integration with CIS. FY 2023 $5,000,000 Complete meter installation, integrated system testing, go live. TOTAL $19,000,000 10 The schedule in Table 1 is based on the Technology Roadmap and assumes most funding is needed in FY 2021, FY 2022, and FY 2023. No additional funds would be needed in FY 2020 while CIS implementation is completed. The FY 2019 Capital Budget does not reflect this updated schedule, but it will be reflected in the FY 2020 Capital Budget. City of Palo Alto Page 19 The impact of these costs on each utility for the next 5 years is shown below.11 The cost responsibility for the water and gas utilities is implemented through scheduled fund transfers to the electric fund, where the capital funds are budgeted. Capital Budget Projections for AMI Project Electric Gas Water Total FY 2019 0.53 0.18 0.29 1.00 FY 2020 0.00 0.00 0.00 0.00 FY 2021 1.59 0.54 0.87 3.00 FY 2022 5.30 1.80 2.90 10.00 FY 2023 2.65 0.90 1.45 5.00 Total 10.07 3.42 5.51 19.00 While the Electric Special Projects (ESP) reserve is available to fund the electric portion of the investment, the Gas and Water Funds will have to cover their associated costs through reserves and rate adjustments. If the natural gas and water AMI investment funds are collected from retail rates in the short term, it may result in an adverse impact on customer retail rates. An alternate arrangement of funding the cost could be through an inter-fund loan from the ESP to the water and natural gas fund, with a loan repayment including interest over time. This alternate funding mechanism will be further investigated by staff and brought forward for UAC and Council consideration if feasible. During the implementation and system stabilization phase, project management support would be provided by a consultant with experience in managing AMI project implementations. Collaboration with Northern California Power Agency (NCPA) is also under consideration. The series of major IT projects (CIS, ERP, and AMI) will require extensive staff time over the five year implementation period. At the peak of the project, nine to twelve FTE may be dedicated to the project. About half of the staff members focusing on the project will be business analysts whose full-time job is to implement IT projects. This means that any other major IT efforts aside from the ERP, CIS, and AMI systems will be deferred. Other staff focused on the project will be drawn from various Divisions of the Utilities Department, such as Customer Service, Operations, and Engineering to manage aspects of the project specific to their area of expertise. To minimize service impacts in those Divisions, some temporary staff will be brought on using the capital project budget listed above to reduce the service impacts resulting from redirecting staff who normally do not focus on IT implementation. The project may also result in increases in overtime, deferral of discretionary projects (for example, lower priority process changes or significant new rate designs might be deferred), and there may occasionally be some service impacts, such as small increases in call times or meter replacement times. Service levels will be 11 Half of the common fixed costs of the project were allocated based on meter count, and the other half of the fixed costs were allocated to the electric utility, in recognition of the electric utility being the main driver for this investment. Based on the above allocation methodology, it is recommended that the $4.4 million in common cost related to project management, network installation and MDM/CIS integration be allocated to electricity, water and gas funds on a 70%, 14%, 16% basis respectively. City of Palo Alto Page 20 monitored, and if there are significant decreases in service quality, additional temporary staffing or consultant help would be used to reduce service impacts. Post-implementation, three to four new permanent roles would be needed to operate and leverage the AMI system. This additional headcount would be off-set by the reduction in meter reader staff headcount. CPAU and Human Resources have begun the process of identifying new training programs and evaluating alternate career path options within the organization for meter reading staff whose roles may largely be eliminated with AMI implementation. Upon implementation of all three projects, the expectation is that there will be a net of one to two position reductions – though the overall staffing cost is projected to be higher due to the higher skill levels needed to manage the AMI system. Policy Implications The recommendation conforms with the 2018 Utilities Strategic Plan (USP) that has identified implementation of AMI system as a key strategy under USP Priority#2 to “Invest in and utilize technology to enhance customer experience and maximize operational efficiency.” A number of policies to implement and operate an AMI system must be considered and approved at a later time. Such policies and procedures include fees that CPAU may need to charge customers that opt not to allow the installation of advanced meters at their homes, a backup customer billing process in the event AMI meters are cannot be read remotely due to a cyber-attack or a communication network interruption, as well as ways of managing other potential AMI operating issues. Environmental Review The Finance Committee’s recommendation to Council regarding the AMI project does not meet the definition of a project under Public Resources Code 21065; therefore, the California Environmental Quality Act (CEQA) review is not required. Attachments: • Attachment A - UWC Report - City of Palo Alto Utilities Assessment - Final • Attachment B - UAC Meeting Minutes 05-02-2018 • Attachment C - UAC Meeting Minutes 09-05-2018 Smart Grid Assessment & Utilities Technology Implementation Plan January 23, 2018 FINAL DRAFT ATTACHMENT A Page 2 of 84 © 2018 UtiliWorks Consulting, LLC Table of Contents Table of Contents ................................................................................................................................................................. 2 List of Tables ......................................................................................................................................................................... 4 List of Figures ........................................................................................................................................................................ 4 Executive Summary .................................................................................................................................... 5 Introduction ............................................................................................................................................... 7 1. Purpose ......................................................................................................................................................................... 7 2. Utility Background ...................................................................................................................................................... 7 3. Scope of Work.............................................................................................................................................................. 9 Discovery Findings ..................................................................................................................................... 10 1. Goals & Objectives ................................................................................................................................................... 10 A. City of Palo Alto Utilities Strategic Plan............................................................................................................ 10 B. Departmental Visions and Strategies ....................................................................................................................... 11 C. Sustainability & Climate Action Plan (SCAP) Goals .......................................................................................... 12 D. City IT Vision .......................................................................................................................................................... 12 2. Risks and Mitigation .................................................................................................................................................. 12 3. Current State Operational Review ......................................................................................................................... 13 Utilities Technology Roadmap ................................................................................................................... 15 1. Technology Maturity at CPAU ................................................................................................................................. 15 2. IT System Gap Analysis and Planning .................................................................................................................... 16 A. Customer Information System and AMI Project Coordination ........................................................................ 16 B. Systems Integration ............................................................................................................................................... 16 C. Data Communications ........................................................................................................................................... 17 D. Enterprise Service Bus .......................................................................................................................................... 18 E. Utilities IT Team .................................................................................................................................................... 18 F. Information and Cyber Security .......................................................................................................................... 18 G. Planning for Technology Obsolescence .............................................................................................................. 20 3. Utilities Technology Roadmap ................................................................................................................................ 21 Cost-Benefit .............................................................................................................................................. 23 1. Results ........................................................................................................................................................................ 23 A. Sensitivity ............................................................................................................................................................... 25 2. Assumptions ............................................................................................................................................................... 26 3. Cost Estimate............................................................................................................................................................. 26 4. Benefits Estimate ...................................................................................................................................................... 29 5. Quantitative Benefits ............................................................................................................................................... 32 6. Qualitative Benefits.................................................................................................................................................. 33 Implementation Roadmap ........................................................................................................................ 35 1. Project Phasing – Scope & Schedule ...................................................................................................................... 35 A. AMI Proof of Concept ............................................................................................................................................ 36 B. Full Deployment ..................................................................................................................................................... 37 2. Implementation-Readiness Gap Analysis .............................................................................................................. 38 Operational Impacts .................................................................................................................................. 40 1. Personnel / Human Resources ................................................................................................................................ 40 Page 3 of 84 © 2018 UtiliWorks Consulting, LLC 2. Business Process Re-Engineering ............................................................................................................................ 42 A. Impacted Core Business Processes ...................................................................................................................... 43 B. Policy Considerations ............................................................................................................................................ 44 3. Data / Information Processing and Reporting ...................................................................................................... 45 Change Management & Communications ................................................................................................. 46 1. Change Management ................................................................................................................................................ 46 2. Communications ........................................................................................................................................................ 47 Recommendations .................................................................................................................................... 48 1. Recommendations ..................................................................................................................................................... 48 Appendices ................................................................................................................................................ 49 Appendix A – Project Risk Register .............................................................................................................................. 49 Appendix B – Current State Operations ....................................................................................................................... 60 1. Meter Reading & Field Services .............................................................................................................................. 60 2. Billing .......................................................................................................................................................................... 60 3. Customer Service ...................................................................................................................................................... 61 4. Electric Meters/Meter Shop .................................................................................................................................... 61 5. Electric Operations ................................................................................................................................................... 62 6. Water Meters/Meter Shop ....................................................................................................................................... 62 7. Water Operations/Water Conservation ................................................................................................................. 63 8. Gas Meters/Meter Shop ............................................................................................................................................ 64 9. Gas Operations .......................................................................................................................................................... 64 10. IT Support/Systems .................................................................................................................................................. 65 Appendix C – IT Considerations for AMI/MDMS Procurement ................................................................................... 67 1. Security Assessment ................................................................................................................................................. 68 2. Disaster Recovery and Continuity .......................................................................................................................... 69 Appendix D – AMI Implementation Methodology ........................................................................................................ 70 Appendix E – Utility Operational Technology ............................................................................................................. 71 1. Advanced Metering Infrastructure ......................................................................................................................... 71 A. AMI System Details ................................................................................................................................................ 71 B. Meter Interface Units ............................................................................................................................................ 75 C. Data Collection Units and Backhaul ................................................................................................................... 78 2. Meter Data Management System ............................................................................................................................ 78 3. Volt/VAR Optimization............................................................................................................................................. 79 4. Water Leak Detection and Pressure Monitoring .................................................................................................. 80 Appendix F – Glossary .................................................................................................................................................... 83 Page 4 of 84 © 2018 UtiliWorks Consulting, LLC List of Tables Table 1: Major Utilities Technology Projects Planned and Capital Cost Estimates: 2018-2022 ................................................ 6 Table 2: CPAU Divisional Objectives .................................................................................................................................................. 11 Table 3: Risk Map Matrix ...................................................................................................................................................................... 13 Table 4: Internal Factors ..................................................................................................................................................................... 15 Table 5: External Factors .................................................................................................................................................................... 16 Table 6: Estimated Major Technology Project Expenditures ......................................................................................................... 22 Table 7: Summary Base Case Results ................................................................................................................................................. 24 Table 8: NPV Sensitivity Matrix ($MM) ............................................................................................................................................... 25 Table 9: General Assumptions ............................................................................................................................................................ 26 Table 10: Project Cost Summary: Capital and Annual O&M Cost ................................................................................................. 27 Table 11: Cost Allocation by Service ($MM) ..................................................................................................................................... 28 Table 12: Annual Project Benefits Summary .................................................................................................................................... 29 Table 13: Implementation-Readiness Gap Analysis ......................................................................................................................... 39 Table 14: Palo Alto Staffing ................................................................................................................................................................ 42 Table 15: Electric Meters by Type ..................................................................................................................................................... 62 Table 16: Water Meter Types by Age ................................................................................................................................................. 63 Table 17: Gas Meter Types by Age ..................................................................................................................................................... 64 Table 18: IT/OT Systems...................................................................................................................................................................... 65 Table 19: Point-to-Multi Point vs. Mesh Network ............................................................................................................................ 75 Table 20: Glossary................................................................................................................................................................................. 83 List of Figures Figure 1: City of Palo Alto Utilities Organizational Chart ................................................................................................................ 8 Figure 2: AMI/MDMS Architecture ...................................................................................................................................................... 17 Figure 3: Cyber Security Life Cycle .................................................................................................................................................... 20 Figure 4: Utilities Technology Roadmap (Simplified) ..................................................................................................................... 22 Figure 5: Base Case AMI Cash Flow .................................................................................................................................................... 24 Figure 6: Base Case AMI Cost-Benefit ................................................................................................................................................ 25 Figure 7: Capital Outlay ....................................................................................................................................................................... 28 Figure 8: Cumulative Operating Expenses ........................................................................................................................................ 29 Figure 9: Cumulative Expenses and Benefits .................................................................................................................................... 32 Figure 10: AMI Deployment Plan ......................................................................................................................................................... 35 Figure 11: Change Management Approach ........................................................................................................................................ 46 Figure 12: Full View, Utilities Technology Roadmap ...................................................................................................................... 68 Figure 13: UtiliWorks Advantage ........................................................................................................................................................ 70 Figure 14: Sample AMI System Diagram (Point to Multipoint Network) ....................................................................................... 72 Figure 15: AMI Mesh Network Illustration ......................................................................................................................................... 74 Figure 16: Under-the-Glass AMI Electric Meter Bank ...................................................................................................................... 76 Figure 17: AMI Water Meter Pit Install .............................................................................................................................................. 76 Figure 18: Gas Meter and AMI MIU ..................................................................................................................................................... 77 Figure 19: AMI/MDMS Data Flow Diagram ......................................................................................................................................... 79 Figure 20: Illustration of VVO ............................................................................................................................................................. 80 Figure 21: Acoustic Leak Detection Technology .............................................................................................................................. 81 Figure 22: Water Burst Detection with Pressure Monitoring Technology .................................................................................... 82 Page 5 of 84 © 2018 UtiliWorks Consulting, LLC Executive Summary UtiliWorks Consulting, LLC (UWC, UtiliWorks) was engaged by the City of Palo Alto Utilities (CPAU, Utilities, City, Palo Alto) to evaluate the merits of investing in an Advanced Metering infrastructure (AMI) based smart grid system and to develop a comprehensive Utilities Technology Roadmap for a five- to ten-year horizon. AMI is a foundational technology that will enable the implementation many other customer programs to enhance customer experience, empower customers to more efficiently utilize utility supply, enable CPAU to operate more effectively and allow more advanced smart grid options to be considered. Given the large investment required to implement an AMI system, a cost-benefit analysis (CBA) was undertaken to determine financial viability and cash flow impacts on CPAU. Over a six-month period, UtiliWorks engaged with a cross-section of CPAU and IT staff to undertake discovery work around current state operations, and it reviewed several CPAU internal reports and a previous cost-benefit analysis performed in 2012. The new cost-benefit analysis presented in this report takes this information into consideration, includes flexibility to account for analysis of all three utility services, and further defines the system and business requirements for Palo Alto in line with the state of the utility industry in 2017. The analysis estimated the capital cost related to the AMI system installation and integration with the Billing System to be $16 to 18 million1. The investment is expected to have an 18-year life. The evaluation also analyzed the impact on the operational costs and found that the project will require many staff role changes and modification of organizational structure to maximize the value of the investment. The annual operating cost of the AMI system is estimated to be $1.9 million, but this increase in cost would be offset by $3.3 million in benefits, resulting in the net benefit of $1.4 million per year. Based on the assumptions employed in the analysis, the overall net-present-value (NPV) of the investment was found to be near to break-even over the 18-year life of the investment2. If one includes the non-quantifiable benefits such as improved customer experience, reliability, and better distribution asset utilization by CPAU, the strategic investment in AMI system appears to be prudent choice for Palo Alto at this time. In addition to the AMI investment, UtiliWorks also reviewed other Utilities technology projects that are in the planning phase or currently underway. It is clear from this assessment and resulting technology roadmap and implementation plan recommendations that staffing resources and budgets need to be carefully planned to successfully execute on these projects. The timelines and budget estimates for the major projects planned are outlined in Table 1: Major Utilities Technology Projects Planned and Capital Cost Estimates: 2018-2022. 1 This includes the cost to replace all utility customer electric meters, install radio modules on all natural gas and water meters, deploy a mesh network to communicate with the meters, integrate the AMI system with CPAU’s Customer Information and Billing system (CIS), provide customers with access to hourly utility consumption patterns and enable programs for customers to more efficiently use utility resources. 2 NPV is based on a discount rate of 3.5% over the 18-year life of the project. The NPV value is highly sensitive to operational staffing synergies that could be achieved, as well as customer-side energy/water conservation that could be spurred by the AMI investments. If such benefits could not be achieved, the annual operational savings would diminish but still be positive on an on- going basis. The NPV value could range from negative $15 million to positive $8 million depending on the variability of the above assumptions. Page 6 of 84 © 2018 UtiliWorks Consulting, LLC Table 1: Major Utilities Technology Projects Planned and Capital Cost Estimates: 2018-2022 Project Est. Capital Cost Timeline Completion Date Upgrade Utility Customer Information Portal $100k Underway Fall 2018 Customer Information System (CIS) System Design and Implementation $4 to $5M Vendor selection 2018; implementation 2019-20 Fall 2020 AMI system implementation $16 to $18M Vendor selection 2019; implementation 2021-22 Fall 2022 Enterprise Resource Planning System (Finance and HR) $1 to $2M3 Vendor selection 2018; implementation 2019-22 2021-22 A detailed technology project roadmap and implementation plan is provided in Section F. Also refer to Section F for a suggested implementation timeline for AMI, which accounts for operational impacts of other CPAU technology projects and staffing requirements. After identifying 36 areas of project risk, five project risks rose to the top. These five risk areas need management focus to manage them to ensure project success. These risks are: 1) ongoing or upcoming infrastructure projects that may compete for resources; 2) poor staff engagement/communication and lack of focused change management plans/implementation; 3) ill-defined contracts that lead to improper levels of configuration or missed integrations; 4) poor system integration to existing and future applications (i.e. Geographic Information System (GIS), Enterprise Resource Planning (ERP), CIS, Asset Management); and 5) lack of Council-approved policies and protocols to effectively respond in a new technology environment (e.g. billing disrupted through a cyber-attack, cyber hack that results in remote-turn off of customer meter). For each of these risks, a mitigation and response strategy has been developed. Additional risks identified and respective mitigation measures are outlined in Appendix A. In addition to the Technology Roadmap outlined in Section D and cost-benefit analysis in Section E, UtiliWorks provides several related recommendations throughout the report. These recommendations are for CPAU to consider during implementation of AMI if the City Council decides to approve the investment. 3 The full cost of the ERP system replacement project is expected to cost $4 to $5 million; cost shown is the anticipated CPAU portion of the cost. Page 7 of 84 © 2018 UtiliWorks Consulting, LLC Introduction 1. Purpose CPAU requires a well-thought-out plan prior to implementing an AMI program that provides enhanced metering functionality and supports future distribution system applications. A strategic assessment is needed to identify which platforms may be worth pursuing, how existing systems and assets can best be utilized for the long term, which technologies offer a best fit with the utility’s footprint, and how to best develop a plan going forward. Palo Alto first completed a cost-benefit analysis of an AMI system in 2012, which resulted in consensus not to proceed with the technology investment at the time due to prohibitive costs and uncertainties of AMI technology; however, the consultant who completed the study recommended that CPAU deploy an AMI pilot system and revisit the cost-benefit analysis in later years. In the years following, an Elster AMI system for electricity, natural gas and water was deployed at 300 homes in Palo Alto’s service territory. CPAU contracted with UtiliWorks Consulting, LLC in May 2017 to develop a comprehensive Utilities Technology Roadmap and conduct a thorough assessment to refine, revise, and build upon the previously completed cost-benefit analysis, adding in flexibility to account for multiple service types, while further defining the system and business requirements at Palo Alto. The analysis and timeline for the AMI deployment contained within this assessment accounts for operational impacts of other Palo Alto technology projects, staffing requirements, and project risk-mitigation measures. The goal of this assessment is to provide Palo Alto with an updated cost-benefit assessment for the AMI investment; outline the quantitative and qualitative benefits that can be realized with an AMI program; and chart out the proposed implementation roadmap, which includes the impact of other projects on the Technology Roadmap on the AMI project. If the City decides to proceed with an AMI project, this foundation will prepare Palo Alto for the subsequent Advanced Metering Infrastructure/Meter Data Management (MDM) Systems Specifications & Procurement Phase (Phase 2). 2. Utility Background The City of Palo Alto is an incorporated city with a population of more than 64,000 residents, located in Santa Clara County. Palo Alto was incorporated in 1894 and formally established via municipal charter in 1909. In 1950, the city formed a council-manager government headed by the mayor, vice mayor, and seven council members. Today, as the economic center of Silicon Valley, Palo Alto is home to many high-profile technology headquarters and start-ups, as well as parts of Stanford University, placing it among the most affluent and most highly-educated municipalities in the country. The Utilities Department provides electric, water, and gas services to the city (except for some rural, outlying areas with over 30,000 electric connections, over 20,000 water connections, and over 24,000 gas connections across nearly 26 square miles. CPAU is managed by the General Manager of Utilities, at the discretion of the City Manager. Broadly, the organization is comprised of the following divisions: Operations, Engineering, Customer Support Services, Resource Management and Administration. CPAU employs over 240 full-time equivalent staff across these divisions. A complete breakdown of Utilities by division and number of positions is illustrated in Figure 1: City of Palo Alto Utilities Organizational Chart. Page 8 of 84 © 2018 UtiliWorks Consulting, LLC Figure 1: City of Palo Alto Utilities Organizational Chart IT for the CPAU is managed by the City’s Information Technology Department, which contains shared resources and represents a source of strategic direction. Some Utilities applications have a system Page 9 of 84 © 2018 UtiliWorks Consulting, LLC owner designated from the Administration division. The current state of CPAU operations and a list of all IT applications at Palo Alto are provided in Appendix B. 3. Scope of Work Under the direction of the Professional Services Agreement executed on May 8, 2017, UtiliWorks has performed this Phase 1 assessment to baseline CPAU operations and assess readiness to successfully implement Advanced Metering Infrastructure and a Meter Data Management System. To further understand the context of an AMI (or Smart Grid) program relative to other CPAU technology projects, UtiliWorks developed a strategic Technology Roadmap and AMI implementation plan contained within this assessment report. The assessment report and associated cost-benefit analysis effectively provides CPAU management the information required to decide whether to proceed with the AMI Project. To effectively assess complex technology, UtiliWorks employs a proven delivery mechanism called the UtiliWorks Advantage™ detailed in Appendix D. Our assessment approach facilitates the identification of the business drivers motivating the effort to undertake an AMI project. It also identifies the critical success factors to support implementation and risks that could undermine success. The outcome of all Phase 1 tasks is reflected in this report and includes the following:  State of the Industry – Personalized, onsite presentation outlining the current state of the AMI industry and discussing important design considerations unique to CPAU based on technology maturity within the organization.  Discovery – Identification of the success factors, gaps, risks, and opportunities to be addressed to prepare for AMI. o Goals and objectives identification o Risk identification o Current state discovery and data collection o IT system gap analysis  Utilities Technology Roadmap – Comprehensive view of CPAU technology project initiatives, including precedence and sequencing.  Cost-Benefit – Provision of a current cost-benefit analysis underlying the AMI project, including water, gas and electric deployment.  Operational Impacts – Identification and analysis of the key operational areas/functions that will be impacted so to minimize risk during and after deployment.  AMI/MDMS Implementation Roadmap – Further detail on a proposed AMI/MDM project schedule, recommended project phasing, and staffing from Proof of Concept (POC) through full deployment and beyond.  Final Recommendations – Summarized in the report and presented to the Utility Advisory Commission and City Council as required. If the Council elects to proceed with the project, Phase 2 tasks will involve development of AMI/MDM system specifications and procurement. Page 10 of 84 © 2018 UtiliWorks Consulting, LLC Discovery Findings 1. Goals & Objectives The Palo Alto City Council, Utility Advisory Council (UAC) and CPAU have been assessing smart grid technologies since 2009. To better understand the current drivers for re-considering AMI technology in 2017, UtiliWorks evaluated the city’s project goals and objectives from several perspectives. This approach involved a review of the CPAU Strategic Plan (in progress), Sustainability & Climate Action Plan (2016), and Utilities IT Systems Review (2014). During the discovery phase of this assessment, UtiliWorks obtained direct input from key stakeholders across the CPAU organization to identify project objectives specific to the AMI program from within the Utilities organization. Key goals from the report review and stakeholder discovery are summarized here. A. City of Palo Alto Utilities Strategic Plan CPAU’s strategic planning initiative in 2017 maintains the organization’s mission statement, but developed a new statement of strategic destination and four strategic priorities for 2018 as outlined below. Mission Statement The City of Palo Alto Utilities' mission is to provide safe, reliable, environmentally sustainable and cost- effective services. Strategic Destination At CPAU, our people empower tomorrow's ambitions while caring for today's needs! We make this possible with our outstanding professional workforce, leading through collaboration and optimizing resources to ensure a sustainable and resilient Palo Alto. Strategic Priorities  We must create a vibrant and competitive environment that attracts, retains, and invests in a skilled and engaged workforce.  We must collaborate with internal teams and external stakeholders to achieve our shared objectives of enhanced communication, coordination, education and delivery of services.  We must invest in and utilize technology to enhance the customer experience and maximize operational efficiency.  We must manage our finances optimally and use resources efficiently to meet our customers’ service priorities. As outlined above, the strategic plan has identified “investments and utilization of technology to enhance the customer experience and operational efficiency” as one of four strategic priorities. In the 2014 Utility Technology Review, technology goals and drivers were identified as follows: Technology Goals and Drivers I. Enable Customer to optimally use Utility services and communicate effectively with the City II. Enable Workforce with IT tools to effectively perform on the job III. Utility Technology for operational optimization IV. Effectively manage and maintain assets for the Electric, Gas, Water, Wastewater utilities V. Effectively manage Utility financial/supply assets & optimize the CIS/ERP configuration to effectively serve customers VI. Design and manage business process optimally VII. Optimally manage energy efficiency and conservation programs; enable customers to reduce bills VIII. Utility Systems and Solutions governance optimization Page 11 of 84 © 2018 UtiliWorks Consulting, LLC B. Departmental Visions and Strategies In July 2017, UtiliWorks met with a wide range of utility stakeholders across the organization during the project kickoff meeting and onsite workshops to solicit Utilities IT and AMI project objectives and identify pain points. UtiliWorks presented to each department on key concepts and marketplace trends of AMI, how the functionality and the data might assist with their respective job, and asked that they provide their ideas of what defines project success. This list was categorized into how each objective was related to one of the eight overarching CPAU Technology Goals, as shown in Table 2: CPAU Divisional Objectives. UtiliWorks recommends that CPAU work to quantify and measure these objectives wherever possible, as the AMI project progresses toward deployment in 2020. Table 2: CPAU Divisional Objectives # Division Project Success Measure (Objective) Priority (Hi/Med/Lo) Related UTL Technology Goal 1 RMD Better understanding of customer consumption data by AMI to better tailor our programs (e.g. efficiency/conservation, DER/DR, electrification) to better serve our customers Hi (VII) 2 RMD Provide Virtual metering toolkit to assist with customer profiling, budget billing, analysis of EVs, PVs, energy storage, and meet CA net metering requirements. Hi (V) 3 RMD Insight into and alert thresholds for high consumption at city parks, customer water leakage detection (with option for remote shut-off for irrigation meters) Med (VII) 4 RMD Ability to implement retail rates in the billing system that can further influence customer utility usage patterns (e.g. TOU rates or CPP) Hi (I) 5 Elec Ops. /Eng. Improve service reliability with timely and accurate information (OMS) to respond to outages Hi (IV) 6 Elec Ops. /Eng. Incorporate information gained from AMI with distribution system design and operation (for switching and restoration, distribution transformer and line segment loading calculations). Hi (III) 7 WGW Ops. /Eng. Near real-time, interval data used for analysis, conservation enforcement, leak detection and overflow alerts Hi (VII) 8 WGW Ops. /Eng., CSS Meter tamper alerts Med (IV) 9 All Benefit/cost ratio of greater than 1.0 for AMI investments Hi (VI) 10 CCS, Admin Increased meter/billing accuracy Hi (VI) 11 CCS, Admin Instituting remote turn on/off Med (III) 12 CCS Less high bill complaints and reduction in phone calls Med (I) 13 CSS, EWWGW Ops. /Eng. Better equipment information and GIS locations for meters Hi (IV) 14 CSS, Admin Improved meter reading accuracy/efficiency (timely read) Hi (III) Page 12 of 84 © 2018 UtiliWorks Consulting, LLC 15 CSS, Admin Improved safety for meter reading and operations staff; reduction in workers compensation Med (VI) 16 CSS, Admin Improve meter to cash flow and improve cycle time from read to bill Hi (VI) 17 CSS, Admin Access to interval meter data to perform analytics for customers and staff (including leak detection) Hi (VII) C. Sustainability & Climate Action Plan (S/CAP) Goals The City envisions building the “Utility of the Future.” The foundation of such a program is a two-way communication system that supports an awareness and command/control capabilities for Utility assets in real time. AMI serves as the foundation to attain this vision. This assessment report provides an updated view of the marketplace for AMI and related programs, as well as an updated cost-benefit analysis, which will help CPAU to realize a key goal relevant from the City’s SCAP “Goal 8.1 Advance smart grid strategies.4” Gaining access to increased granularity of data will also help inform the other strategies outlined in Goal 1.2 (Evaluate and adapt the CPAU business model) and Goal 1.3 (Continue to advance carbon neutrality) from the SCAP. D. City IT Vision Goal 8.1 is closely tied to the more broadly defined, City IT Department vision, “To Build and Enable a Leading Smart and Digital City.5” While AMI can contribute to the goals that are discussed in this section, to achieve these goals significant planning and strong project governance/oversight are critical to success. This is discussed in more detail in Section F – Implementation Roadmap. 2. Risks and Mitigation Like any large-scale technology investment, the transition to AMI is not immediate and not without obstacles. The complexity involved with bridging multiple departments, integrating with a live billing system, and sustaining critical utility operations will no doubt lead to challenges. However, many project hurdles can be planned for and addressed as part of a proper risk management approach. As part of the City’s consideration for an AMI deployment, UtiliWorks commenced early identification, prioritization and development of mitigation strategies for risks that may be inherent to the project. To this end, a risk register has been developed that documents potential risks, respective priorities, and respective response strategies. For the purposes of planning, risks have been categorized into eight (8) distinct types: budget, community, organizational change management, resources, schedule, scope, security, and technology. Each risk is assigned a risk impact (representing the potential impact of the risk, should the risk be realized) and a risk probability (representing the likelihood of the risk ever occurring during the course of the project), each of which is rated as “high,” “medium,” or “low.” The confluence of these two vectors generates a risk map, illustrating the priority. The matrix used to generate the risk map is illustrated in Table 3: Risk Map Matrix, where green represents a low priority, yellow represents medium priority, and red represents a high priority. 4 City of Palo Alto: Sustainability and Climate Action Plan 2016 Framework, Nov. 2016. 5 http://www.cityofpaloalto.org/gov/depts/it/city_it_strategy.asp. Page 13 of 84 © 2018 UtiliWorks Consulting, LLC Risks can be addressed by one of four (4) responses:  Accept - Acknowledging the existence of a particular risk and making a deliberate decision to accept it without engaging in special efforts to control it.  Avoid - Adjusting program requirements or constraints to eliminate or reduce the risk).  Mitigate - Implementing actions to minimize the impact or likelihood of the risk.  Transfer - Reassigning organizational accountability, responsibility, and authority to another stakeholder willing to accept the risk. As of this assessment, 36 risks have been identified, including: 25 implementation phase risks, and 11 post-implementation phase risks. Of these risks, eight (8) are coded green, 18 are coded yellow, and ten (10) are coded red. Of the ten (10) risks coded red, CPAU has identified five (5) that warrant high- level consideration:  Resources - Ongoing or upcoming infrastructure projects may compete for resources.  Resources - Poor staff engagement/communication and lack of focused change management plans/implementation.  Scope - Ill-defined contracts lead to improper level of configuration or missing integrations.  Technology - Poor system integration to existing and future applications (i.e. GIS, ERP, CIS, Asset Management).  Community - Lack of Council-approved policies and protocols to effectively respond in a new technology environment (e.g. billing disrupted through a cyber-attack, cyber hack that results in remote turn-off of customer meter). Mitigation strategies for each of the risks listed can be found in Appendix A, but specific actions have already taken place to mitigate these risks. For instance, the Utilities Technology Roadmap (Appendix C) has been developed to ensure that current and future project needs do not overlap and create financial friction within the organization. Moreover, CPAU has been proactive about involving different areas of the organization to develop awareness and buy-in to the AMI project. See Appendix A for the full risk register. Risks are sorted based on risk type then risk map. Risks have also been delineated between implementation and post-implementation phases. As a living document, this risk register should be actively managed by the Project Manager as Palo Alto proceeds with its smart grid effort. Table 3: Risk Map Matrix Risk Probability Low Medium High Risk Impact Low Green Green Yellow Medium Green Yellow Red High Yellow Red Red 3. Current State Operational Review UtiliWorks has provided support and guidance to several multi-service utilities as they plan, design, develop, deploy, train, test, and accept an AMI system. A key step in this process is to assess readiness and identify potential operational gaps that could pose a challenge during implementation and with ongoing system maintenance and support. Across multiple departments, UtiliWorks examined current Page 14 of 84 © 2018 UtiliWorks Consulting, LLC utility operations, meter hardware and equipment, systems and software, reporting capabilities, and personnel. The information was acquired via data requests and a series of workshops in July 2017. A narrative of findings resulting from the discovery effort related to the current state of operations are included in Appendix B. UtiliWorks’ findings are divided into the following categories:  Meter Reading & Field Services  Billing  Customer Service  Electric Meters/Meter Shop  Electric Operations  Water Meters/Meter Shop  Water Operations/Water Conservation  Gas Meters/Meter Shop  Gas Operations  IT Support/Systems The discovery effort allowed team members across the organization to discuss potential constraints in their operations which could impact the implementation of an AMI system. This information was reviewed and analyzed to establish Palo Alto’s divisional goals, to help identify gaps in implementation planning, and to establish the necessary assumptions behind the cost-benefit analysis. Review of these functions also provides a baseline for the current state business process design so that required process changes can be identified and discussed. In general, CPAU appears well equipped and well-informed for AMI deployment. UtiliWorks also conducted a state-of-the-industry presentation to a large cross-section of the organization. CPAU has considered the project staffing needs, along with the new opportunities that will be available. Within Section F, Table 13: Implementation-Readiness Gap Analysis provides details on key areas specific to implementation readiness at Palo Alto. Page 15 of 84 © 2018 UtiliWorks Consulting, LLC Utilities Technology Roadmap An AMI system provides capabilities related to advanced analytics for a utility. The level of technical maturity of a utility impacts the readiness to make use of these capabilities. CPAU has made use of business intelligence tools and has identified uses of AMI data to support utility goals and objectives, such as distributed energy generation. Areas of concern for the utility organization include the timely implementation of a new CIS, including a large data cleanup effort, and conversion of GIS to an ESRI format with all meters and infrastructure assets properly identified. UtiliWorks emphasizes that these systems are key for integrating with an MDMS and impact the system analytical capabilities available after full deployment. 1. Technology Maturity at CPAU Given that the technologies Palo Alto plans to implement are fundamentally transformative to daily operations, it is important that Utilities recognize its readiness to proceed with planned technology projects. Here we address readiness, both in terms of Palo Alto’s own organizational ability to implement new technology (“internal factors”), as well as the market’s maturity to deliver on solutions that address Utilities’ needs (“external factors”). To evaluate each area, UtiliWorks has developed a model for appraising the maturity level. This methodology has been adapted from similar models used to evaluate Smart Grid maturity. Table 4: Internal Factors and Table 5: External Factors score each readiness area and outline the corresponding rationale for each score. Internal factors are scored on a 1-5 scale: 1. Base Capability/Default 2. Expanded Capabilities 3. Integrated Capabilities 4. Early Adopter 5. Bleeding Edge Table 4: Internal Factors Readiness Area Score Rationale Org Structure 3 • Project Management Office (PMO) • Utility-owned IT systems Strategy, Management 3 • Coordination between city-wide projects Technology Capabilities 2 • Elster pilot (including Home Area Network) • MUA 2.0 to begin November 2017 • CIS replacement in progress - Fall 2017 • Business Intelligence reporting tools Grid/Distribution Operations 2 • Conservation Voltage Reduction assessment completed 2015 • Distributed Energy Resources assessment underway • Gas model completed • Water model being evaluated Work Order and Asset Management 2 • Utility Asset Management System to be deployed in conjunction with ERP • Pilot mobile workforce app • Planned migration to new GIS platform, ESRI Page 16 of 84 © 2018 UtiliWorks Consulting, LLC External factors are scored on a 1-5 scale: 1. Base Capability/Default 2. Expanded Capabilities 3. Some Integration Capabilities 4. Fully Integrated Capabilities 5. Fully Matured Table 5: External Factors Readiness Area Score Rationale Technology Market 5 • AMI has fully matured over past 5 years • MDMS has fully matured over past 5 years • Customer portals can vary from vendor to vendor, but Smart Energy Water is a mature platform Community 4 • Community engagement through Strategic Plan • Educated customer-base, with high adoption of EV and portal technology Regulatory (State, Federal) 4 • Rapidly evolving market for all commodities • CEC, CPUC, FERC, NERC, DOE Because external factors are well-matured, Palo Alto possesses relatively little functional, social, or political risk in moving forward with technology projects, but Utilities must be careful to not be organizationally or technologically hindered because of controllable internal factors. 2. IT System Gap Analysis and Planning Findings related to IT Systems planning can be found in italics at the end of each section below. Additional considerations for these systems as they relate to the procurement stage of the AMI project are included in Appendix C. A. Customer Information System and AMI Project Coordination CPAU is implementing a new Customer Information System (CIS), with current plans to deploy at the end of Q2 2020. The CIS will have requirements related to AMI, including storing interval billing data and Meter data, reporting on interval billing and meter data, validating the data and processing exceptions, and integrating with the new MDMS. CPAU issued an RFP to replace its CIS in September 2017, with responses received at the end of October 2017. As the CIS vendor proposals are reviewed, both CPAU and the AMI advisors should assess the CIS vendor’s capabilities around AMI functionality and integration. B. Systems Integration AMI introduces new integrations between software systems. An example of MDMS integration is shown in Figure 2: AMI/MDMS Architecture. The MDMS will integrate with the AMI Head End System (HES), CIS, MyUtilitiesAccount (MUA), and GIS, and eventually the Outage Management System (OMS). In choosing an MDMS, CPAU should consider whether it has prebuilt integrations with the CIS, AMI HES, GIS, and OMS, and whether the pre-built integrations can be customized without vendor assistance. Page 17 of 84 © 2018 UtiliWorks Consulting, LLC The AMI/MDMS interfaces will be implemented using web services and may also include secure flat file transfers. CPAU is currently using MultiSpeak version 3.0 in the integration between the Outage Management System (NISC) and SCADA (ACS). In choosing an MDMS and CIS vendor, CPAU should ensure that each system support integration standards, such as MultiSpeak (version 4.1 or higher), or the Common Information Model (CIM). Figure 2: AMI/MDMS Architecture C. Data Communications Backhaul communications for an AMI system is up to the utilities’ discretion. CPAU is considering deploying a municipally-owned fiber-to-the-node (FTTN) network. This network is being considered as a platform for Public Safety and Utilities wireless communication in the field, Smart Grid and Smart City applications, and new dark fiber licensing opportunities. Benefits associated with a fiber network include: 1. Reliability – Fiber is exceptionally resilient for data communications with a low failure rate. The equipment used to connect fiber has improved over time. Many cable and network providers use fiber due to its reliability, performance, and relatively low maintenance costs. 2. Network optimization – Since the owner has total control over the backhaul communications network, advanced IP V6 capabilities can be provided to devices that connect to nodes (which can have multiple access capabilities). Fiber networks can provide very high bandwidth data communications that can support multiple video streams, high data volumes, and enhanced network response times. The same network backbone could easily support a wide variety of “Smart City” applications including street light optimization and control and even parking meters. It should be noted that the data volume related to AMI systems is relatively small and does not require such high bandwidth channels. 3. Security - Private fiber networks are routinely used for high-security environments and systems such as SCADA and can be configured to meet all state, federal and utility requirements. AMI Head- End MDMS Event Files Meter Events Meter Commands Measurement Data Interval & Register Files Meter Commands CISOMS SCADA IVR GIS Base Maps, Selected Layers Meter Events Data Synchronization, Billing Reads MDMS Customer Portal MWM SSO Integration Layer Integration Layer MUA Portal SSO Page 18 of 84 © 2018 UtiliWorks Consulting, LLC If fiber is in place for the AMI backhaul, it can be used. If not, the existing city network and or a private, cellular network can be utilized for backhaul communications of AMI data. A cellular network is managed by a public access carrier, such as Verizon or AT&T, and requires monthly payment for service. The initial capital cost associated with setting up a communication channel through a public carrier is likely lower than capital costs associated with accessing the fiber network. UtiliWorks recommends that CPAU explore all backhaul options that will be available prior to 2020 deployment and update the AMI Implementation Plan accordingly. D. Enterprise Service Bus An Enterprise Service Bus (ESB) is a robust system integration platform that supports the communication between multiple software applications. With this architecture, each application transmits the necessary data directly with the ESB. The ESB routes that data to one or more applications that is connected to the Bus. When an ESB is not in place, integration is commonly achieved using point-to-point web services. CPAU does not currently have an ESB. This platform may be used, but is not required, to integrate AMI/MDMS with other applications. Implementing an ESB in conjunction with AMI will increase the timeline, budget and complexity for the project; however, if the city wants to move toward an ESB as an integration platform, then it can be leveraged for necessary interfaces with the AMI and MDMS. Since an ESB is not currently in place, it is recommended that CPAU implement a Service Oriented Architecture (SOA) using web services and MultiSpeak. UtiliWorks does not recommend that CPAU implement an ESB solely for AMI, as point-to-point integration is sufficient for AMI/MDMS integration. E. Utilities IT Team CPAU is undertaking many large-scale IT projects over the next five years, including a new CIS, newly designed MUA, ERP and AMI. These systems will be tightly integrated and dependent on each other. CPAU and the city IT Department’s technology preference is to purchase software-as-a-service, which is hosted by the vendor and may be cloud-based. In this model, certain system development and administration duties are shifted away from the city. Still, some city IT resources are necessary to act as a liaison between the city and the vendors, to support utility employees who use the system and to take ownership of the systems. UtiliWorks recommends that the CPAU organization maintain ownership of ongoing planning, development and support of Utility software systems, with ongoing input from city IT staff on security and support agreement. F. Information and Cyber Security The reliable availability of critical infrastructure−such as the electric grid and water/natural gas supply infrastructure−is essential to the well-being and security of the country and the Palo Alto community. Utilities are making concerted efforts to identify and address security risks across electric, water, and gas utility system assets and their connectivity points. With the implementation of advanced metering infrastructure, these industrial control systems (ICSs) can be vulnerable to cyber- attacks. This includes attacks to steal customer personal information/energy consumption behavior and the utility infrastructure controls. Due to their increasing deployment at utilities across the country, smart meter hacking has become a popular topic among security professionals and ethical hackers, with many talks given annually on the penetration-testing of these devices at popular conferences such as Defcon, Black Hat, and Shmoocon. Page 19 of 84 © 2018 UtiliWorks Consulting, LLC Though no catastrophic actions have yet occurred, a few isolated incidents have resulted in the theft of utility services and limited access to back-end data. Utilities can reduce vulnerabilities from cyber-attacks or events by following these steps: 1. Identify systems that need to be protected. 2. Separate systems into functional groups. 3. Implement tiered defenses around each system. 4. Control access into and between each group. There are various standards that utilities can refer to regarding cyber security. In January 2016, the North American Electricity Reliability Corporation (NERC) issued revised Critical Infrastructure Protection (CIP) reliability standards for electric utilities. The updated standards provide guidance in preparing for cyber security, including quarterly cyber security training for large utilities, closing unnecessary networking ports, and developing procedures for the storage of information. Water utilities can refer to American Water Works Association (AWWA)’s Water Security Roadmap. Another useful resource for all utilities is the Department of Homeland Security (DHS)’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT, https://ics-cert.us- cert.gov/). The ICS-CERT works to reduce risks within and across all critical infrastructure sectors by partnering with law enforcement agencies and the intelligence community and coordinating efforts among federal, state, local, and tribal governments and control systems owners, operators, and vendors. The Department of Energy (DOE) has developed DataGuard as a framework for utilities to use in developing their data privacy policies, to protect the access, use, and sharing of customer data. Page 20 of 84 © 2018 UtiliWorks Consulting, LLC Figure 3: Cyber Security Life Cycle UtiliWorks recommends that CPAU explore these resources and adopt a life cycle approach to build cyber security knowledge for key staff involved with the project. UtiliWorks also recommends that the CPAU project team liaise with an Information Security Officer (ISO) from City IT for the AMI and MDM systems. The ISO will define Information Security requirements for the RFP, review the vendors’ proposals from a security perspective, review and sign off project designs from a security perspective, and plan for ongoing security audits and penetration testing. Additional IT security recommendations are included in Appendix C. G. Planning for Technology Obsolescence Technology Obsolescence occurs “when a technical product or service is no longer needed or wanted even though it could still be in working order."6 Since AMI is part of an evolving industry with multiple types of technologies, the risk of technology obsolescence must be considered and mitigated. The risk of technology obsolescence can be mitigated by the following: 6 http://www.businessdictionary.com/definition/technological-obsolescence.html. Page 21 of 84 © 2018 UtiliWorks Consulting, LLC 1. Choose vendors that conform to industry standards such as the MultiSpeak or API integration standards. 2. Prioritize interoperability and flexibility in the AMI system design and vendor selection. a. As a multi-commodity utility, CPAU needs to ensure that water, gas, and electric meters all communicate with installed systems. In choosing gas and water meter vendors, it is critical to consider their track record in supporting modules/communications with a variety of AMI systems. 3. Choose widely-adopted technology types. 4. Choose vendors with strong financial viability and that invest in innovation and product improvement. AMI technologies continue to evolve, so it is important to architect a solution that is flexible and adaptable, and one that can be upgraded and enhanced as technologies change. The system design should also be scalable, to accommodate projected growth in number of meters. For more factors to consider during procurement, see Appendix C. 3. Utilities Technology Roadmap UtiliWorks created a Technology Roadmap (Figure 4: Utilities Technology Roadmap) of the projects that CPAU plans to undertake in the next five (5) years. Estimated costs for major projects included are itemized in Table 6: Estimated Major Technology Project Expenditures. To create the roadmap, UtiliWorks reviewed the progress and current state of 40 technology projects that resulted from the 2014 Utilities IT Systems Review, along with CPAU’s input on new projects. The City of Palo Alto is currently planning the implementation of a new ERP system, starting with the HR module, continuing with the Finance module and Utility Asset Management. This will occur in lock- step with the deployment of a new CIS. The CIS deployment is expected to be complete by the end of Q2 2020 and will be followed by a six-month stabilization period. There are several projects dependent on the CIS, which include: AMI, new MUA Phase II, Mobile Workforce Management, and a flexible billing and payment solution. CPAU plans to implement an AMI system following the first three (3) months of the CIS stabilization period, with full deployment of AMI estimated to conclude by the end of Q2 2022. Several longer-term projects are dependent on the AMI system being in place, including an integrated Outage Management System, Distribution System Optimization and an expanded Demand Response Management System. CPAU started a Smart Grid Pilot project in 2013, which is still operational and administered by Utilismart/Elster. Roughly 300 meters each of electric, water, and gas are included in the pilot, with a mix of both opt-in customers and regular customers. During the pilot, CPAU assessed the impact of TOU rates on Electric Vehicle (EV) charging, as well as use of HAN devices using ZigBee protocol. As a result of the pilot, CPAU has decided not to proceed with deployment of HAN devices at this time. CPAU will continue to offer opt-in Time of Use (TOU) rates, since the rate structure has proven to be cost-effective for EV owners. Palo Alto has one of the highest EV adoption rates in the country. The pilot project’s data is expected to be migrated to the new MDMS, once available in 2021. UtiliWorks recommends that the Utilities Technology Roadmap presented in this section be reviewed and revised on an annual basis by the Utilities IT team. There is a longer-term Reassessment Phase identified after Year 5. This period will be a strategic, cross-cutting review of all technology in place and will set the direction for future projects at CPAU. Page 22 of 84 © 2018 UtiliWorks Consulting, LLC Figure 4: Utilities Technology Roadmap (Simplified) Table 6: Estimated Major Technology Project Expenditures Project Estimated Cost ($Million) Enterprise Resource Planning $1.5 Customer Information System $4.0 Energy Efficiency Programming Optimization TBD Advanced Metering Infrastructure and Meter Data Management System $16.3 Conservation Voltage Reduction $0.4 My Utilities Account $0.2 Data Cleansing $0.4 Outage Management System TBD Note that for the purposes of this report, the Technology Roadmap illustrated here is a simplified version. A comprehensive roadmap can be found in Appendix C. Key: Q4-2017 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Energy Efficiency Program Optimization (EEO) (TBD) Technology Systems (Est. Capital Cost) Year 1 - 2018 Year 2 - 2019 Year 3 - 2020 OMS & AMI Integration Distribution System Optimization, CVR Customer Time-of- Use Rates Expansion New EE Programs, DR programs Utility Strategic Plan Development Re - a s s e s s m e n t P h a s e AMI/MDMS ProcurementAMI/MDMS System Spec Data Cleansing - field checks, master data clean-up CIS Stabilization Issue ERP RFP and Retain Vendor Implement New ERP HR Module Implement New ERP Finance Module Develop Technology Roadmap Note: Early selection of AMI vendor allows meter replacements to resume as planned, ahead of mass installation of AMI meters. Future Programs that are dependent on AMI Dates and $ TBD Integrate CIS to SAP & MUA Data Conversion: Create existing Customers in CIS Implement CIS + Integration with existing SAP/ERP systemCIS Design PhaseIssue CIS RFP and Retain Vendor 300 Home Customer Connect / TOU Rate Pilot Program - Maintenance Phase Full Deployment (by route/cycle) Improvement of Energy Efficiency Program Promotions based on new CIS/AMI - Planning and Pilots, on going Technology Deployment Advanced Metering Infrastructure (AMI) & Meter Data Management System (MDMS) ($17 to $19 M) Future ProjectIn Progress Alpha Phase AMI/MDMS Implementation Beta Phase AMI/MDMS Implementation Integrate MDMS to CIS, MUA, AMI Head End System (HES), OMS & GIS Enterprise Resource Planning (ERP) (UTL share $1 to $2 M) Customer Information System (CIS) ($4-5M) In Planning Flexible Billing & Payment Solution Year 5 - 2022Year 4 - 2021 ERP Design Phase Integrate new ERP with CIS Years 6+ Dependenton CIS Coordination Dependenton CIS/MUA Dependenton AMI Dependent on AMI Dependenton AMI Coordination Dependenton AMI Page 23 of 84 © 2018 UtiliWorks Consulting, LLC Cost-Benefit The foundation of the Palo Alto cost-benefit analysis is implementation of a comprehensive AMI solution. This includes an AMI system, an MDMS, a Customer Portal, and the necessary integration of these systems to produce an accurate bill. As part of this effort, the city will need to replace all electric meters and some natural gas and water meters, and retrofit all water and gas meters with an AMI radio, or endpoint. The meter replacement determinations are discussed in greater detail within the Assumptions section below. Palo Alto also requested that an add-on program for Conservation Voltage Reduction (CVR), be included to the base cost-benefit. This program leverages the AMI technology and would therefore not be feasible without the implementation of AMI in Palo Alto’s service area. UtiliWorks developed a comprehensive financial model, which represents the deployment of these various technologies. There are three primary areas that comprise the cost-benefit:  Capital Costs (i.e., AMI infrastructure, equipment, installation, professional services, etc.).  Ongoing Operation and Maintenance (O&M) Costs (i.e., annual fees related to software hosting and licensing, staffing, etc.).  Anticipated Benefits (i.e., potential operational savings, revenue enhancement, reduction of water leaks, conservation/efficiency programs for customers, better asset utilization, etc.). UtiliWorks’ general approach when developing the model is to review the assumptions with the respective Utility staff and ultimately arrive at a conservative base case. This section provides the cost-benefit results summary, project assumptions, and a breakdown of costs and benefits used in the calculations. The detailed model inputs provided by Palo Alto along with assumptions underlying the cost and benefit calculations are provided in the Excel-based financial model. The model can facilitate further changes to the underlying assumptions and examine various scenarios with relative ease in the event Palo Alto wishes to explore other scenarios. 1. Results The model provides a variety of financial metrics for Palo Alto to evaluate the financial viability of the AMI project, including the Net Present Value (NPV) and capital expenditure. See Table 7: Summary Base Case Results for the summary of Cost-Benefit results based on deployment of AMI, MDMS, Customer Portal, and CVR technologies. This table displays the results of the so-called “base case.” The base case involves full AMI deployment endpoints, with 100% electric meter replacement, and retrofitting of all water and gas meters (with no meter replacements). For purposes of analysis, the purview of this assessment report and proceeding sections reflect the base case results. Despite the relatively low NPV that has been assessed for the project, net annual cash flow is positive post-AMI deployment (2023), with a payback period of 15 years. Net and cumulative cash flow across the project lifespan is illustrated in Figure 5: Base Case AMI Cash Flow, while relative costs and benefits are illustrated in Figure 6: Base Case AMI Cost-Benefit. Page 24 of 84 © 2018 UtiliWorks Consulting, LLC Table 7: Summary Base Case Results Financial Metric Base Case Results ($Million) Capital Expenditure - $16.74 Annual Operational Expense - Year 5 - $1.9 Annual CPAU/Customer Benefit - Year 5 + $3.3 Present Value of Expenses (over 18 years) - $27.08 Present Value of Benefits (over 18 years) + $43.83 Net Present Value (over 18 years) + $0.01 In addition to the metrics outlined, the estimated capital outlay can be expressed on a per-meter basis. For the base case, this cost is estimated to be $224.26 per meter to deploy AMI. By comparison, this per-meter expenditure is substantially lower than those of industry peers (of about $300.00 per meter, based on other CBAs conducted by UtiliWorks). This differential is primarily driven by Palo Alto’s preference not to exchange any water or gas meters within the scope of the AMI project. Figure 5: Base Case AMI Cash Flow $(20,000) $(15,000) $(10,000) $(5,000) $- $5,000 $10,000 CASH FLOW ($000; 18 Years) Cumulative Cash Flow Net Annual Cash Flow Page 25 of 84 © 2018 UtiliWorks Consulting, LLC Figure 6: Base Case AMI Cost-Benefit A. Sensitivity It should be noted that the base case results represent only one possible scenario, and that projections of NPV are highly dependent upon the operational and benefits assumptions used, due to length the project lifespan. Herein, we discuss the NPV’s relative sensitivity related to potentially higher operating costs as a result of failing to realize the staffing synergies assumed in the CBA and the extent to which the AMI system can facilitate conservation savings. The effect of these variables on NPV is illustrated in Table 8: NPV Sensitivity Matrix. Table 8: NPV Sensitivity Matrix ($MM) Conservation Goals Achieved 50% 100% 150% Staffing Synergy Status Achieved ($7.76) $0.01 $7.77 Not Achieved ($14.7) ($6.96) $0.80 Here, 100% conservation goals are defined as: 1.5% reduction in electric consumption; 2.5% reduction in water consumption; and 2.0% reduction in gas consumption. Achievement of staffing synergy is defined as the sun-setting of the program manager position at the close of AMI deployment and the absorption of electric and water AMI meter-related duties into the current meter technician staffing pool. For a more detailed discussion on staffing, see Section G. In addition to those savings outlined, further conservation savings can be realized as a result of CVR. In the base case, energy reduction related to a CVR program is assumed to be 0.5%. Assuming a 1.0% reduction, the NPV over an 18-year lifespan increases by $5.34 million. $(20,000) $(15,000) $(10,000) $(5,000) $- $5,000 $10,000 202020212022202320242025202620272028202920302031203220332034203520362037203820392040 Cost-Benefit ($000; 18 Years) Benefits OpEx CapEx Cumulative Cash Flow Page 26 of 84 © 2018 UtiliWorks Consulting, LLC Should CPAU choose to proceed with gas and water meter replacement within the scope of the AMI project, incremental costs can also be assessed for the scenario of replacing water or gas meters. For each service, we can consider replacement of all meters 20-years or older from the start of deployment. For gas meters under this condition, an additional capital cost of $3.96 million is incurred; for the water meters under this condition, an additional capital cost of $3.64 million is incurred. Note that, for the purposes of this CBA, we do not account for revenue recovery that may occur as a result of improved meter accuracy. 2. Assumptions UtiliWorks incorporated several informed assumptions into the cost/benefit model. Key assumptions include:  CPAU plans to utilize the services of third-party installation vendor, but may consider self- install if resources are available. Pricing includes the cost of using a third-party installation contractor, except for a small number of 3S, 5S, and 9S electric meters.  CPAU will seek out third-party services to host the AMI Headend, MDMS, and Customer Portal applications. Software hosting and maintenance fees have been applied as future operating expenses.  Electric Operations is the only department that will proceed with meter change-out; however, Electric, Water and Gas will be AMI-equipped with a concurrent deployment.  All residential electric meters will be equipped with remote disconnect capability.  Deployment of the AMI system is expected to take place over a period from Q3 2020 to Q3 2022 including 12 months of proof of concept (POC) testing. Full deployment is estimated to take approximately one year with the use of a third-party installation contractor. General model assumptions are listed in Table 9: General Assumptions. Table 9: General Assumptions Assumption Metric Annual Meter Growth Rate 0.0% Deployment Period 2 Years Total Electric Meters 30,076 Total Water Meters 20,581 Total Gas Meters 24,002 Discount Rate 3.5% Project Lifespan 18 Years Annual Operational Expense Growth Rate 3.0% Annual Benefits Growth Rate 1.0% 3. Cost Estimate UtiliWorks utilizes up-to-date vendor pricing when modeling-the cost estimate. Figures are obtained based on recent market quotes from manufacturers and suppliers, as well as a vendor database that reflects pricing obtained for recent projects at other utilities. Whenever conflicting pricing is noted, UtiliWorks presents a blended rate or upper estimate in the financial model cost assumptions. This method is used to ensure that Palo Alto is provided with a conservative estimate. As an exception, pricing for meters and meter installation are based on Palo Alto CIP budgetary projections. These prices are considerably higher than what would be expected when buying meters in bulk from a vendor and after obtaining the necessary California Department of Industrial Relations (DIR) special wage determination. Actual pricing for Palo Alto is anticipated to be slightly lower than the results presented; however, until proposals are received, actual costs cannot be verified. Page 27 of 84 © 2018 UtiliWorks Consulting, LLC In addition to ordinary expenditures on equipment and professional services, the financial model includes an overall contingency of 10% of capital costs, and 9% sales tax on materials. Based on the assumptions used, the total capital outlay is estimated to be $16.74 million for the base case. Table 10: Project Cost Summary shows a summary of all estimated project costs, including capital and annual operations and maintenance (O&M) costs. Table 10: Project Cost Summary: Capital and Annual O&M Cost Cost Category Total Capital Cost ($) Annual O&M Cost ($) AMI/MDMS Network Deployment + PM AMI Network Infrastructure, Software, and Professional Services $780,000 $115,000 MDMS and Professional Services $550,000 $225,000 Program Management Services and CIS Integration $2,825,551 $0 Planning $200,000 $0 Subtotal $4,355,551 $340,000 Electric Deployment/Maintenance Electric Meters and Sales Tax $4,028,406 $0 Electric Meter Installation Services and Equipment $950,463 $0 Contingency $528,112 $0 Staffing $0 $406,079 Subtotal $5,506,981 $406,079 Water Deployment/Maintenance Water Meters Endpoints, Equipment, and Sales Tax $3,392,732 $0 Water Meter Installation Services and Equipment $411,620 $0 Contingency $352,421 $0 Staffing $0 $406,079 Subtotal 4,156,775 $406,079 Gas Deployment/Maintenance Gas Endpoints, Equipment, and Sales Tax $1,648,217 $0 Gas Meter Installation Services and Equipment $472,570 $0 Contingency $198,469 $0 Staffing $0 $640,401 Subtotal $2,319,257 $640,401 Conservation Voltage Reduction Software License $200,000 $0 Professional Services $204,505 $133,161 Subtotal $404,505 $133,161 GRAND Total $16,743,069 $1,925,720 Note that the annual O&M cost is somewhat higher than the Year 5 projected O&M cost outlined in Table 7: Summary Base Case Results, as some staffing costs are transient to support project deployment. Also, note that not all capital costs will be incurred in the first year, but rather over the Page 28 of 84 © 2018 UtiliWorks Consulting, LLC designated deployment period discussed in the Assumptions section. Figure 7: Capital Outlay illustrates this projected capital cost outlay from 2020 through 2022. Figure 7: Capital Outlay A tabular display of overall costs by service is provided in Table 11: Cost Allocation by Service, where AMI/MDMS Network Deployment and PM costs can be allocated by one of two methods: (I), with electric as a driver and all AMI/MDMS Network Deployment and PM costs allocated to that service; or (II), with AMI/MDMS Network Deployment and PM allocated based on proportion of the total meter population across all three services (40% electric, 28% water, and 32% gas). An average of the two allocation method is also presented for CPAU consideration. Table 11: Cost Allocation by Service ($MM) Category Electric Water Gas Total Cost Allocation Method (I) $10.27 $4.16 $2.32 $16.74 Cost Allocation Method (II) $7.65 $5.38 $3.71 $16.74 Average of (I) and (II) $8.96 $4.77 $3.02 $16.74 In addition, the annual O&M costs presented in Table 10: Project Cost Summary is inclusive of: two (2) temporary positions staffed during AMI deployment—a half-time AMI program manager and a customer service representative, accounting for annual costs $167,280 and $196,371, respectively. Figure 8: Cumulative Operating Expenses illustrates the PV of all operating expenses, considering the phasing-in and phasing-out of staff over the deployment timeline for the project. $2,766 $8,745 $5,233 $- $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2020 2021 2022 Program CapEx ($000) AMI/MDMS Network Deployment + PM Electric Deployment Water Deployment Gas Deployment Conservation Voltage Reduction Page 29 of 84 © 2018 UtiliWorks Consulting, LLC Figure 8: Cumulative Operating Expenses To clarify, the O&M costs illustrated in this CBA represent only the incremental costs that would be incurred by the AMI project and are not inclusive of any operating expenditures that are currently incurred by CPAU. 4. Benefits Estimate Palo Alto completed an initial financial data request, followed by the model assumptions and results review with UtiliWorks. All benefits used in the financial model are based on the annual operating expenses and capital budget costs for FY16. Table 12: Annual Project Benefits Summary summarizes all benefits areas, their value driver with key calculation assumptions, and annual value for the first year of full operation. Table 12: Annual Project Benefits Summary Cost Category Key Assumptions(s) Annual Benefit ($) Meter Reading Electric Meter Reading 95% reduction overall $507,799 Water Meter Reading 95% reduction overall $347,487 Gas Meter Reading 95% reduction overall $405,247 AMI Head End, $1.80 Cellular Backhaul, $0.27 MDMS + Customer Portal, $4.04 Electric Staff Subtotal, $5.64 Water Staff Total, $5.36 Gas Staff Total, $9.33 Annual Maintenance - CVR, $0.65 $- $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 PV OpEx - Lifetime ($MM) 18-yr. Present Value of Cumulative OpEx ($MM) Page 30 of 84 © 2018 UtiliWorks Consulting, LLC Subtotal 95% reduction in staffing load $1,260,533 Customer Service Outstanding Payment Reduction 10% late payment reduction on remote disconnect meters $11,700 Electric Customer Call Reduction 5% reduction $13,278 Electric Customer-Generated Service Order Reduction 90% reduction on service checks $48,356 Electric Billing Expense Handling Expense 25% reduction $13,426 Water Customer Call Reduction 5% reduction $26,557 Water Customer-Generated Service Order Reduction 90% reduction on service checks $96,711 Water Billing Expense Handling Expense 25% reduction $9,188 Gas Customer Call Reduction 5% reduction $26,557 Gas Customer-Generated Service Order Reduction 90% reduction on service checks $96,711 Gas Billing Expense Handling Expense 25% reduction $10,715 Subtotal 12.7% reduction in staffing load $353,199 Operations Non-Pay Disconnect Labor 99% reduction $15,345 Outage Management 10% response-time reduction $1,366 CVR 0.5% reduction in electricity purchases $397,348 Electric Theft Identification 0.05% reduction of total consumption impact $469 Water Theft Identification 0.1% revenue recovery $38,000 Gas Theft Identification 0.05% revenue recovery $19,000 Subtotal 10.1% reduction in staffing load $471,528 Improved Meter Accuracy Electric Revenue Capture Negligible meter inaccuracy benefit $0 Water Revenue Capture No meter replacement $0 Gas Revenue Capture No meter replacement $0 Subtotal $0 Conservation Savings & Avoided Cost Electric Conservation 0.5% conservation for residential customers, ramping up to 1.5% in 5 years; 0.25% for commercial customers $377,481 Water Conservation 1.00% conservation, ramping up to 2.5% in 5 years $550,067 Page 31 of 84 © 2018 UtiliWorks Consulting, LLC Gas Conservation 1.00% conservation, ramping up to 2.0% in 5 years $264,000 Subtotal $1,191,548 Avoided CIP Water Annual Meter Replacement Budget 0% inaccurate meters (no meter replacement) $0 Gas Annual Meter Replacement Budget 0% inaccurate meters (no meter replacement) $0 Subtotal $0 Asset Management Solar Meter Installation Cost Avoidance 100% reduction $20,000 Subtotal $20,000 GRAND Total $3,296,808 A graphic representation of benefits across the project lifespan is depicted in Figure 9: Cumulative Expenses and Benefits, and cumulative expenses are also shown for comparison. As is evidenced by this graph, a major factor is increased conservation by customers, which alone accounts for over one-third of total annual benefits. On a PV-basis, total conservation savings is estimated to be $15.5 million. This PV estimate scales proportionally to conservation goals, accounting for $7.75 million in benefits for half of conservation goals met, and $31 million in benefits for doubling conservation goals met. AMI implementation makes demand-side conservation goals significantly easier to attain due to the abundance of data available to customers, and this effect is magnified due to the highly-educated, environmentally-conscious populace of Palo Alto. Page 32 of 84 © 2018 UtiliWorks Consulting, LLC Figure 9: Cumulative Expenses and Benefits It is important to remember that, while the cost-benefit results provide a fairly accurate estimate of the expected project costs and payback, this model represents a conservative estimate of the cost and value of an AMI project. AMI technology fundamentally changes the meter-to-cash process. What is not easily recognized is that, depending on the supporting technology and business process changes employed, a utility can realize even greater benefits through the proactive use of the data and information now available. Leveraging AMI technologies will significantly improve the measurement and management of utility resources and will bring direct benefit and value to customers. 5. Quantitative Benefits The following section will outline the potential benefits that can be realized with the data yielded from an AMI system along with add-on technologies, such as remote disconnect and leak detection. UtiliWorks worked with staff at Palo Alto to derive the necessary data and assumptions to calculate the potential benefits and factored those conclusions into the cost-benefit analysis in Section E.  Meter Reading Reduction – Elimination of on-cycle manual meter reading expenses, including staff time, fuel, and vehicle maintenance costs.  Customer Call Reduction – Reduction of cost related to decreased number of customer calls. This reduction occurs from a combination of online usage information now available to a CSR to better respond to inquiries, in addition to customers having access to their information via Page 33 of 84 © 2018 UtiliWorks Consulting, LLC Customer Portal. Customers will also now have the ability to configure usage notifications via text or email.  Customer Generated Service Order Reduction – Elimination of most check-read/skip/no-read field activities and expenses in reviewing skips report, creating the work orders and rolling a truck to collect the re-read. New billing routines will have a range of dates a read may be pulled to use on bill (e.g. read date or two days prior) and/or a read may be collected via on- demand read functionality.  Move-In / Move-Out Read Reduction – Elimination of most off-cycle read field activities when customers move in and out of a premise. This savings will result from new presentation of daily AMI reads and the ability to collect on-demand reads.  Non-Pay Disconnect Labor – Reduction in collections labor and field activities for non-paying customers. The majority of trips to a premise can be avoided due to remote disconnect/connect capability of electric AMI meters.  Billing Exception Handling Expense – Reduction in billing service expenses associated with increased efficiencies. The new MDMS will contain advanced Validation, Editing, and Estimation (VEE) routines and accurate real-time and historical meter information. This can translate to fewer bill estimations, billing errors, and adjustments.  Electric Distribution System Asset Performance Improvement – Reduction in O&M costs from utilizing real-time AMI data to assist with operational decisions. Manual adjustments or integration with a SCADA system can result in performance improvements via electrical distribution system controls. Ability to monitor distribution transformer loading, particularly given the wide spread adoption of Electric vehicles and other distributed energy resources.  Theft Identification Revenue – Alarms triggered in the AMI software can identify both electric and water meter tampering and product diversion. This is a valuable tool for any utility to identify theft in near real time as compared to monthly when the meter reader puts eyes on a meter.  Electric Improved Meter Accuracy – Electromechanical electric meters degrade over time. According to a study performed by the Electric Power Research Institute (EPRI), electromechanical meters register at a slower rate if not calibrated ranging from 0.5% after five years to 2.75% after 20 years. Given the societal perspective of this analysis, this benefit was not included in the CBA.  Meter Scrap Revenue – Added revenue from scrap of old meters during replacement. Local market pricing is utilized for all scrap values and weight is determined by the number and size of meters to be replaced as part of the project.  Annual Meter Replacement Budget – Elimination of current annual meter replacement spending for faulty meters by installing new AMI ready meters with long-term warranties. Any capital cost for new meters will be accounted for in the capital costs of the financial model, so this is added as a benefit to avoid any double counting of the meter replacement budget.  Unaccounted-for Water Loss Savings – A significant savings of unaccounted for losses may be recovered via acoustic leak detection. This technology allows the Utility to identify leaks through remote devices that piggyback on the AMI network. The devices are placed in strategic locations throughout the water distribution system to provide full system monitoring. 6. Qualitative Benefits In addition to those benefits that can be quantified and included in the cost-benefit analysis, Palo Alto can realize numerous intangible/soft benefits. While many of these benefits are not easily measurable, they are certainly real and achievable with the successful deployment of an AMI system.  Improved Customer Experience - Using interval consumption data (consumption, power factor, voltage, etc.), customers can more effectively manage their energy usage. Page 34 of 84 © 2018 UtiliWorks Consulting, LLC  Improved Reliability - The AMI system will detect electrical outages and enable Palo Alto to model the overall system(s) demand to facilitate proactive management and improve reliability.  Improved System Planning Capabilities - Information that can be produced and analyzed from an AMI system can facilitate the improved management and monitoring of electric, gas, water, and wastewater system performance leading to better informed capital investment decisions. System engineering and maintenance programs can be supported with better, more frequent access to the more granular data that will be provided by the AMI system.  Improved Asset Utilization – Reduction in O&M costs from utilizing real-time AMI data to assist with operational decisions. Manual adjustments or integration with a SCADA system can result in performance improvements via distribution system controls. Improved visibility of distribution transformer loading.  Improved Water Resource Management - Using interval consumption data, customers can more proactively and effectively manage their water consumption. The AMI system will enable CPAU to model the overall system demand, identify customer leaks and facilitate proactive management of the industrial and residential customer base.  Timely and Accurate Meter Reading – Beyond simply the fully burdened costs of meter readers, this activity involves coordination across a variety of staff within CPAU. AMI reads will alleviate the strain on staff to deliver timely and accurate meter reads.  Implementing Advanced Retail Rates – Interval consumption data and advanced MDMS reporting options will assist Rates Analyst in developing and evaluating advanced rate structures such as TOU or rebate for participating in Demand Response programs.  Meter Right-Sizing – Data and alarms produced by an AMI system will provide the Utility with the ability to detect if a water meter is over or undersized.  Unauthorized Use Detection - Current generation AMI Systems provide flag or high priority alerts or reports for reverse water flow and tamper detection. This information could be of significant benefit to CPAU and should also facilitate reduction of unauthorized usage or theft.  Improved Safety/Reduced Workers’ Compensation - Ensuring safety for both utility employees and customers is essential. With the introduction of automated meter reading, Palo Alto will have the ability to remotely read meters, initiate on-demand meter reads, and remotely disconnect/reconnect customers. This will dramatically reduce exposure to risky conditions on the road and at a customer premise, such as weather conditions, unfriendly pets, physically hard to access meters, and theft.  Compliance with Future Legislative Requirements - The Energy Policy Act of 2005 placed a requirement on states and non-regulated utilities to investigate and consider AMI for its customers. With the introduction of AMI, Palo Alto will better prepare itself to address all legislative and/or CA state requirements regarding conservation, time based rates and other energy-related issues.  Potential Grants from Water District – The implementation of AMI places CPAU in the advanced group of utilities that may be eligible for grants from the water district. Page 35 of 84 © 2018 UtiliWorks Consulting, LLC Implementation Roadmap 1. Project Phasing – Scope & Schedule With an enterprise project of this scope, it is important to track the effectiveness of the implementation and how it meets the pre-established acceptance criteria. Project phasing is a critical aspect of implementing AMI given the multi-faceted nature of the technology. This approach divides the project work into specific phases, each with its own measurable outcome which builds from the previous phase. Performing work in this manner reduces the risk that the effort does not get off-track or otherwise proceed without the prerequisite steps successfully completed. Following contract execution (and to the extent possible overlapping with contract negotiation), UtiliWorks recommends that Palo Alto start pre-deployment planning. Figure 10: AMI Deployment Plan provides a visual representation of the project deployment phasing, from proof of concept to full deployment. Note that the full deployment phase of this timeline spans 12 months, but may be accelerated depending on CPAU preference and budget. Figure 10: AMI Deployment Plan UtiliWorks recommends that Palo Alto undertake and document the following planning efforts at the appropriate time during the AMI project:  Project Execution Plan  Proof of Concept Implementation Plan  Test Plan  Change Management & Training Plan Page 36 of 84 © 2018 UtiliWorks Consulting, LLC  Communications (Public Relations, Education, and Outreach) Plan  Mass Meter Change-Out Plan  Field/Data Quality Assurance Plan The cost-benefit analysis, as presented, estimates a two-year deployment period that can be adjusted depending on project financing, resource availability and other variables specific to Palo Alto. The following sections describe UtiliWorks’ recommended deployment approach in more detail. A. AMI Proof of Concept Within the last few years, AMI as a technology has matured. There was a transition period from the time two-way communications with the meter was introduced. During this transition, utilities were more apt to explore AMI through a working “Pilot.” The intent was to test the technology to confirm it worked with the utility’s service area configuration/topology/meter population. UtiliWorks advises our clients to take a different approach to AMI design and deployment. Specifically, we recommend a “Proof of Concept” (POC) as a lead in to full deployment. The underlying philosophy of a POC Phase is to minimize risk and commit as little project funding as possible, while reaching basic system functionality as early as possible. This approach allows Palo Alto to work with each vendor to identify and address issues, to test the necessary interfaces with other systems, and to design, develop and test the future state business processes prior to full deployment. Based on our experience in deploying AMI technology, UtiliWorks recommends the POC be split into an Alpha and Beta phase. The intent of the Alpha Phase is to establish and test basic connectivity and a cross-section of the meter population in a controlled environment (i.e., meter shop). The goal, at a minimum, is to ensure connectivity between the meter, the collector(s), the AMI Headend and the MDMS. For a more comprehensive Alpha, you can go the extra step to integrate with a test instance of the CIS and produce a bill from automated meter data. UtiliWorks recommends the use of a dedicated meter test bench, if available, during Alpha. If not, a limited amount of metering hardware can be field-deployed during this phase if it is easily accessible for troubleshooting purposes. The team will also commence the work to deploy a limited number of collectors that are able to communicate with the Alpha meters. It is also advised that any work required to deploy the backhaul infrastructure is coordinated and completed during Alpha in preparation for the Beta phase of deployment. At this time, the vendors will install and configure the software, most typically the AMI headend and MDMS. The vendors will also meet with the Palo Alto team to gather the necessary software/configuration requirements. Systems integration requirements will also be captured. Interfaces that need to be in place for Alpha will proceed through design/develop/test. Beta interface design and development will proceed once Alpha is complete. Business process re-engineering can start in the early phases of Alpha. UtiliWorks suggests that Palo Alto map out the current state processes as soon as possible and overlap the mapping of future state business processes with the MDMS requirements/configuration. POC test plans and training plans will be produced by the vendors for Palo Alto to review and comment. It is advised that each vendor specify what will be required to satisfy Alpha and Beta, respectively. Page 37 of 84 © 2018 UtiliWorks Consulting, LLC UtiliWorks estimates a six-month Alpha phase. A “quality gate” or hold point is established at the end of the Alpha phase, with specific acceptance criteria that must be satisfied by each vendor thereby signaling completion. The Beta phase begins with field deployment of a pre-determined quantity of metering hardware and the remaining backhaul network infrastructure. Since the Beta phase cannot be entered without a successful completion of the Alpha phase, basic meter-reading and billing functionality is available immediately, allowing routes to be moved to automated billing immediately upon route acceptance (if desired). The balance of systems interfaces, included work order management, are developed and fully tested. If Palo Alto elects to use a third-party installation contractor, it will be necessary to configure and test the interface(s) with their work order management system. It is advised that this is completed prior to the Beta field deployment so to have an opportunity to troubleshoot and resolve issues prior to full deployment. If Palo Alto chooses to self-deploy, it will be necessary to assess the in-house work order management system and determine if configuration changes are required to support the full deployment. Business process changes are finalized and tested, so that they can also be debugged prior to a production deployment. This provides the users time to adjust to new processes and procedures and builds a familiarity with the new systems and methods to be employed. Additional functionality is added and tested in stages, with the goal to complete system integration and documentation activities prior to user training and system-acceptance testing. User training runs in parallel with the end of the Beta phase, typically beginning approximately two months before the end of Beta. The respective users/system owners and system administrators are trained on full use of the AMI Headend software, MDMS software, and Customer Portal. Much of the field training has been completed (OTJ – On the Job) for the Palo Alto staff, given the work performed during both Alpha and Beta. There is a comprehensive quality assurance (QA) effort that must be planned during the Beta phase. Beta is also the time to plan for parallel testing and the desired timing to “go-live” with AMI meter reads for billing. The Beta phase is complete with Palo Alto user acceptance of the entire system. This serves as the quality gate to move forward to full deployment. UtiliWorks estimates a six-month Beta phase. B. Full Deployment With all the planning, preparation, testing, and training complete, full deployment is managed more like a construction project in contrast to the POC. The assumption is that full-system functionality is available, with route acceptance to switch a meter from manual to AMI reads for billing. This approach has several advantages, including pushing back warranty start dates until functionality can be used, and the ability to realize the full benefit of deployed devices from the moment they are installed. Keys to project success include the accurate recording and timely delivery of serial numbers, out reads, various meter characteristics, geographic co-ordinates, digital pictures, and install notes to the appropriate departments and systems. Palo Alto staff must play an active role in monitoring data and equipment installation quality throughout full deployment. Page 38 of 84 © 2018 UtiliWorks Consulting, LLC Full deployment is estimated to take approximately one year with the use of a third-party installation contractor. C. Supplemental Technology In addition to updating IT infrastructure to leverage the data generated in an AMI system, Palo Alto has expressed interest in several technologies to improve efficiency. Given the strong push to enhance sustainability and reliability, Palo Alto will look at deploying Conservation Voltage Reduction (CVR) equipment/functionality, in conjunction with this project. UtiliWorks recommends that Utilities include this technology in the RFP and indicate intent to deploy during the Beta POC to leverage the AMI Communications network. The outcome of this testing will assist Utilities in the program design and conclude how best and when to deploy this technology across the system. Distribution automation refers to a wide range of hardware-software solutions that remotely sense and control service delivery. Distribution automation gives rise to outage location and automatic service restoration for electric service, and leak detection optimization for water service. By employing schemes to increase uptime, a utility may see benefits through reduced operating costs and increased revenue. These benefits, in turn, result in improve service quality and customer satisfaction. CVR is predicated on controlling the upstream voltage of a distribution circuit to conform to the low- end of a tolerance band set by the utility. Prior to this assessment, Palo Alto conducted an evaluation on CVR potential, with promising results. Although Palo Alto has a low base voltage (relative to other utilities), the City’s density and short primary feeders make CVR viable and financially-justifiable. Isolated testing of a Palo Alto transformer with three feeders could demonstrate a 0.5%-1% decrease in real power demand for a 1% voltage change, in accordance with industry findings. This change in power demand serves as the basis for the CVR program implemented in the cost-benefit conducted by UtiliWorks. For a comprehensive overview of CVR (and other AMI technologies), see Appendix E. 2. Implementation-Readiness Gap Analysis UtiliWorks has identified several factors that will help facilitate POC success. The team analyzed Palo Alto’s ability to meet these criteria based on current-state discovery and project planning done to date, and findings are itemized in Table 13: Implementation-Readiness Gap Analysis. Page 39 of 84 © 2018 UtiliWorks Consulting, LLC Table 13: Implementation-Readiness Gap Analysis Potential Gap Palo Alto State Designated AMI Project owner Palo Alto has a designated Project Manager and Project Sponsor, and it has identified key stakeholders and representatives from across divisions. A project manager position has been allocated to support deployment. Staff to support communications infrastructure Existing Engineering/SCADA personnel equipped to fill this role. Gas meter test bench Palo Alto possesses multiple gas meter test benches. All test benches are currently stationary, but the large meter test bench can be made mobile. A formal meter testing program is in place. This test bench is expected to support POC testing. Water meter test bench Palo Alto possesses a water meter test bench and has implemented a formal water meter testing program. Though Palo Alto noted unreliability for e-series meters, this test bench should be able to support POC testing. Electric meter test bench Palo Alto possesses an electric meter test bench that is calibrated annually; however, there is no formal testing program in place. This test bench is expected to support POC testing. Physical space/warehouse to support large scale deployment Utilities do not have adequate space available (approximately 2,500 sq. ft.) to host/stage deployment on its property and will have to lease a substantial area for deployment, capable of supporting worker parking, inventory storage, office space use, and disposal. Well-maintained gas meter characteristics in a database Yes, gas meter characteristics are maintained in SAP as the system of record. Well-maintained water meter characteristics in a database Yes, water meter characteristics are maintained in SAP as the system of record. Well-maintained electric meter characteristics in a database Yes, electric meter characteristics are maintained in SAP as the system of record. Out-of-the-ordinary gas meter access issues Some gas meters are in high-security areas that will require substantially higher than ordinary time to access due to the necessity of requisitioning an escort. Most curb meters are also difficult to access. Out-of-the-ordinary water meter access issues Some water meters are behind gates, but there are no other noteworthy access issues. Out-of-the-ordinary electric meter access issues Some electric meters are behind gates, but there are no other noteworthy access issues. Communications From experience with past projects, Palo Alto expects some push-back from the public on AMI RF, due to security, privacy, and health-related concerns, and will require outreach and education assistance. Staffing Electric operations and engineering currently expresses that current staffing is working at capacity, and additional AMI workload be untenable. CPAU would need to ensure that CIS implementation is successfully implemented and stable before embarking on the AMI implementation. This is very important to ensure staff resources are not stretched. See Section G for projected staffing- related project impacts. Integration Due to the number of overlapping IT and technology projects currently underway at Palo Alto, comprehensive identification of all integration points is key, which may be difficult depending upon IT workload. CIS stabilization will be critical to deployment of AMI. Page 40 of 84 © 2018 UtiliWorks Consulting, LLC Operational Impacts AMI technology has the potential to touch the entire organization. As the Utility transitions, there will be numerous operational impacts that require identification, definition and planning. The volume of data that will be available to Palo Alto will be substantially larger than the norm. This increased granularity and sheer volume of data is what opens new value streams, but these areas must be properly managed. Determining the operational impacts inherent to an AMI deployment is an extremely important process that can have material impacts on the realization of cost-benefit benefits. The operational impacts can be broadly categorized in the following areas:  Personnel/Human Resources  Business Process Re-Engineering  Data/Information Processing Some -benefits depend on a relatively quick deployment of features. For example, decreasing the time required to deploy AMI endpoints can accelerate the ROI. Even in the largest utility, rapid deployment can place tremendous strain on internal staff already dedicated to existing business functions. UtiliWorks recommends that Palo Alto actively engage staff from customer service to billing, engineering, IT, meter shop, operations/maintenance, and field services throughout the effort. Buy-in and support is needed from the top-down to ensure an efficient discovery process and smooth deployment. Staff augmentation is also a consideration given the added strain on resources already dedicated to existing business functions. In addition, the creation of a formal Steering Committee that meets periodically to address issues that are unresolved or blocked is critical, given the multiple participants and organizations involved. For a full description of tasks involved in Procurement through to Full Deployment phases, refer to the detailed staffing planning documents which include project task estimates. This was delivered to CPAU as an Excel workbook, titled “CPAU AMI Staffing Plan.” Each of these areas needs to be well defined to maximize ROI. The following sections will provide a high- level outline of the types of changes and planning that should occur within each area as Palo Alto moves forward with the project. 1. Personnel / Human Resources Based on UtiliWorks’ experience with the deployment of AMI technology and staff availability within CPAU, the following roles have been identified to facilitate project success:  Program Manager - The Program Manager will have on-going responsibilities as the “AMI Project” transitions into an “AMI Program.” This manager will ensure proper system oversight and that all QA functions are occurring as expected. The Program Manager will also keep his or her finger on the pulse of the AMI system at a global level, which includes benefits verification and tracking key performance indicators (KPIs) that may be monitored as part of future state operations.  AMI System Tech - UtiliWorks recommends the utility identify staff to fill the role of an AMI System Tech, along with a cross-trained backup. It is not necessary to hire to fill this role if utility can identify internal staff who are interested and capable of fulfilling the responsibilities. UtiliWorks recommends a resource who will work to understand the communications network, metering technology, systems and software to train and lead other staff members in daily use and oversight. It is best to include the people identified during project planning and deployment. Upon completion of deployment, the AMI System Tech will continue as a full-time staff member focused on identifying, troubleshooting, and dispatching staff to resolve issues in the field. Page 41 of 84 © 2018 UtiliWorks Consulting, LLC  Data Analyst(s) - UtiliWorks recommends utility identify staff to be dedicated as Data Analysts to support, administer and use the AMI and MDMS system data and reports. Like the AMI System Tech role, it is not necessary to hire to fill this role if the utility can identify internal staff that is available, interested and capable of fulfilling the responsibilities. It is also recommended that utility involve these team members throughout project planning and deployment so they are actively involved in the system configuration and training.  AMI Infrastructure O&M - New equipment in the field for network communications and AMI related equipment such as collectors and backhaul will need to be monitored and maintained. This is commonly performed by staff already responsible for the Communications network or SCADA and may be split between departments.  AMI Meter Tech (Gas) - Troubleshoot issues related to gas AMI meters in the field. This person should have extensive field experience at the utility, and the position can be filled from the Meter Technician team.  AMI Meter Tech (Water) - Troubleshoot issues related to water AMI meters in the field. This person should have extensive field experience at the utility, and the position can be filled from the Meter Technician team.  AMI Meter Tech (Electric) - Troubleshoot issues related to electric AMI meters in the field. This person should have extensive field experience at the utility, and the position can be filled from the Meter Technician team.  CVR Oversight - The Conservation Voltage Reduction (CVR) program will help CPAU monitor real-time voltage data and optimize voltage across the distribution network. Automated devices will be installed to ease the oversight and maximize the benefits of such technology; however, a 0.25 FTE is anticipated to be required for hardware and software oversight to maintain operations. Table 14: Palo Alto Staffing illustrates the project resource requirements assumed for purposes of the CBA. A total number of positions are presented by phase for Current, Deployment and Future State Operations, and these figures have been modified from the UtiliWorks suggested staffing to fit Palo Alto’s anticipated needs. Total costs for each position are derived from a base wage, plus benefits, with a 3.0% annual escalation rate. Page 42 of 84 © 2018 UtiliWorks Consulting, LLC Table 14: Palo Alto Staffing Note that AMI Meters Technicians are not called out as a separate line-item but have instead been bundled into traditional meter technician roles, whose positions will absorb additional responsibilities (as others decrease) as a result of AMI. Because Palo Alto’s meter readers are higher educated than those employed by other utilities, Palo Alto has expressed an opportunity to fill additional roles (Gas Meter Technician; AMI System Technician; Data Analyst; and AMI infrastructure Operations & Maintenance) from its current human resource pool as a first resort. Also note that the 0.25 FTE required for CVR oversight does not inherently necessitate CPAU create a new position to perform this role. CVR oversight duties may be absorbed by current engineering staff or contracted out entirely, pending further determination by CPAU. 2. Business Process Re-Engineering Advanced utility technology is highly integrated and especially sensitive to variances in the quality of data input, which requires adopters to practice strong discipline regarding data integrity and maintenance processes. Due to the potential for disruption of business processes by technology, Business Process Engineering should commence in the design phase of the project and continue through project completion following a continuous improvement process. Initial efforts during this Assessment to describe and quantify the current state business processes are a baseline for future business process re-design efforts. The gaps and pain points identified in the current state workshops Page 43 of 84 © 2018 UtiliWorks Consulting, LLC will provide an initial glimpse of how future state operations can be re-designed to meet the Utility’s needs. Adoption of AMI technology requires significant re-design of current utility business processes to fully satisfy acceptance criteria and expected payback. This exercise provides a common understanding of the business process it represents for all impacted stakeholders, no matter the level of technical expertise they possess. The process is also useful to capture and memorialize decisions made during the design and development of the AMI system. It is often overlooked in terms of how critical business process design is to the success of any project. Once fully developed, the documents can be used as training material for all internal and external resources involved in the business process. A. Impacted Core Business Processes UtiliWorks recommends that the following business processes, at a minimum, undergo a complete current state process definition and mapping to provide the basis for future state process design: 1. Meter Reading & Billing The meter reading process will be impacted the most of any business process in that it will require the development of an entirely new process. The management of the consumption data and its quality will become a daily responsibility. Resources will have to be assigned to monitor and manage exception reports to ensure the quality of the data that the billing function depends. The reassignment and training of resources will be crucial for the transition to a network based reading system. New processes will need to be developed for exception investigation and handling. The consumption validation process will change by having quality-assurance processes set up in the MDM system for meter reads before the CIS receives the meter reads for billing. The AMI and MDM systems will be used earlier on in the data flow to identify missing reads, investigate, and resolve issues. Billing will continue to run its quality assurance processes and will remain as the last line of validation against inaccurate bills going to customers. 2. Customer Inquiry and Response (High Bills) Assuming Palo Alto elects to implement a fully integrated Customer Portal, CSRs will be able work with customers to help them learn how to access detailed information on their own pertaining to bills, consumption and rates. Even without the deployment of a customer portal, the role of the CSR will move toward education and coaching, which will pay dividends for both the Customer and the Utility over time. 3. Single Meter Change-out/Retrofit After deployment of the metering project, Palo Alto will need to adhere to proper process and procedures to maintain data integrity within the systems. Single meter exchanges, new installations, and retrofits will include additional data tracking which will require workflow alterations. 4. Move In/Move Out CSRs will be able to provide a higher level of customer service by scheduling the start and stop of service for customers. Remote meter reading and disconnect/connect capabilities will allow CSRs to capture the out/in read and disconnect/connect electric service with the push of a button. Existing business processes will need to be maintained along with development of new processes to manage remote reads. Decisions and permissions will need to be set up to support the personnel who will be authorized to perform this process from the office. 5. Service Disconnect for Non-Payment Like the changes in Move-In/Out, CSRs will have the ability to use the capabilities of the system to remotely disconnect/connect service for non-paying customers. Process and Page 44 of 84 © 2018 UtiliWorks Consulting, LLC policy development will be required to determine the best methodology for performing this activity, the workflow alterations, policy shifts and any other changes will be required for the process. B. Policy Considerations There are several policy impacts that CPAU should consider as they undertake a business process re- engineering initiative related to the AMI deployment. Many changes will affect internal policies, which do not require changes to official Rules and Regulations, but do require consensus from those in the organization. In addition to the internal changes, there are others that will likely require changes to official Rules and Regulations. CPAU estimates that it could take up to six to nine months to make changes, and as such, should begin assessing these policy impacts as soon as possible. Some policies will not be able to be fully defined until systems are selected and BPR future state sessions have taken place. This exercise will help inform which direction the policies will shift. Specific policies that may be impacted include:  RR09 – Discontinuance, Termination and Restoration of Service Procedures for CPAU-Initiated Termination of Service – Review the procedures and include anything applicable to remote disconnect for electric meters. CPAU may also consider remote disconnect for water meters. These policy changes will coincide with business process changes around whether to allow same-day and after-hours disconnects/reconnects.  RR10 – Meter Reading Billing Period – CPAU will revisit the billing period of 27-33 days during re-engineering of business processes. If desired, this window can be condensed with AMI reads available daily. Also, abnormal conditions and bill estimation techniques may change with AMI/MDMS systems in place. These cannot be fully determined until selection has taken place. CPAU must also consider whether the “Customer Reads Own Meter” Program; will this program continue under AMI?  RR11 – Billing, Adjustments, and Payment of Bills Theft of Service – The language in this section is a great start, but should be reviewed. See Meter Seals section under RR15. Leak Credits – There is clear language that leaks beyond the meter are the customer’s responsibility. However, CPAU may consider including additional language about automatic leak alerts or proactive notification by Customer Service whenever a leak event seems likely.  RR15 – Meter Installation Meter Seals – There is a solid definition of and language to enforce tamper and theft scenarios in the current rules and regulations. However, this should be reviewed to make sure all cases are properly accounted for. This could include cost to replace certain new AMI materials, such as endpoint-only for water meter. CPAU may choose to add specific definitions of tamper, theft and illegal consumption.  Meter tamper (unauthorized interference with equipment, e.g. cut lock)  Meter theft (illegal use of electricity, water or gas, e.g. bypass)  Illegal consumption (no account tied to consumption, e.g. new customer). Also, CPAU can choose to set increasing charges based on repeat incidents of theft or tamper. Page 45 of 84 © 2018 UtiliWorks Consulting, LLC Meter Tests – Current rules and regulations state that all meters will be tested prior to installation. This policy may need to be changed for mass deployment, which often rely on factory meter accuracy tests, rather than testing all new meters. This policy is only indicated for electric meters currently. Also, CPAU should increase the meter-testing fee and consider implementing a maximum number of meter tests allowed per customer per year (or per service lifetime). Both changes can be justified, since inaccurate meters and testing is expected to be reduced with daily meter read data now readily available to the utility staff and customers.  New Policy for “Opt Out” Program - CPAU should consider eligibility for this program, who will administer it within the Utility, charges to be applied for meter reading activity, charges for meter replacement of a new customer moving into an AMI-equipped premise, charges/program eligibility for disconnect for non-payment. 3. Data / Information Processing and Reporting It is important to focus on the data and information that will be captured by the AMI system and stored in the MDMS to make the most of the investment. Decisions regarding what to do with the resulting expansion of data available to Utility staff is a key driver regarding the design and configuration of the system. Both the AMI and MDM systems will offer more robust exception, troubleshooting, and diagnostic reporting options, along with alarms and alerts. However, it will be necessary for Palo Alto to invest the time and effort up front to clearly define business requirements and understand the respective reporting capabilities of each system to maintain a manageable workload. The AMI system will provide expansive amounts of data that must be converted to useful information, or business intelligence, before it can be meaningfully used by CPAU. To fully use this functionality, it is important to define the integrations, especially with the CIS and the GIS, which facilitate business intelligence to support CPAU goals and strategic direction. Business intelligence reports also need to be specific to the users’ needs, and they, for the most part, do not come out of the box. They need to be developed with the tools provided by the MDMS. The ability of individuals users to use these tools to build the strategic information needed will vary within departments and sometimes a “superuser” resource is needed to facilitate report customization. As part of a procurement process, UtiliWorks recommends that Palo Alto investigate thoroughly the underlying data retention, notifications, reporting and alarm functionality of all considered systems, request for samples of any preconfigured reports, and verify that the system will facilitate customized development at the user level, if so desired. Page 46 of 84 © 2018 UtiliWorks Consulting, LLC Change Management & Communications 1. Change Management A "one-size-fits-all" approach is not effective for Change Management. Every new project has a distinctly different scope for change, with varying impacts to stakeholders. UtiliWorks employs the basic Change Management approach depicted in Figure 11: Change Management Approach. As part of an onsite exercise in November 2017, UtiliWorks met with the CPAU project team to discuss the aspects related to developing a Change Management strategy. Figure 11: Change Management Approach The November 2017 Organizational Impacts onsite workshop included dialogue on change scope, readiness of the organization, stakeholder analysis, and internal messaging for the project moving forward. In large part, implementation has been driven by interest from the Palo Alto community, with the expectation that Utilities is forward-thinking and technologically-progressive. However, there has been some criticism as to the relatively late adoption AMI. To alleviate resource constraints and mitigate risks associated with too radical a change, the AMI/MDM system is not scheduled to begin deployment until Q4 2020 due to the impact of other projects as outlined in Section D. The staff at Palo Alto is largely well-informed about the upcoming implementation of the AMI project. Though Utilities already started to implement other technologies, such as a customer engagement portal, CIS and ERP, an AMI/MDM system is needed to realize the full potential of current and future projects. 3. Supporting Change Implement Corrective Actions and Reinforcement Review Change Management Plan 2. Administering Change Establish Change Plan Manage Communications Plan Administer Training Respond to Resistance 1. Priming for Change Assess Change Scope & Objectives Evaluate Readiness of Organization Conduct Stakeholder Analysis Develop Key Change Messages Page 47 of 84 © 2018 UtiliWorks Consulting, LLC The implementation of AMI poses substantial change for Utilities. Operationally, Palo Alto’s data stream will grow from 12 reads per meter per year to over 8,760 reads per meter per year, affecting not only individual departments, but the public generally. For some departments, which are well- keyed-into the ongoing project planning process, the changes that come with AMI implementation will be expected, and negative consequences or potential risks will be substantially mitigated. For other groups, such as the meter readers whose current responsibilities will be phased out, the operational impacts will represent radical change, especially if there is an inability to meet new staffing needs dues to a skills gap. Palo Alto possesses relatively higher-educated staff than other utilities—both academically and professionally. Most meter readers are tech-savvy, with at least an associate’s degree, which positions them to make the switch to AMI-related positions. In addition, a number of those persons working in Customer Support/Administration/Resource Management have been involved with the Palo Alto pilot smart meter program. Customer Support is already accustomed to using multiple applications aside from CIS as a part of daily operations and would likely readily adopt additional Customer Portal and MDMS software into their current workflow. To manage concerns and expectations of the upcoming changes, Palo Alto management has expressed a need for clear and concise messaging that AMI will enhance and empower employees to more effectively perform their roles. Palo Alto has identified three primary stakeholders moving forward—the AMI/MDM project team; UAC and City Council; and the Palo Alto community—all of whom have substantial buy-in to the project. A small, but vocal resistance is expected within the community once deployment begins. However, Utilities plans to offer educational town halls and an “opt-out” option from the AMI program to address this group’s concerns. UtiliWorks emphasizes that identification of stakeholders’ needs and leveraging their influence is invaluable to project progress. To prime stakeholders for change, the Palo Alto team has developed a few key change messages, which communicate the vision for AMI implementation and the future of Utilities:  On AMI & CPAU Strategic Direction: CPAU must invest in technology to enable customer adoption of new technology applications and improve operational efficiency. CPAU will utilize AMI as a foundational technology for operations as it continues to invest in value-add projects for the customers it serves.  To Meter Readers: Meter Readers will be provided with opportunities to cross-train with Meter Technicians, Field Service Representatives and Customer Support to explore new career paths.  On AMI Project Timing: AMI project must be carefully sequenced around CIS and ERP deployment to minimize disruption to operations and maximize benefits from the AMI infrastructure. 2. Communications Communications planning will become increasingly important, both internally and externally, as the AMI project progresses. CPAU has a dedicated Communications Manager who is also involved in the Strategic Planning initiative currently underway. The AMI project planning team should continue to check-in with the communications group to ensure all CPAU communications are on point. The majority of project-related communications planning is not expected to occur until the procurement phase is underway in 2019-2020. However, the stakeholders identified and key messages developed as part of initial Change Management preparations should be used to help inform internal messaging between now and the beginning of procurement. See Section H.1. Page 48 of 84 © 2018 UtiliWorks Consulting, LLC Recommendations 1. Recommendations As a “next step” for this project, UtiliWorks has presented the following recommendations to CPAU: 1. Based upon the cost-benefit analysis outcome and readiness assessment contained in this report, CPAU recommends seeking approval for AMI investment. 2. If approved, CPAU will proceed with Phase 2 (Procurement) for the AMI project. UtiliWorks will stay engaged with CPAU to assist with the system specifications and procurement process. 3. Deployment preparations should follow the AMI Implementation Plan and Technology Roadmap presented in Section F and Section D, respectively. Activities include refinement of the CPAU staffing plan, development of requirements specification, and completion of CIS data cleansing and meter audit. 4. During deployment planning, UtiliWorks recommends that Palo Alto undertake and document the following planning efforts at the appropriate time during the project: a. Project Execution Plan b. Proof of Concept Implementation Plan c. Test Plan d. Change Management & Training Plan e. Communications (Public Relations, Education, and Outreach) Plan f. Mass Meter Change-Out Plan g. Field/Data Quality Assurance Plan. 5. UtiliWorks recommends that the Utilities Technology Roadmap be reviewed and revised on an annual basis by the Utilities IT team to assess project progress and reprioritize Utilities projects. A full reassessment should be completed after five years. Page 49 of 84 © 2018 UtiliWorks Consulting, LLC Appendices Appendix A – Project Risk Register PALO ALTO SMART GRID RISK MANAGEMENT LOG Project Name: Smart Grid Assessment Project Manager Name: Kara Truschel ID Current Status Risk Impact Probabilit y of Occ. Risk Map Risk Description Project Impact Risk Type Threat / Opportunity Risk Response Mitigation & Response Strategy Description Implementation Phase 1 Open Medium Low Green Insufficient project funding Could lead to project delays or work stoppage. Grid modernization is capital intensive and faces problems imposed by the utilities’ constrained balance sheets. Budget Threat Avoid Pursue grant opportunities through California Financing Coordinating Committee (CFCC), Department of Energy (DOE), Department of the Interior (DOI), and United States Bureau of Reclamation (USBR). 2 Open High Low Yellow A lack of public awareness and education concerning the AMI program Could lead to some public concerns and hostility within the community. Customer buy-in is extremely important for an AMI/MDM system. Community Threat Mitigate Launch a public awareness campaign to build support within the community and educate consumers on AMI/Smart Meter technology. Consumer education is needed regarding the merits of AMI and the societal benefits of grid modernization. If appropriate, host town halls to engage the customer community at grass-roots level. 3 Open High Low Yellow Poor community engagement/opt-out program planning/customer opt-out first and ongoing costs This risk poses a threat to the perceived value and success of the project. Community Threat Mitigate Well-defined communication and stakeholder management plans will be critical to success and the control of this risk. Risk response plans for a variety of potential scenarios are recommended. Page 50 of 84 © 2018 UtiliWorks Consulting, LLC 4 Open Medium Medium Yellow Customer concerns of EMF safety and privacy This risk poses a threat to the customer confidence and sentiment regarding the implementation of an AMI system. Community Threat Mitigate The stakeholder and communication management plans must address these enterprise environmental factors to mitigate this risk and allay fears the customer community may have regarding these details. Opt-out program will be offered. 5 Open Medium Low Green Lack of customer- specific FAQs and CPAU contact information for all subjects related to their new AMI service This risk poses a threat to the perceived value and success of the project. Community Threat Mitigate This risk is somewhat similar and related to Risk ID #3, in that communication and stakeholder management are keys to controlling this threat. Risk response plans for a variety of potential scenarios are recommended. 6 Open Low Low Green Lack of meter maintenance/meter reading plan for opt- out customers This risk of alienating customers, who may already be reticent to "buy in" to the "new" AMI technology. Loss of customer confidence would be a concern. Community Threat Mitigate This risk is somewhat similar and related to Risk ID #3 and #5. One meter reader will remain to perform manual reads. 7 Open Medium Low Green No identification of staffing and other resource requirements needed to continue to provide non-AMI meter reading services to opt-out customers This risk of alienating customers who may already be reticent to "buy in" to the "new" AMI technology. Loss of customer confidence would be a concern. Community Threat Mitigate This risk is somewhat similar and related to Risk ID #3, #5 and #6. This risk can be mitigated by identifying and planning for staffing and other resource requirements needed. Risk response plans for a variety of potential scenarios are recommended. Page 51 of 84 © 2018 UtiliWorks Consulting, LLC 8 Open High Medium Red Poor re-engineering of business processes, documentation and training This risk poses a threat to the perceived value and success of the project. Organizational Change Management Threat Avoid 1) A continuous improvement project should be written into the AMI implementation program to provide post live auditing of business processes and knowledge transfer to ensure the complete utilization and maximize the benefits of the technology investment. 2) Including a PM with AMI implementation experience can reduce the probability of developing poor processes and training. 3) Institute a Change Management Plan. 9 Open Medium Medium Yellow Shifting politics and organizational changes Could disrupt project progress or halt it altogether. Overlapping federal, regional, state, and municipal agencies sometimes create an impediment. Organizational Change Management Threat Accept 1) Build support from neighboring utilities, City Council, and Utility Boards. 2) Participate in AMI industry workshops and conferences to stay abreast of best practices and industry standards. Page 52 of 84 © 2018 UtiliWorks Consulting, LLC 10 Open High Medium Red Ongoing or upcoming infrastructure projects may compete for resources Competing projects/departments may require the same SMEs or project leads. Resources Threat Mitigate 1) Dedicate a Project Manager within the organization to keep the project on track and escalate any resource issues. Dedicate a Project Sponsor within the organization to work with and assist the PM with internal politics and to escalate any resource issues. 2) Establish a Steering Committee to provide the project team with an escalation point for issues that are unresolved or blocked. 3) Minimize the large team meetings to only include kickoff, major review sessions, final presentations, and training to avoid burnout from too many meetings. 4) Dedicate one key process owner for each of the following functions: billing, customer service, IT, meter reading, field support, and operations. This resource should be experienced, available for individual deep-dive sessions, and able to participate in the project from beginning-to- end. 5) Perform Annual Review of the Technology Roadmap to ensure that project needs don't overlap and precedent projects stay on schedule. 11 Open High Medium Red Poor staff engagement/ communication and lack of focused change management plans/ implementation This risk has the potential to cause delays to the project schedule if not addressed. Resources Threat Mitigate This risk is somewhat related to Risk ID # 13. Well-defined communication and stakeholder management plans will be critical to success and the control of this risk. Risk response plans for a variety of potential scenarios are recommended. Page 53 of 84 © 2018 UtiliWorks Consulting, LLC 12 Open High High Red Lack of adequate warehousing and receiving space for deployment This risk poses a threat to the deployment pace desired by CPAU. It is anticipated no suitable facility will be provided by CPAU. Resources Threat Transfer This risk can be mitigated during the Procurement Phase through incorporation of a requirement that vendors identify their own warehousing and storage space. Transferring the risk to a third- party installation contractor will increase the overall cost of the project. 13 Open High Low Yellow Lack of project team and internal stakeholder buy-in Could lead to project delays, cost overruns, and project failure. Resources Threat Mitigate 1) Leadership should demonstrate a strong understanding of project goals and develop an “elevator pitch” that shows project support. 2) Internal project staff should be fully educated on the technical components of an AMI system and undergo thorough training prior to the Go-Live date. 14 Open High Low Yellow Insufficient staffing to deploy and integrate systems This risk has the potential to cause delays to the project schedule if not addressed. Resources Threat Mitigate Resource requirement planning and projections must be well- defined and a component part of risk analysis to avoid this threat. 15 Open High Medium Red Cost overruns due to unforeseen deployment risks Cost overruns can contribute to a variety of undesirable results including schedule delays and loss of both internal and external stakeholder confidence which are difficult to rebuild and recover from. Schedule Threat Accept 1) Rigorous project risk management must be applied to identify, analyze, and plan responses for all known risks to reduce to the degree possible the amount of unforeseeable risks that might be encountered during the monitor and control phase of the project. 2) A possible risk response strategy is to plan a management reserve or contingency budget for areas of concern. 3) Including a PM with AMI implementation experience can reduce the amount of unforeseen deployment risks. Page 54 of 84 © 2018 UtiliWorks Consulting, LLC 16 Open High Medium Red Ill-defined contracts lead to improper level of configuration, or missing integrations This risk poses the potential for significant impacts to project scope, schedule, and budget resulting in a variety of undesirable issues. Scope Threat Mitigate Project scope and procurement management planning will be critical to mitigating risks that will increase scope and project duration after implementation and installation has begun. The components of these two plans must be well-defined. 17 Open Medium Medium Yellow Meter pits/lids in poor condition or undersized, preventing installation Failure to address this risk when scoping the project would result in the need for a change request to expand scope during the installation phase and would increase the budget and schedule of the project Scope Threat Mitigate 1) Accurately defining hardware requirements will be critical to mitigating the risk of change requests during the installation phase of a project leading to delays. 2) Meter survey will help inform pit and lid replacement strategy. Meter lid replacement will be in scope for AMI project. 18 Open Medium Low Green Overlapping deployment of IT projects leads to inadequate identification of all integration points with AMI/MDMS This risk has the potential to cause delays to the project schedule if not addressed during the planning phase of the project. Scope Threat Mitigate 1) Accurately defining integration requirements will be critical to mitigating change requests during the implementation phase of the project leading to delays. Scope definition and management are key and will begin during the Procurement Phase. 2) Including a PM with AMI implementation experience can reduce the amount of unforeseen integration risks. 19 Open Medium Low Green Lack of AMI meter testing plans, schedules, protocols and customer charges Failure to address testing, schedules, and protocols would result in a critical failure and must be spoken for in risk analysis. Scope Threat Mitigate The planning for quality management as it relates to testing activities will be critical to the mitigation of issues that can arise when not thoroughly testing systems. Scope definition and planning are key. Page 55 of 84 © 2018 UtiliWorks Consulting, LLC 20 Open Medium Medium Yellow Lack of customer notification plan for cybersecurity breach This risk poses a threat to customer confidence and sentiment regarding the implementation of an AMI system. Security Threat Mitigate 1) This risk can be mitigated by developing a customer notification plan for a cybersecurity breach. Process to be developed and incorporated into Rules and Regulations changes. 2) The stakeholder and communication management plans must address this public relations threat to mitigate risk and potential loss of customer confidence. 3) Coordinate with City IT to inform planning on this risk. 21 Open High Medium Red Incorrect/incomplete meter data in CIS for mass meter deployment Could lead to inaccurate vendor proposals/pricing, and eventually cost overruns and delays. Technology Threat Mitigate Plan and implement CIS data- cleansing and meter surveys prior to AMI procurement. 22 Open High Medium Red Poor system integration to existing and future applications (i.e. GIS, ERP, CIS, Asset Management) Attention must be given to this critical requirement to prevent high costs, delays and the risk of incompatible technologies in the future. Technology Threat Mitigate Requirements gathering, planning, and procurement management will be key to mitigate the potential for system and technology incompatibilities. 23 Open High Low Yellow Existing customer meter incompatibility with AMI communication module selected (mainly related to water and gas meters) Will require full meter replacement. Technology Threat Mitigate Meter changeout should be pursued for all locations that do not have AMI-compatible encoder register. Full electric meter replacement anticipated. Page 56 of 84 © 2018 UtiliWorks Consulting, LLC 24 Open Low Low Green Immaturity of technology (e.g. new meter types such as ultrasonic/electronic water meters) Choosing immature technology can lead to issues that may not be fully understood by the vendors supplying these software and hardware materials. Technology Threat Mitigate Exposing the utility to the risk of immature and unreliable technology must be considered when balancing reliability and future proofing in the technology selection process. This risk should be mitigated by thorough and rigorous research into the available technologies to support well-informed selection decisions during Procurement Phase. 25 Open Medium Low Green Improper equipment specification/selectio n leading to operational and/or billing problems The impact of improper hardware or software selection would negatively impact the project cost and schedule. It has the potential to negatively impact project team morale as well. Technology Threat Mitigate Requirements gathering and procurement management will be key to mitigate the potential for improper equipment selection. Post-Implementation Phase 26 Open High Medium Red Lack of Council- approved policies and protocols to effectively respond in a new technology environment (e.g. billing disrupted through a cyber- attack, cyber hack that results in remote turn-off of customer meter) Could lead to some public concerns within the community. Protecting customers from the exposure of unwanted impacts from the implementation of an AMI/MDMS system must be treated with a very high priority. Community Threat Mitigate The creation or revision of policies related to day-to-day operations should be identified during business process design and development. These policy requirements must be treated with sufficient urgency and priority to ensure that they're approved by the time the impacted processes are ready to be released to the production business environment. Revisit on an annual basis. 27 Open Medium Medium Yellow Poor utilization of data supplied by AMI headend and MDMS This risk poses a threat to the perceived value and success of the project. Organizational Change Management Threat Avoid A continuous improvement project should be written into the AMI implementation program to ensure complete utilization of the technology investment. Page 57 of 84 © 2018 UtiliWorks Consulting, LLC 28 Open Medium Medium Yellow Failure of delivery/realization of cited benefits and functionalities This risk poses a threat to the perceived value and success of the project. Organizational Change Management Threat Avoid A continuous improvement project should be written into the AMI implementation program to provide post live auditing of business processes and benefits verification to ensure the complete utilization and maximization of the technology investment. 29 Open High Medium Red Technology obsolescence and vendor instability over project life cycle Changing vendors of the type and variety required for an AMI project could cause major disruption to cost, schedule and quality. Resources Threat Mitigate This risk can be mitigated through a careful vendor selection process. This risk should be mitigated by thorough and rigorous research into the vendors to support well-informed selection decisions during Procurement Phase. 30 Open High Low Yellow Inadequate resources to support the ongoing operations, maintenance, and data analytics of the AMI system With the implementation of AMI, there will be new tasks related to system monitoring, reporting, and exception handling. It is expected that a dedicated technical resource that is familiar with Palo Alto processes will be required for this work. Additional resource(s) may be required to support the data analytics for both the water and electric departments. Resources Threat Avoid 1) Hire or reallocate technical resource(s) to the AMI project. Failing to build and/or attract the needed technical talent would be a barrier to the full realization of system potential. 2) Revisit operational staffing plan on an annual basis. 31 Open Medium Medium Yellow Cost overruns related to maintenance and staffing for operational support Cost overruns can contribute to a variety of undesirable results including loss of both internal and external stakeholder confidence, which is difficult to rebuild and recover from. Resources Threat Mitigate Resource planning and management will be key to mitigate the potential for cost overruns. Page 58 of 84 © 2018 UtiliWorks Consulting, LLC 32 Open Medium Medium Yellow Data encryption and cyber security risks The risk of insufficient cyber security protection in new systems being implemented has the potential to cause unplanned costs and project delays as well as loss of customer confidence and sentiment. Security Threat Mitigate Requirements gathering, planning and procurement management will be key to mitigate the potential for system and technology security vulnerabilities (AES 256-bit encryption). 33 Open High Low Yellow Inability to manually read meter routes if the AMI system should go down As meter data collection is a critical function, any issue here must be mitigated. Technology Threat Mitigate 1) System design will be key to durability and resilience which will reduce the need to manually read meters. A well-planned risk response regarding any potential threat should be prepared. 2) Decide what the alternative data collection method would be in event of a failure (i.e., drive-by or manual collection) and choose a relevant AMI system that supports the alternative method. 3) Include in warranty language for contract(s). 34 Open High Low Yellow Inability to use AMI data and existing rates to calculate debits, credits, and charges in the billing system The inability to use AMI data for these critical-to- success business requirements would be perceived as a failure of the project and the investment. Technology Threat Mitigate The selection of a compatible AMI system that can be successfully integrated to the CIS system is key to controlling this risk. 35 Open High Low Yellow Inability to update software and/or firmware for meters and ancillary equipment over the air Inability to update software or firmware over the air has the potential to cause significant costs in the future and reduce or limit product lifecycle. Technology Threat Mitigate Requirements gathering, planning, and procurement management will be key to mitigating the potential for the reduction in the utility's ability to "future proof" its technology investments. Page 59 of 84 © 2018 UtiliWorks Consulting, LLC 36 Open Medium Medium Yellow Inaccurate connectivity/distribu tion models and GIS data prevent full AMI capabilities from being utilized This risk poses a threat to performing timely meter work and can lead to confusion in field activities. Technology Threat GIS project scope should encompass defining asset relationships in GIS (such as meter to transformer, and meter to pressure zone) so that full AMI analytics may be utilized. Page 60 of 84 © 2018 UtiliWorks Consulting, LLC Appendix B – Current State Operations For the purposes of this report, current state operations data that was discovered during the initial stages of this assessment is categorized and presented in a narrative format herein. This data served as the background for this assessment and is presented to provide a holistic, rather than technical, overview of operations at CPAU. 1. Meter Reading & Field Services The City of Palo Alto services over 30,000 electric connections, over 20,000 water connections, and over 24,000 gas connections. There are formal meter-testing programs in place for both water and gas meters, but none for electric meters. Utilities have a replacement program in place for gas meters and small (2” and under) water meters, following AWWA/AGA standards of a 17-20-year replacement cut-off. Larger water meters are not slated for replacement, but most deployed units have been monitored and calibrated appropriately. In general, meter technicians maintain and install all meters, excluding large water meters, which are serviced by a combination of contractors and city crew. Customer Support Services oversees the meter readers, while the Water-Gas-Wastewater operations group oversees the field service personnel that address meter-related issues. The Utility service area covers approximately 25 square miles. There are 17 reading cycles and 109 routes. Between 3,000 and 4,000 meters are read daily by six regular and three temporary meter readers, using nine vehicles consuming unleaded gas. In addition to the meter readers, there are other personnel that support the meter reading process—among these, one lead customer service specialist, six customer service representatives, two customer service specialists and two credit and collections specialists. Meters are read on a formalized schedule, every business day, using Itron FC300 handheld units to interface with Itron FCS and Itron MCLite reading systems. A small proportion of the customer base (approximately 700 customers) participates in a self-read program. Meter-reading exceptions are triggered in the billing system by one of several flags: zero consumption, meter roll-over, higher-than-expected read, or lower-than-expected read. Customer service will then review the read, send a service order to the meter reader, and manually enter a corrected value into the system the following day. For the case of move-out, only electric service is terminated, while water and gas service is left on. Only after usage is detected will the remaining services be switched off. In the case of delinquency, service will be terminated after notification of a door hanger notice. These turn-offs can take place on any business day and are scheduled. Same-day turn-on is offered, except for Fridays and days preceding a holiday. Service Notifications for the services enumerated above are handled via SAP. 2. Billing The CIS system and meter-to-cash billing process is supported by six full-time equivalents consisting of one project coordinator, two business analysts, two senior business analysts, and one principal business analyst. The number of days in a billing cycle ranges from 27-33 days. It usually takes two business days from the time the meter is read to when a bill is generated, and bills are printed daily. Bills are seldom estimated, except in the case of meter damage or inaccessibility. Re-reads are flagged in the system and prompt manual investigation, requiring a customer service specialist to review usage history, Page 61 of 84 © 2018 UtiliWorks Consulting, LLC before a service notification is generated to dispatch a meter reader to confirm the read. Precursory exceptions are outlined in the previous subsection. Utilities customers have 20 days to pay their bill from the day of invoicing. If payment is not remitted, Utilities will mail a delinquent notice to the customer 10 days following the bill due date. After 13 additional days, a service disconnect may occur. For service disconnects, Palo Alto notifies customers via a door hanger 48 hours prior. If Utilities detects water or gas usage after electric disconnect, Palo Alto will disconnect water, but is required to leave a door hanger notice prior to disconnection, in compliance with the California Health and Safety Code. Gas is never disconnected. For these disconnects, a manual disconnection notice must be created by staff and sent to field service. Billing assesses late fees of 2% of the total bill, with approximately $279,000 in late fees collected in fiscal year 2016. 3. Customer Service Utilities customer service is staffed by eight customer service representatives (one of whom is part- time), two customer service specialists, and two lead customer service specialists, responsible for setting up accounts, responding to inquiries, and providing account maintenance. Though Utilities no longer tracks call type, a holistic estimation of the top three call topics includes: 1. High bill 2. Move-in/move-out 3. Efficiency advice The average call length is three minutes, 45 seconds. In addition to calls, Utilities offers a walk-in service for customer inquiries, which assists about 3,600 customers per year. In addition to traditional billing, customers can submit payments via walk-in, over-the-phone, interactive voice response system, or My Utilities Account web portal. The customer portal supports one-time credit card and recurring bank draft payments. Approximately 18,000 customers are actively registered, and though distinct logins are tracked, no other metrics are available. The web portal allows customers to view statements online, view payment and usage history, process one- time credit card or recurring bank draft payments, and manage billing notifications. 4. Electric Meters/Meter Shop The electric meter shop purchased a WECO meter test bench in 2014. This system is calibrated annually. To date, no formal periodic meter testing and/or replacement program has been implemented for electric meters. Meters are tested and calibrated (only mechanical meters are calibrated) when removed from service if they are to be reused. The estimated lead time when ordering new meters is six to eight weeks, and there is no preferred make or model. Upon receipt of meters from a supplier, about 10% are tested before installation. Palo Alto has neither the space, equipment, nor manpower to facilitate AMI deployment and will require vendors to locate off-site staging and warehousing. Utilities has expressed interest in using in-house personnel to deploy commercial and industrial meters, however. UtiliWorks reviewed and analyzed the electric meter inventory (summarized in Table 15: Electric Meters by Type) to populate the cost-benefit model with an accurate count of meter replacements. Page 62 of 84 © 2018 UtiliWorks Consulting, LLC In addition, we review the meter population to identify exceptions or anything that would be useful so that a proposing vendor can provide a more accurate response to an RFP. Table 15: Electric Meters by Type Electric Meter Type Count Single Phase - 1S w/ Remote Disconnect 110 Single Phase - 2S w/ Remote Disconnect 19,806 Single Phase - 2SE 695 Single Phase - 3S 81 Single Phase - 4S 3 Single Phase - 9S 1 Poly Phase - 5S, CL20 80 Poly Phase - 9S (8S), CL20 991 Poly Phase - 12S, CL 200 w/ Remote Disconnect 7,131 Poly Phase - 16S (14S, 15S), CL200 1,178 5. Electric Operations Power is supplied to the city by Western Hydro, NCPA Hydro, solar, wind, and LFG. CAISO serves as the transmission provider, and all marginal power supply is bought and sold through the CAISO market. The average load factor of the distribution system is approximately 63%, with a downward trend since 2000. The system peak demand is 170-175 MW, with 940 GWh having been billed in 2016. Utilities maintain 304 miles of electric lines across Palo Alto, with 96 service connections per line mile. Utilities also maintain (but does not own) streetlights throughout the City. Average annual line losses are estimated at 3%. The electrical system interfaces with an outage management system (OMS) that indirectly predicts outages by phone call logs. A geographic information system (GIS) system is also used to map equipment for OMS and maintenance, as well as distribution facilities. The Supervisory Control and Data Acquisition (SCADA) system in place controls a series of nine substations across the city. In its current design, Utilities has no control over substation voltage from the control center, nor does it have the ability to control individual phase voltage on feeders, voltage regulators, or capacitor banks. These functions can only be controlled at the substation- level. Utilities currently has an opt-in demand-side management program in place, with enrollment numbering in the hundreds and savings achieved of .44%-1.31% over the past decade. 6. Water Meters/Meter Shop Utilities makes use of a water meter test bench and a mobile test platform that is two years old and capable of testing meters 2” and smaller. Utilities has expressed interest in drought management tools, virtual metering, and remote shut-off for parks and irrigation meters. UtiliWorks reviewed and analyzed the water meter database to populate the cost-benefit model with an accurate count of meter replacements versus meter retrofits. Less than half of water meters at Page 63 of 84 © 2018 UtiliWorks Consulting, LLC Palo Alto will be greater than 20 years old prior to deployment. A summary of meter types by install date is shown in Table 16: Water Meter Types by Age. Table 16: Water Meter Types by Age Pre- 2002 200 2 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 1" 1,272 71 70 76 69 64 202 171 163 174 274 196 221 153 142 134 61 5/8" x 3/4" 5,670 324 281 302 374 268 546 515 1,236 1353 1728 732 791 418 240 80 36 Hydran t 29 20 5 2" 383 40 14 16 24 19 26 29 23 45 37 30 24 50 42 29 6 1-1/2" 277 19 13 15 28 17 34 28 30 63 31 11 14 21 27 26 7 3" 37 4 2 3 3 6 2 4 2 8 6 12 2 1 1 4" 32 4 1 2 2 1 2 2 1 2 3 7 2 4 3 2 6" 20 1 1 2 1 2 1 2 3 2 8" 6 2 2 3 2 1 3/4" x 9" 364 3 5 3 3 2 2 5 1 3 31 15 21 2 2 In addition, we reviewed the meter population to identify exceptions or anything that would be useful so that a proposing vendor can provide a more accurate response to an RFP. The radio device that is the means of communication with the AMI network is a separate piece of equipment that must be connected to an encoded register. This allows a utility to keep the existing meter body and replace a register only if it is not currently compatible with AMI. 7. Water Operations/Water Conservation Palo Alto’s water is stored in five above-ground and two below-ground storage tanks. The total distribution storage capacity is 13.5 million gallons. Distribution of water across the 236 miles of water mains is facilitated through nine water pressure zones, with seven pump stations. Operational technology is overseen through a SCADA system, with pressure monitoring capabilities at all pump stations. In addition, SCADA is capable of monitoring and controlling PRV zones, tower levels, and pump pressure. The distribution system is metered via SFPUC transmission meters, but these meters have not been calibrated since inclusion within the system. A calibration plan will be implemented for all service meters by 2019. In 2016, 86 total breaks were reported, with daily production loss per break of .50% for mains breaks and .005% for hydrant breaks. Only large breaks are reported by SCADA where pressure drops are recognized in current operations; small customer breaks are not reported. Hydrant flushing occurs with mains breaks, but the distribution system is rarely flushed outright due to drought and water conservation efforts. Severe drought conditions in California led to a State of Emergency declaration by the governor in January 2014. In April 2015, the governor followed up with Executive Order B-29-15, which mandated the State Water Resources Control Board (SWRCB) impose water use restrictions. With this mandate, every water utility in the state was ordered to reduce water usage by a percentage relative to 2013 levels. Palo Alto residents have taken great strides in water conservation. With annual savings goals of .91% since 2013, Palo Alto has achieved savings of 1.54% and 1.96% in 2015 and 2016, respectively. Page 64 of 84 © 2018 UtiliWorks Consulting, LLC Conservation was achieved through a combination of programs targeted at both residential and commercial consumers. Conservation programs include: landscape conversion and hardware rebates, outdoor water auditing, and indoor self-auditing. At this time, however, Palo Alto has no specialized conservation dashboard on its web presentment service. 8. Gas Meters/Meter Shop Utilities maintains stationary gas meter test benches, though the Model 5 (used for larger meters) can be made mobile. A formal testing program has been implemented. Though no meters are pressure-compensated, some (fewer than 10) are temperature-compensated and are easily-identifiable in CIS. All gas meters are located outdoors; though some are behind gates or other enclosures, none have noteworthy access issues. UtiliWorks reviewed and analyzed the gas meter database to populate the cost-benefit model with an accurate count of meter replacements versus meter retrofits. In addition, we reviewed the meter population to identify exceptions or anything that would be useful so that a proposing vendor can provide a more accurate response to an RFP. About half of Palo Alto’s gas meter population will be greater than 20 years of age prior to deployment. A summary of meter types by install date is shown in Table 17: Gas Meter Types by Age. Table 17: Gas Meter Types by Age Pre- 2002 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 CNG 1 Curb (175-275) 115 5 10 12 6 9 13 17 8 19 22 8 13 21 14 18 9 Curb (310-630) 8 1 5 10 12 6 8 7 17 3 2 2 9 6 2 Curb (675+) 1 House (175-275) 10,568 583 421 479 479 405 438 611 530 746 693 718 811 674 590 712 304 House (310-630) 268 57 75 80 108 153 205 288 180 157 168 260 219 204 205 189 69 House (675+) 1 1 3 7 17 13 27 14 20 23 5 LDM 14 1 1 4 11 5 6 2 2 1 1 Rotary 107 44 35 36 33 65 40 24 33 28 34 39 49 46 62 63 11 Turbine 1 1 1 Ultrasonic 1 1 3 After discussions with Palo Alto, UtiliWorks was also able to identify that 50% of the meter population will require filter replacement and Grunsky tee installation during deployment. 9. Gas Operations Currently, Utilities measures natural gas purchases via SCADA, which monitors PG&E inlets; however, this method is neither accurate, nor reliable, and Palo Alto does not have separate inlet meters past the PG&E metering for cross-check purposes. Across its distribution lines, Utilities estimates losses of 2.2%-2.5%. Gas distribution is monitored through several vectors. As with purchase measurements, SCADA is relied upon heavily for gas operations and acts as a remote monitoring system for gas system pressure, temperature, and flow at key distribution locations. SCADA is also capable of real-time alarming and reporting on the four pressure regulator stations. Natural gas temperature Page 65 of 84 © 2018 UtiliWorks Consulting, LLC compensation is accounted for in the meter and, for high usage, is also factored into billing. Leaks are discovered via leak detection surveys. Unmetered gas consumption is usually the result of broken piping, and, although common on small services, it is not common on mains. Additionally, though a theft detection and prevention program is in place, theft does not pose a significant issue to operations. 10. IT Support/Systems A detailed analysis of IT systems and recommendations is provided in Section D. See Table 18: IT/OT Systems for a record of IT/OT systems in use at Palo Alto. Table 18: IT/OT Systems Function Name of Application Manufacturer System Interfaces Hosted / In House? System Owner Accounting/Financial/Purchasing SAP SAP Varies In House IT/Admin Services Department AMI (Pilot) Energy Axis Elster/ Honeywell Hosted Utilismart, Inc. Asset Management SAP SAP Topobase In House IT/Admin Services Department Automatic Vehicle Location (AVL) NASPO ValuePoint Verizon Portal Hosted Utilities BI/Reporting Software SAP BI SAP Anticipated: MDMS IT BI – Visualization Tableau Various Departments CIS/Billing/Service Orders SAP SAP SAP In House IT/Utilities Call Center Software Avaya Call Center Elite Avaya City phone system In House IT/Utilities Customer Web Portal MUA SAP SAP In House IT/Utilities Customer Web Bill Pay Portal MUA SAP SAP In House IT/Utilities Customer Web Portal MUA 2.0 SEW SAP Hosted Utilities GIS AME (Topobase) Autodesk GIS, SAP, and OMS In House Electric Engineering (AME) GIS (City) Homegrown - Geodesy IT Electric Estimating Software Autodesk Utility Design (AUD) Spatial Business Systems Utilities Page 66 of 84 © 2018 UtiliWorks Consulting, LLC Interactive Voice Response (IVR) IVR Vocantas SAP Hosted Customer Support Meter Reading - Water, Gas & Electric FCS Itron SAP In House Customer Support/Meter Reading Outage Management (OMS) NISC NISC Multispeak 3.0 to ACS; NISC IVR and ArcGIS In House Electric Ops/ Electric Engr. SCADA - Water/Wastewater ACS ACS In House Electric Ops/ Electric Engr. SCADA - Natural Gas ACS ACS In House Electric Ops/ Electric Engr. SCADA – Electric ACS ACS Multispeak 3.0 to NISC In House Electric Ops/ Electric Engr. Work Order Management System SAP SAP SAP In House IT/Utilities Page 67 of 84 © 2018 UtiliWorks Consulting, LLC Appendix C – IT Considerations for AMI/MDMS Procurement In addition to the vendor selection criteria to be decided by CPAU during Procurement, the following are considerations when selecting vendors for the AMI and MDMS systems, with regard to “future-proofing” the AMI selection. These areas should be incorporated both in the RFP and in the written contracts with the vendors wherever possible: 1. Financial viability. 2. Number of years in business. 3. Client list – Does the vendor have clients similar to CPAU in size and services offered? 4. Upgradability – AMI technologies continue to evolve, and so it is important to choose a vendor whose solution can be upgraded and enhanced without significant cost. 5. Innovation – What is the percent of annual revenues invested in research and development? 6. Data retention – How long is data maintained, for each type of data? 7. Application monitoring – What application monitoring capabilities are built in, and how they are presented to the client? 8. Reporting – Ask to see samples of preconfigured reports. 9. Service Level Agreements (SLAs) – What are the vendor’s SLAs for responding to and resolving system issues? Page 68 of 84 © 2018 UtiliWorks Consulting, LLC Figure 12: Full View, Utilities Technology Roadmap 1. Security Assessment As part of the AMI RFP process, CPAU should require MDMS and AMI system vendors to complete a Security Assessment. The Security Assessment will ask for the vendor’s approach to cyber security, including:  Meters: o Limiting access to meters. Key : Q4- 2 0 1 7 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Ene r g y E f f i c i e n c y Pro g r a m O p t i m i z a t i o n (EE O ) (T B D ) Tec h n o l o g y S y s t e m s (Es t . C a p i t a l C o s t ) Yea r 1 - 2 0 1 8 Yea r 2 - 2 0 1 9 Yea r 3 - 2 0 2 0 OM S & A M I In t e g r a t i o n Dis t r i b u t i o n S y s t e m Opt i m i z a t i o n , C V R Cus t o m e r T i m e - o f - Use R a t e s E x p a n s i o n New E E P r o g r a m s , D R pro g r a m s Util i t y S t r a t e g i c P l a n Dev e l o p m e n t Re-assessment Phase AMI / M D M S P r o c u r e m e n t AM I / M D M S S y s t e m S p e c Data C l e a n s i n g - f i e l d c h e c k s , m a s t e r d a t a c l e a n - u p CIS S t a b i l i z a t i o n Iss u e E R P R F P and R e t a i n V e n d o r Im p l e m e n t N e w E R P HR M o d u l e Im p l e m e n t N e w E R P Fin a n c e M o d u l e Dev e l o p T e c h n o l o g y Roa d m a p Not e : E a r l y s e l e c t i o n o f A M I v e n d o r a l l o w s met e r r e p l a c e m e n t s t o r e s u m e a s p l a n n e d , ahe a d o f m a s s i n s t a l l a t i o n o f A M I m e t e r s . Fut u r e P r o g r a m s t h a t a r e dep e n d e n t o n A M I Dat e s a n d $ T B D In t e g r a t e C I S t o S A P & M U A Dat a C o n v e r s i o n : C r e a t e e x i s t i n g Cus t o m e r s i n C I S Im p l e m e n t C I S + I n t e g r a t i o n w i t h exi s t i n g S A P / E R P s y s t e m CIS D e s i g n P h a s e Iss u e C I S R F P and R e t a i n V e n d o r 300 H o m e C u s t o m e r C o n n e c t / T O U R a t e P i l o t P r o g r a m - M a i n t e n a n c e P h a s e Ful l D e p l o y m e n t ( b y r o u t e / c y c l e ) Im p r o v e m e n t o f E n e r g y E f f i c i e n c y P r o g r a m P r o m o t i o n s b a s e d o n n e w C I S / A M I - P l a n n i n g a n d Pilo t s , o n g o i n g Tec h n o l o g y D e p l o y m e n t Adv a n c e d M e t e r i n g In f r a s t r u c t u r e ( A M I ) & Met e r D a t a Man a g e m e n t S y s t e m (M D M S ) ($ 1 7 t o $ 1 9 M ) Fut u r e P r o j e c t In P r o g r e s s Alp h a P h a s e AM I / M D M S Im p l e m e n t a t i o n Bet a P h a s e AM I / M D M S Im p l e m e n t a t i o n In t e g r a t e M D M S t o C I S , M U A , A M I H e a d End S y s t e m ( H E S ) , O M S & G I S Ent e r p r i s e R e s o u r c e Pla n n i n g ( E R P ) (U T L s h a r e $ 1 t o $ 2 M ) Cus t o m e r I n f o r m a t i o n Sys t e m ( C I S ) ($4 - 5 M ) In P l a n n i n g Fle x i b l e B i l l i n g & Pay m e n t S o l u t i o n Yea r 5 - 2 0 2 2 Yea r 4 - 2 0 2 1 ER P D e s i g n P h a s e In t e g r a t e n e w E R P w i t h C I S Yea r s 6 + Dep e n d e n t on CIS Coo r d i n a t i o n Dep e n d e n t on CIS / M U A Dep e n d e n t on A M I Dep e n d e n t on A M I Dep e n d e n t on A M I Coo r d i n a t i o n Dep e n d e n t on A M I Page 69 of 84 © 2018 UtiliWorks Consulting, LLC o Physical security of the meter – Locks and/or mechanisms that disable or alert if a meter is tampered with. o Encrypting Personally Identifiable Information (PII) at rest and in transit using government- and industry-approved encryption standards. o The ability to remotely and securely upgrade firmware to patch for security threats. o Not allowing firmware to be read from the meter.  Field Area Network infrastructure: o Hardwired network security. o Wireless network security. o Software security. o Hardware security, including limiting access to Field Area Network devices. o Intrusion detection. o Encrypting Personally Identifiable Information (PII) at rest and in transit using government and industry approved encryption standards. o Regular security audits and penetration-testing.  AMI HES and MDMS hardware and software: o Data center physical security. o Network interface security. o Encrypting Personally Identifiable Information (PII) at rest and in transit using government- and industry-approved encryption standards. o Regular security audits and penetration-testing. In addition to reviewing security practices during the RFP and vendor selection, UtiliWorks recommends that CPAU include security in the procurement contract language, including requiring the vendors to take responsibility for security and vulnerability mitigation over the full product life cycle. 2. Disaster Recovery and Continuity As part of an RFP process, UtiliWorks recommends that CPAU assess the AMI and MDMS vendors’ disaster recovery and continuity plans. The review should include:  What is the Recovery Time Objective (RTO)? This is how long it takes before major systems are back online after a disaster.  What is the Maximum Tolerable Downtime (MTD)? This is how long systems can be down before it is deemed unacceptable and impacting the business.  Are redundant data centers used? What are the geographical locations of the data centers? What is the frequency of data backups?  Do the data centers follow security best practices for physical security and data security?  Does the vendor perform annual disaster recovery and failover testing? Are the test scenarios and test results provided to customers? Page 70 of 84 © 2018 UtiliWorks Consulting, LLC Appendix D – AMI Implementation Methodology To effectively deploy complex technology, such as an AMI system, it is critical to have a well-devised implementation plan. UtiliWorks has developed a proven delivery mechanism for complex, technology implementations called the UtiliWorks Advantage™. This approach was specifically designed to clearly identify the project steps and highlight the inherent dependencies between technology and business process. The steps in this process are outlined in Figure 13: UtiliWorks Advantage. Figure 13: UtiliWorks Advantage This report is designed to meet the requirements of Step One – Assess. The feasibility study effectively provides the first go/no-go decision point on whether to proceed with future project development. Page 71 of 84 © 2018 UtiliWorks Consulting, LLC Appendix E – Utility Operational Technology Historically, Operation Technology (OT) and Information Technology (IT) have been managed as two different domains by most industries, including utilities. However, as connectivity and real-time data became more prominent in the last few years, OT has started to adopt IT-like technologies. This convergence of IT and OT is expected to enhance performance and operational flexibility with the better optimization of data. Utilities, can gain the most benefits in converging IT and OT, with most of its operational assets−transmission equipment, substations and meters−can be increasingly connected with intelligence while the performance data can be collected in real time. For example, utility metering was traditionally part of the OT world, while utility billing was traditionally part of the IT world. Now with advanced metering infrastructure, these two functions can be connected, bringing an end-to-end smart metering (meter-to-bill) where bills are produced based on exact meter readings, no longer on estimates. This section provides a description of the relevant technologies that potentially will transform utility operations and improve their performance and service to its customers. 1. Advanced Metering Infrastructure AMI is a transformational technology. This technology provides an excellent data collection platform, a bi- directional control network, and automates a very expensive and at times challenging business function. The deployment of an AMI system opens the door to a wealth of data previously unavailable to utilities and their customers. Previously, a customer’s meter consisted of a simple read once/month. Once the data was collected, all but the largest customers with specially designed meters generated a single-data element per month: a billing read. In contrast, AMI provides a steady stream of meter-reading and diagnostic data at regular intervals, as well as event-driven urgent messages. More granular usage data and system information can be transmitted digitally over the AMI network. If managed properly, this data can be used by many different applications, ranging from customer presentation of consumption profiles to usage of the data by engineering and operations to monitor system health and predict where upgrades to the system will have the most favorable return on investment. An AMI system can be configured so that a customer service representative can request an on-demand meter read. By relaying that information to the customer immediately (over the phone or at the billing and collection location), issue resolution can be accelerated. An AMI system, along with the data it delivers, can facilitate numerous improvements; however, a solid plan to design and deploy the system and business process changes is essential to project success. AMI implementation must be approached wisely in preparation for drastic changes in data volume, variety, and velocity. A successful path to AMI includes careful advanced planning and preparation regarding data distribution to all stakeholders involved. A. AMI System Details AMI systems allow meters to be read remotely from a central location through a fixed communications network. There are various AMI network designs available, including radio-frequency based, powerline carrier, or via broadband powerline. Today’s AMI systems suitable for Palo Alto are radio-frequency based. Radio-based products operate on either licensed or unlicensed frequencies. A license covers the use of a specific frequency in each area. The licensed band normally permits a higher power signal, which enables greater distance between the transmitter and receiver units. Unlicensed radio frequency systems operate under greater Federal Communications Commission (FCC) imposed frequency and power level constraints but with increased channel width and thus higher bandwidth capabilities. The same band can be shared by other devices using specialized modulation and frequency-hopping techniques, which make the systems inherently more interference-tolerant. Page 72 of 84 © 2018 UtiliWorks Consulting, LLC The most advanced metering systems use one-way or two-way communications to get the data to and from the meter through a transmit/receive endpoint or meter interface unit (MIU) connected to the meter encoder/register. These MIUs talk to nearby collectors, also known as gateways or data concentrator units (DCUs). It is not uncommon for AMI systems to also use a series of network repeaters to ensure adequate communications. The collectors are then networked to the utility head-end system through a fixed communication backhaul network. This backhaul network typical uses an Ethernet transport and can leverage city fiber, radio systems, cellular modems or any combination. Communications between the meter and the collectors are specific to each vendor and use proprietary protocols. The components of an advanced metering infrastructure system are illustrated in Figure 14: Sample AMI System Diagram (Point to Multipoint Network). *The diagram above illustrates a point to multipoint communication network, utilizing a radio frequency system. Although there are instances where the communication systems for electric and water are different and communicates to separate base stations/DCUs, in this diagram, both electric and water MIUs are presented communicating to the same base stations/DCUs. In future AMI network design, the network can be leveraged to support additional applications such as: distribution automation, demand response, SCADA “lite,” street-lighting management, plug-in hybrid electric vehicles, etc. Figure 14: Sample AMI System Diagram (Point to Multipoint Network) Many AMI systems collect interval (e.g., hourly or sub-hourly) data. Two-way systems enable the system to collect on-demand reads, send control signals, firmware updates and time synchronization signals to the MIU at the meter. Other sensors, such as acoustic leak detectors, can passively gather information and send it along periodically. Actuators, such as remote shut-off valves, can be triggered in response to commands from the head-end software. Typically, at pre-programmed intervals, MIUs at the customer premise transmit meter readings to nearby permanently positioned DCUs, which in turn relay the readings back to the head-end. Fixed Page 73 of 84 © 2018 UtiliWorks Consulting, LLC network MIUs typically collect readings from the meter several times per day and transmit them at least once per day. Most AMI systems rely on a relatively large number of low cost DCUs closely spaced on power poles or rooftops. The distance between the MIU and the data collector might be less than one mile. Other systems (sometimes referred to as “tower-based” AMI) use fewer more expensive collectors located on tall towers or buildings. These systems operate at higher power and the signals can propagate farther. The use of repeaters between MIUs and data collection units is common to fill in gaps and create a more uniform communications network. Point-to-Multipoint Networks A point-to-multipoint connection refers to a type of architecture for fixed wireless data communications, as described in the previous figure. A point-to-multipoint network configuration has a communication link between an “access point” radio and associated “remote” endpoints at the meter level. All meters can talk to the collector in this scenario, and the collector can talk back to the individual meters. Thus, this scenario is classified as two-way communication architecture. However, the meters cannot communicate to each other. In this setup, only data packets sent to the access point are acknowledged. Point-to-multipoint networks are licensed-spectrum networks and are classified as private. Mesh Networks Another variant of fixed network AMI uses a mesh network. In mesh networks, MIUs (“nodes”) themselves serve as relaying devices for data and instructions. Information “hops” from MIU to MIU until the head-end destination is reached. These mesh networks are generally self-forming and self- healing. Since the City of Palo Alto’s system will encompass electric and water, the combination network will allow meters to be routed to hop through the closest meter of any type. Most mesh networks use low power transmissions in the unlicensed bands, and MIUs must be reasonably close together (typical ranges up to 1,000 feet). Using the relaying scheme, a data collector can cover greater distances than some networks that rely on local data collectors. However, each hop adds latency to the network, thus avoiding excessive hops with good planning of DCU locations is important. Typically, AMI mesh network design is not recommended for a water-only utility, as the power required for the daily multiple hops may cause the meter interface unit battery (at the water meter) to drain quicker. It can be considered for utilities such as Palo Alto, which is a combination of electric and water, as the water meter interface unit can communicate only to the nearest electric meter and have the electric meter interface unit (which does not require battery) perform the multiple hops to send data, thus prolonging the battery life of the water-meter interface unit. Page 74 of 84 © 2018 UtiliWorks Consulting, LLC Figure 15: AMI Mesh Network Illustration Page 75 of 84 © 2018 UtiliWorks Consulting, LLC Table 19: Point-to-Multi Point vs. Mesh Network Characteristic Point-to-MultiPoint Network Mesh Network Spectrum Operates on a private licensed spectrum. Requires annual licensing fee Interference less likely because of licensing, but systems are more susceptible to interference if there is source. Operates on a public unlicensed spectrum. Does not require annual licensing fee. Higher chance of interference but systems are also more interference-tolerant. Signal-to-Noise Ratio Has a low noise floor. Signal-to-noise ratio can be maintained at a high level. Has a high noise floor. Signal-to-noise ratio can rapidly reduce when high noise levels are generated in shared frequencies Signal Range (Coverage) Can use higher level of output (US) to extend range. Range is limited due to one watt of power output limit (U.S.); remediated by locating points close together. Latency Signal moves through few or no mid-point nodes; latency is minimal. Signal must go through multiple “hops,” which increases latency. Hops can be reduced by adding more backhaul. Communicated Data Retrieval Higher risk of losing communication with endpoint due to relying on one communication path. AMI network needs to be designed carefully to ensure full coverage. “Self-forming” and “Self-healing” capability; network can re-route information to an alternative communication path. Infrastructure Higher cost of collectors (base stations). Less complex/requires less equipment. Lower cost of collectors (gateways). More complex/requires more equipment. B. Meter Interface Units The MIU either interrogates the encoded register of the meter, or accumulates electronic pulses corresponding to consumption from the meter, and transmits this and other information (such as identification numbers or tamper flags). Most MIUs are equipped with some tamper resistant features and may generate electronic “flags” if tampering occurs, such as a cut wire, a tilted meter, a tilted register, etc. Most of the leading electric meter vendors have their own electric meters designed with their MIUs incorporated in its meter casing (“under-the-glass”). See Figure 16: Under-the-Glass AMI Electric Meter Bank for an illustration. Page 76 of 84 © 2018 UtiliWorks Consulting, LLC Figure 16: Under-the-Glass AMI Electric Meter Bank Water meter registers are connected to stand-alone MIUs using a cable. Stand-alone MIUs are sometimes square or rectangular boxes, a few inches on each side and usually not more than two inches thick. The circuitry is usually encased to resist corrosion. A cast iron lid and supporting ring of a water meter pit will diminish transmission signal strength. For fixed AMI systems, the MIU should be mounted with its antenna protruding through the iron lid, or a composite lid may be used. A water meter being installed inside a pit is illustrated in Figure 17: AMI Water Meter Pit Install. AMI ready meter lids can be purchased or a hole can be drilled in a current cast iron or concrete lid so the MIU can fit. Likewise, gas meters can also be retrofitted with stand-alone MIU units (Figure 18: Gas Meter and AMI MIU). Figure 17: AMI Water Meter Pit Install Page 77 of 84 © 2018 UtiliWorks Consulting, LLC Figure 18: Gas Meter and AMI MIU MIUs are equipped with lithium (lithium-thionyl chloride or Li-SOCl2) batteries designed to last 10-20 years, depending on the MIU model and its frequency of transmission. If the MIU is set to transmit above certain design parameters, the battery will wear out prematurely. For example, an MIU designed to transmit a simple reading twice per day will run down its battery quickly if reprogrammed to transmit every 15 minutes. MIU batteries are generally not field replaceable. MIU warranties are typically tied to battery life. For an initial period, manufacturer’s warranties will replace the MIU with a new MIU for no cost (equipment only). Past a certain age, manufacturers will Page 78 of 84 © 2018 UtiliWorks Consulting, LLC replace the MIU under a pro-rated warranty at a cost based on the “list” price. All AMI/AMR manufacturers use batteries from the same few providers and have generally comparable life and warranty periods. C. Data Collection Units and Backhaul Data collectors are typically mounted on light or utility poles, rooftops, or on top of water tanks. Depending on the vendor and local operating conditions, they may be configured to use AC electrical power or DC solar cells. Transferring information from data collectors to the AMI head-end requires a wide area network (WAN). AMI vendors do not typically provide the WAN. Instead, they work with the utility to identify and use locally provided telecommunications facilities. Backhaul may be accomplished over fiber, radio frequency systems or cellular networks. Cities will sometimes develop in-house multi-function wireless communications systems (e.g. SCADA, AMI, Workforce Management, etc.) to further leverage investment. Backhaul over commercial networks such as cell phone service or private, proprietary, or dedicated networks will generally require monthly service charges. 2. Meter Data Management System It is advised for utilities to have MDMS implemented in conjunction with the implementation of AMI. With AMI, utilities will receive endless amount of data; however, without a proper data management system the data will be rendered meaningless as no appropriate action can be taken. An MDMS will be responsible for AMI data cleansing, calculating, providing data persistency and disseminating metered-consumption data. The partitioned data will then can be utilized by different utility technology functions (i.e. billing, customer service, operational, outage management, water leak detection, etc.) to inform and make better decisions. This is where the true business value of an AMI system is realized. MDMS is an essential technology for AMI if predicted benefits outlined in the cost-benefit are to be realized. AMI systems generate an amount of data that exceeds both the capacity and analytical capabilities of both CIS and AMI system environments, which are not designed for this function. Typically, the MDMS requirements are shaped by needs in the electric power utility, as it has a higher complexity in managing the commodity (as electricity can rarely be stored), while MDMS requirements for the water utility are subsets of the MDMS requirements for the electric utility, from functional and performance/scalability standpoints. If Palo Alto is to proceed with an AMI implementation, it is recommended to compliment that implementation with an MDMS. This is taken under consideration of the size and complexity of Palo Alto’s AMI implementation with over 30,000 electric connections, over 20,000 water connections, and over 24,000 gas connections, and the availability of dedicated IT staff in both the electric and water department. Currently available AMI headend systems typically store data for one to thirteen months. The MDMS database, analytics and complex event-processing (CEP) engines provide functionality, bridging the gap between the AMI headend and other business systems within the utility. The MDMS is designed to analyze and manage the large data volumes generated by AMI, and to serve this data to other systems as needed. By design, it will become the system of record for meter-consumption data. The storage and capability of the analytic engine of the MDMS also makes it an ideal nexus for combination of SCADA and Meter Data. Data can be extracted from SCADA historians for offline queries and used in other analytic tools, or read-only views into SCADA Historian databases can be created for real-time queries to Page 79 of 84 © 2018 UtiliWorks Consulting, LLC avoid data replication. This is optional but highly recommended, as the value is quite high and the incremental cost to implement is quite low. The MDMS provides tiered data storage for multiple years of interval data, and provides advanced analytics, reporting, and complex event processing based on meter interval data. In addition, the MDMS:  Validates meter-reading data based upon utility configured validation rules.  The reporting engine provides preconfigured and ad-hoc reports to users.  Provides validated billing determinants to CIS Certain functionality offered by MDM systems can overlap with functionality offered by AMI systems. During the RFP and requirements definition phase of the project, it is necessary to establish the specifics of what that functionality is for each system and why the use of one system would be more advantageous than the other. To provide customers with access to their historical consumption data, configurable alerts, and push notifications, a web-based portal should be procured as a companion product to the MDMS. It is common for the MDMS vendor to offer this functionality; however, the underlying requirements definition along with a design effort will be necessary. Figure 19: AMI/MDMS Data Flow Diagram below provides a detailed look at the data flow throughout the resulting AMI/MDMS system. Figure 19: AMI/MDMS Data Flow Diagram 3. Volt/VAR Optimization The traditional Voltage/VAR management technologies have been used by the power industry for over 30 years and are utilized to reduce electric line losses and increase grid efficiency. This technology has been improved today to include sophisticated VVO sensors, equipment and software and claimed to be capable to reduce overall distribution line losses by 2% - 5% through tight control of voltage and current fluctuations. However, these VVO systems have not been widely deployed in the U.S., as traditional utility fee structures Page 80 of 84 © 2018 UtiliWorks Consulting, LLC fail to provide revenue recovery or ROI to pay the investment needed. Thus, in November 2012, the National Association of Regulatory Utility Commissioners (NARUC) encouraged the State Public Service Commissions to evaluate the energy efficiency and demand reduction opportunities that can be achieved with the deployment of VVO technologies and encouraged them to consider appropriate regulatory cost recovery mechanisms. Voltage regulation refers to the management of voltages on a feeder with carrying load conditions, as the utility needs to deliver power to consumers within a predefined voltage range. VAR is reactive power that is unused and can result in voltage drop and losses due to increased current flow. VAR regulation is achieved by switching capacitors on when demand is high (higher VAR during heavy load conditions) and off when demand is low. Both voltage and VAR affects one another, positively and negatively, and they can be best managed if their regulation is well integrated. The advent of widely deployed sensor technology, including AMI systems and advanced software algorithms has opened the possibility to maximize VVO at the feeder, substation or utility level. This is possible thanks to the development of microprocessor-based controls and computing platforms, pervasive and high- performance communication technologies. Utilities now have higher visibility of their system and control, resulting in the possibility of peak demand reduction, energy loss minimization by targeting power-factor levels, or Conservation Voltage Reduction (CVR). *Graphics adopted from Utility Case Study: Volt/VAR Control at Dominion Voltage Inc. (2012). Graphic on the right, illustration with VVO controls in place, presents a lower starting customer voltage required compared to the traditional design on the left. This is achieved by optimizing voltage profiles and VAR flow, thus lowering overall system voltage and increasing efficiency. Figure 20: Illustration of VVO 4. Water Leak Detection and Pressure Monitoring It is estimated by the City of Palo Alto that distribution water system losses are approximately 7-10%. In past years, the City has been attempting to target older neighborhoods for leaks using “leak noise correlator,” which resulted in the discovery of some water leaks. A leak noise correlator is an electronic device that is used to detect the presence of water/gas leak and pinpoint the location of the leak. It utilizes acoustic sound sensors to record the sound that is produced by the leak. Using mathematical algorithms, the location of the leak can be estimated/pinpointed by translating the time delta it takes for the noise to travel (from the leak site to the sound sensors in between) into distance. This current method takes a great deal of manual “trial and error” in guessing where a water leak may occur in the distribution of the system. Alongside with an AMI network implementation, a sophisticated acoustic water leak-detection and pressure- monitoring system will improve the water leak-detection efforts. The implementation of advanced/smart meters will provide granular real-time data to the utility with information which will indicate potential Page 81 of 84 © 2018 UtiliWorks Consulting, LLC customer-side leaks, illustrate high water use translating to possible waste, and identify theft of water use for accounts that are not considered active by the utility. The ability to produce and analyze interval data by the AMI and MDMS will also allow the utility to proactively identify leaks or water mismanagement. The two technologies that the utility can leverage for water leak detection are: 1) Acoustic Sensors - By attaching an acoustic sensor to the AMI or AMI endpoint, the City's utility will be able to monitor its distribution system along with customer-service lines to get complete system coverage. The acoustic sensor will monitor pipe conditions, looking for changes in the sound that travels down the pipe. The sensor has been designed to listen for a certain frequency range that represents the frequency a leak would produce. The sensors will leverage the AMI communications network to provide a snapshot of its system as often as it obtains the network reads. This leak- detection system should be integrated with the AMI utility-management-platform established by the utility. (a) (b) (c) *Images adopted from National Institute of Standards and Technology (NIST)’s Case Study – Las Vegas Valley Water District Water Leak Detection. Figure (a) illustrates location of acoustic sensor/node in the distribution, (b) illustrates multiple acoustic nodes monitored in real time, (c) presents a detected increase of acoustic signal compared to the normal acoustic noises in the water main, indicating potential water leak. Figure 21: Acoustic Leak Detection Technology The acoustic nodes/loggers are deployed throughout the areas of the water distribution system and provide continuous monitoring of leakage. There are logger types that can be permanently fixed on the main pipe and loggers that can be repositioned/moved around, retained in a place with a strong magnet. Leak detection using acoustic method is straightforward: sound waves detected by the sensors is converted to electric signals and are sent to the management software. An increase of voltage levels compared to the baseline indicates a potential leak in the system. The position of the leak can be estimated from the time delay when the sound wave arrives to the two sensors in between. The time delay, correlated with other information such as distance between sensor, pipe material, velocity of the sound wave, enables the leak detection software to pinpoint the location of potential leak in the system. 2) Flow or Pressure Change - This technique relies on the assumption that an abnormally high rate of change of flow or pressure at the inlet or outlet of a distribution section is indication of the probably the occurrence of a new leak. If the flow or pressure rate of change is higher than a predefined limit within a specific period, then a leak alarm is generated and further investigation and subsequent repairs are triggered. Page 82 of 84 © 2018 UtiliWorks Consulting, LLC A remote pressure monitoring system can be deployed in parallel with an AMI network deployment – leveraging the communication infrastructure. The pressure sensors are installed throughout the distribution area, typically two sensors per district metering area or pressure zone−ideally at high pressure and low-pressure zones. They can either be installed into the distribution main or placed inside a meter vault. The pressure sensors can typically measure pressure from 0 to 200 psig and transmitted securely to the utility office, where it is monitored. Pressure-monitoring technology goes beyond just water leak detection. An accurate, real-time pressure monitoring allows the water utility to optimize the system operation and reduce the duration and disruptions of repairs and maintenance. Accurate pressure data and management allows water utilities to:  Reduce leakage, which in turn reduces cost (supply and energy).  Reduce customer complaints.  Reduce unaccounted for non-revenue water.  Prevention of potential infrastructure failures related to pressure fluctuations.  Improve public health and safety (loss of pressure can allow ground water to contaminate distribution system). *Graphic and illustration adopted from Whittle et. al., 2013, Sensor Networks for Monitoring and Control of Water Distribution Systems. Graphic on the left side presents the pressure vs travel time from three points of the system, t1, t2, and t3 as described in the figure on the right. Meanwhile tb indicates a potential burst/water leak which was detected by a drastic loss of pressure as can be seen in the graph. Using the same principals as acoustic leak detection, location of potential leak can be pinpointed by correlating the travel time, wave speed and pipe properties. Figure 22: Water Burst Detection with Pressure Monitoring Technology By leveraging the AMI communications network, water leak-detection technology can be monitored in close to real time and allow utilities to proactively locate and fix leaks before they go on for years, causing significant water and revenue loss. Page 83 of 84 © 2018 UtiliWorks Consulting, LLC Appendix F – Glossary Table 20: Glossary Term Definition Admin Administration Division AMI Advanced Metering Infrastructure BPR Business Process Re-Engineering CBA Cost-Benefit Analysis CEC California Energy Commission CIS Customer Information System CPAU City of Palo Alto Utilities CPUC California Public Utilities Commission CSS Customer Support Services CVR Conservation Voltage Reduction DER Distributed Energy Resources DIR Department of Industrial Relations DOE Department of Energy Elec. Ops. /Eng. Electrical Operations and Engineering ERP Enterprise Resource Planning ESB Enterprise Service Bus FERC Federal Energy Regulatory Commission GIS Geographic Information System HES Head-End system ICS Industrial Control System IVR Interactive Voice Response KPI Key Performance Indicator MDM(S) Meter Data Management (System) MUA MyUtilitiesAccount NERC North American Electric Reliability Corporation O&M Operations & Maintenance OMS Outage Management System PMO Project Management Office RFP Request for Proposal RMD Resource Management Division SCADA Supervisory Control and Data Acquisition SCAP Sustainability & Climate Action Plan SUS Smart Utility Systems UAC Utility Advisory Commission WGW Ops. /Eng. Water, Gas, and Wastewater Operations and Engineering Page 84 of 84 © 2018 UtiliWorks Consulting, LLC 1 ATTACHMENT B Excerpts of Meeting Minutes from the Utilities Advisory Commission Meeting of 05-02-3018 ITEM 1: ACTION: Staff recommendation that the Utilities Advisory Commission recommend the City Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan including advanced metering infrastructure-based smart grid systems to serve electricity, water, and natural gas utility customers. Jeff Hoel believed the correct financial calculation showed a loss of $7.3 million over 18 years. The current time-of-use (TOU) rate provides discounts at night when electric vehicle (EV) users are charging their vehicles. He wondered about the EV users' reaction if TOU discounts occurred during the day. Replacing gas and water meters because of dead batteries would be a cost and nuisance over time. He questioned whether staff would learn of dead batteries quickly. He questioned whether the number of data samples would provide sufficient information to persuade anybody to increase conservation. Meters should not encrypt data before sending it. Chair Danaher announced the current discussion is introductory, and a vote on staff's recommendation will be taken at a subsequent meeting so that Commissioners have more time to study the document. The UAC may wish to draft an informational report of its thoughts to the Council following a recommendation to the Council. Dean Batchelor, Chief Operating Officer, announced the item will return to the Commission in August for further discussion. Jonathan Abendschein, Assistant Director of Resource Management, advised that the report represents an initial high-level exploration of the cost and benefits of advanced metering infrastructure (AMI) and a high-level map of the work leading to implementation. The UAC's vote to accept the Smart Grid Assessment and Utilities Technology Implementation Plan (Plan) would indicate staff is planning appropriately. Over time, the Council will need to approve multiple policies, procedures, budgets, and contracts. Throughout the process, the Plan can be refined. Shiva Swaminathan, Senior Resource Planner, reported the Plan recognizes three major elements of technology projects that staff is going to undertake in the next five years, the Customer Information and Billing System (CIS), the Enterprise Resource Planning System (ERP), and advanced metering infrastructure (AMI). When work on these elements begin in earnest, other projects may have to be delayed or not initiated until these three projects are complete. Staff views the investment costs as equipment and vendor costs, which total approximately $16.5 million. Staff estimated additional staffing-related costs at $1-$2 million. The Capital Improvement Program (CIP) amount of $19 million is comprised of $10 million for electric, $5 million for water, and $3.5 million for gas. Electric meters will be replaced, but radios will be placed on water and gas meters. The water and gas meter radios operate on batteries and, when the battery runs out, the radio will be replaced. Chair Danaher calculated a cost per residence of approximately $700. Swaminathan clarified that the typical measurement is cost per meter. Staff plans to install approximately 72,000 meters at a cost of $300 per meter. Staff proposes funding the electric portion of the project through the Electric Special Project Reserve. The water and gas portions of the project could 2 be funded through capitalization or financing over a 20 or 10-year term. The primary financial benefits of the project are reduction in meter reading costs and increased conservation. Staff did not quantify non-financial benefits such as improved reliability and better customer experience. In November, staff presented the net present value (NPV) as negative $7 million over 18 years. Since November, staff has determined there could be greater synergies in staffing and utilization of devices for greater conservation. These changes result in a breakeven NPV. Implementing AMI will require review of policies, procedures, and staffing resources and receipt of community and staff input. Change management and communication is a key part of the project. A transition plan is being discussed and developed for staff as roles change. Selection of technology will be relatively easy as the technology is mature. Staff has identified approximately 35 risks, the top five of which are sufficient resources, staff engagement and communication, definition of vendor contracts, integration of software, and Council approval of policies and protocols. With respect to the impact of the project on utility bills and rates, the project is a winner across the full utility and for each utility. The overall impact on bills for residential customers is neutral. In the worst-case scenario, there could be a 0.35-0.7% impact on bills if costs are incurred but benefits do not materialize as projected. Next steps include further discussion and acceptance of the Plan in August. Some of the capital investments have been included in the fiscal year 2018-2019 CIP budget. If the UAC accepts the Plan in August, staff will present it to the Council in September. In response to Commissioner Johnston's request for additional details of staff's calculation of the NPV, Swaminathan explained that staff made assumptions initially without considering any sensitivities and calculated a value. Staff then changed the assumptions and calculated the NPV. Commissioner Johnston did not find an assessment of the likelihood of not achieving each of the savings used in calculating NPV. Swaminathan indicated staff does not have a probability for achieving each savings. Staff knows with relative certainty the capital costs, but staff has a large uncertainty around the ongoing operations and maintenance cost and the value that can be harvested from the systems. The benefits projections and assumptions contribute to NPV. Commissioner Johnston inquired about experiences from other cities that staff could utilize to minimize the risk that the systems would not communicate well with one another. Abendschein related that one of the key ways to control the risk is to hire an excellent implementer who has experience with utilities similar to City of Palo Alto Utility (CPAU). Staff is investigating different avenues to make that work. Swaminathan added that the project included a $1 million contract with expert project managers who have done this type of project multiple times with utilities similar to CPAU. The project managers will be familiar with CPAU's CIS and ERP. In reply to Commissioner Segal's question regarding the contractor being responsible for just AMI integration or CIS and ERP integration, Swaminathan clarified that integration of CIS and AMI is part of the AMI project budget. Commissioner Segal presumed CIS implementation has to anticipate integration with AMI. Swaminathan stated the consultant handling the CIS and ERP projects has subcontractors, and one of the subcontractors will understand AMI integration. There would be no direct integration between AMI and ERP, only between AMI and CIS. Vice Chair Ballantine remarked that if the infrastructure supporting telemetry did not have backup systems all the way through, then the entire telemetry network could be lost in the event of a large earthquake or other significant catastrophe. In this scenario, staff would not be able to see all the meters to identify the locations of problems. If all the nodes go to data collection boxes per neighborhood and have no backup power, they will go out the moment the utility goes out. That would be a disappointing result for the whole project. Swaminathan reported the collectors have backup batteries. Vice Chair Ballantine responded that the numbers for recovering from an earthquake are 3 significantly longer than battery life. Abendschein explained that one purpose of the battery is to pass on the last gasp of information from all of the meters so that staff has at least a snapshot of what the system looked like when the earthquake hit. Part of the disaster recovery process is getting the collectors running and getting real-time telemetry up. Vice Chair Ballantine commented that if the main hub receiving the data did not stay up to get that blast of data, then all data would be lost. Often the entire electrical infrastructure goes down even though the damaging event is localized. If receiving assets also lose power or do not have sufficient battery life to ride through that, then the data would not get to the main computer asset, which might have backup power. The longer the collectors last the more they can help staff restore the utility. Abendschein clarified that the collectors are designed to deal with exactly that problem. The battery is intended to get all that information to the main system. Batchelor added that staff should explore the length of battery life. Swaminathan advised that the battery life is days. Commissioner Forssell commented that NPV does not have to be positive in all cases. There might be nonquantifiable benefits that the CPAU wants to purchase, such as system reliability. In terms of system reliability, CPAU is already extremely reliable at more than 99%. She inquired about improvements in reliability that an AMI system could provide. Vice Chair Ballantine remarked that Korea and Japan view the reliability of U.S. electrical utilities as extremely poor. Swaminathan reported electric reliability is comprised of length of time to detect and correct the outage and proactively avoiding outages. An AMI system could provide an outage notice sooner and locate the source faster, thereby reducing the length of an outage. With AMI, staff could monitor the loads on transformers during specific time periods and proactively upgrade or replace transformers to avoid outages. Abendschein added that the economic value of reducing an outage by 15 minutes or 30 minutes is much greater for commercial customers than for residential customers, and the majority of the utility's customers are commercial. Swaminathan advised that staff attempted to monetize reliability for both commercial and residential customers using industry statistics. The value is tens of thousands of dollars a year. Commissioner Forssell assumed that type of value was included in the NPV calculation. Swaminathan indicated the values were wild guestimates and small. However, preventing an outage and reducing the length of an outage contributed to customer experience. Commissioner Forssell requested examples of customer experience benefits other than TOU rates for EV users. Swaminathan offered potential benefits of resolving billing inquiries quickly, reducing the length of a power outage, notifying customers of an outage sooner, sending a right price signal to customers, and improving demand response. Chair Danaher referred to Mr. Hoel's query regarding saving money by using Fiber to the Premises and inquired whether RF connections were a significant part of the $19 million project. Swaminathan replied no. Chair Danaher noted smart meters had been used for about 25 years; therefore, a great deal of contractor experience is available. He asked if NPV numbers were informed by the experiences of other utilities and if the NPV calculation included an escalation of labor costs. Swaminathan advised that the NPV was informed by other utilities' experiences and included a labor cost increase of 3% and a benefits increase of 1%. Commissioner Schwartz remarked that there are many examples of AMI projects and of value added to utilities. CPAU could avoid some of the painful lessons of other utilities. Technologies and applications are becoming available that CPAU could utilize right away. Implementing CIS first will allow CPAU to offer more options and services as soon as meters are installed. She recommended the UAC discuss with the consultant the kinds of functions that should be installed so that CIS will accommodate those functions from the beginning. Across the country, outage detection has become an incredibly popular customer experience benefit. Leak detection is even better for customer experience. Each customer 4 having an endpoint device that can communicate will allow CPAU to offer different programs to different customers. The UAC should discuss the kinds of consumer and business-facing programs that allow variability among customers. CPAU policy should allow customers to opt out of AMI. At a recent workshop, she learned of an account reconciliation app. Consumers who utilize the app increase their conservation. The value of AMI should not be determined by cost per meter but by system wide benefits. ACTION: No action ATTACHMENT C Excerpts of Meeting Minutes from the Utilities Advisory Commission Meeting of 09-05-3018 ITEM 2. ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that Council Accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, Including Advanced Metering Infrastructure-Based Smart Grid Systems to Serve Electricity, Water, and Natural Gas Utility Customers. Shiva Swaminathan, Senior Resource Planner, reported staff framed the discussion in the broader context of coordinating projects for the Electric Resource Plan (ERP) System, the Customer Infrastructure System (CIS), and Advanced Metering Infrastructure (AMI). Staff quantified the benefits where possible, but there are significant qualitative benefits. The net present value for investment over an 18-20 year period was calculated to be zero with operating expenses of $27 million and capital expenses of $17 million. In answer to Chair Danaher's question regarding inclusion of expanding the time-of-use (TOU) billing system and more aggressive or new demand response approaches as benefits, Swaminathan indicated that demand response was included, but a TOU rate was not included. The coincident capacity is accounted for. Benefits such as influencing the load with smart meters to charge at the right time were too difficult to quantify. Swaminathan further reported that the expected customer bill impact is neutral, but a wide range occurs based on the outcomes of cost sensitivities. In adverse scenarios, the bill impact is predicted to be 1-2%. In more beneficial scenarios, the bill impact is a decrease of 0.5%. Abendschein clarified that the staff recommendation is an indication that the general roadmap for AMI is acceptable to the UAC and Council. If the UAC wishes to submit a letter to the Finance Committee and Council regarding the UAC's position, he would appreciate any direction from the UAC. Commissioner Johnston expressed some discomfort with the expected outcomes in each case falling at the bottom of the sensitivity range. In response to his question regarding AMI interaction with DERs, Swaminathan explained that AMI meters will aid in differential compensation for customers who invest in DERs. To the extent AMI can incentivize EV charging at a particular time, it can reduce the adverse impact on the distribution grid. For commercial customers, AMI can aid the implementation of TOU rates. Commissioner Johnston stated that reinforces the importance of AMI. Herb Borock questioned whether customers could choose not to utilize a smart meter, the security of data transmissions, and whether fiber to the premises (FTTP) could be utilized with AMI. Swaminathan reported customers could opt out of smart meters with the cost of manual meter reading charged to the customer. FTTP is an option for data transmission, but it occurs at backhaul nodes only. Vice Chair Schwartz remarked that utilities receive so much more value from AMI than anticipated. Techniques to enhance customer buy-in are known and available. Allowing customers to opt out of smart meters should be a policy. The DOE is developing a voluntary code of conduct that will align with information and data privacy concerns in both the U.S. and Europe. She volunteered to compile a list of publications and videos that explain all the components of AMI. Dean Batchelor, Utilities Chief Operating Officer, agreed that customers have many concerns about radio waves and data security. The most important component of implementing AMI is a communication plan for all residents and businesses. Staff has plenty of time to explore best practices and lessons learned by other jurisdictions. Vice Chair Schwartz believed the value of AMI is all the things it will enable. In reply to Chair Danaher's query regarding communicating the UAC's strong support for implementing AMI to the Council, Councilmember Filseth did not believe AMI would be a controversial issue for the Council because the numbers work. Chair Danaher commented that the numbers omit many of AMI's benefits. Commissioner Forssell felt it is important for staff to point out to the Council that the business case does not express the full value of AMI. ACTION: Commissioner Trumbull moved to recommend that Council accept the Utilities Smart Grid Assessment and Utilities Technology Implementation Plan, including Advanced Metering Infrastructure- based smart grid systems to serve Electricity, Water, and Natural Gas Utility customers. Commissioner Forssell seconded the motion. The motion carried 6-0 with Chair Danaher, Vice Chair Schwartz, and Commissioners Ballantine, Forssell, Johnston, and Trumbull voting yes, and Commissioner Segal absent.