Document elcerrito_gov_doc_cb8a563b4d

AGENDA BILL Agenda Item No. 7 Date: November 18, 2014 To: El Cerrito City Council From: Maria Sanders, Environmental Analyst Melanie Mintz, Interim Community Development Director Subject: Study Session to Provide Policy Direction Regarding Membership in Marin Clean Energy’s Community Choice Aggregation Joint Powers Agency ACTION REQUESTED Receive a presentation on the results of the “Marin Clean Energy Applicant Analysis for the City of El Cerrito” and the risks and benefits associated with joining Marin Clean Energy, and provide policy direction regarding joining Marin Clean Energy’s Community Choice Aggregation Joint Powers Authority. BACKGROUND The City of El Cerrito’s Climate Action Plan (CAP), adopted May 2013, contains a strategy to “Explore opportunities for instituting or joining a regional Community Choice Aggregation (CCA) effort” (Strategy EW-3.2). Joining a CCA with a high renewable energy portfolio is identified in the CAP as one of the most cost-effective ways to reduce greenhouse gas emissions in El Cerrito, yielding an estimated 4,200 - 6,700 annual tons of CO2 reductions by 2020 with relatively little investment. In 2002, passage of Community Choice Aggregation (AB 117, Migden) allowed CCAs to operate in California. This legislation enables California cities, counties, public agencies, and joint powers agencies to aggregate the electricity demand of its constituents and to procure electricity that meets their desired electricity supply portfolio, while still having the local utility (PG&E, in El Cerrito’s case) provide transmission, distribution, billing, and repair services. Participation in a CCA is automatic for electricity account holders in a jurisdiction that offers a CCA. Customers who do not want to participate and prefer to purchase power from PG&E can opt out of the CCA. CCA participation rates are high due to this opt-out approach, allowing CCA agencies to compete for competitive energy contracts in California’s monopoly- dominated energy markets. Energy transmission, distribution, repair, most customer service, and billing would continue to be administered by PG&E. In 2010, Marin Clean Energy (MCE) launched California’s first CCA. MCE is a joint powers authority (JPA) currently consisting of all jurisdictions in Marin County, the City of Richmond, and more recently Napa County and the cities of Benicia and San Pablo. The mission of MCE is to address climate change by reducing energy-related greenhouse gas emissions, while also securing energy supply, price stability, energy ---PAGE BREAK--- Agenda Item No. 7 Page 2 efficiencies, and local economic and workforce benefits. Consistent with that mission, MCE sources energy from 51% renewable sources (compared to PG&E’s 22% renewable energy portfolio) at rates that are currently less than those of PG&E. Given the success of MCE to procure renewable supplies of electricity at competitive rates, many communities throughout California are taking a fresh look at instituting CCAs. Sonoma County launched their county-wide CCA this year. Nine other counties, including Alameda County, are also exploring CCAs as an option. Closer to home, the City of Richmond successfully joined MCE in 2012. In the past few months, San Pablo, Benicia, and Napa County also joined MCE, setting the stage for a new electricity procurement cycle with MCE to begin early in 2015. The City of El Cerrito has taken several steps to investigate the various CCA options potentially available to the City. On October 2, 2012, the City Council received a presentation by MCE and the City of Richmond regarding CCA, their membership process, and their program offerings. During the spring of 2014, the El Cerrito Environmental Quality Committee (EQC) hosted several presentations from various groups involved in CCAs in the Bay Area. Agreeing that joining MCE represented the least cost, lowest risk, and most time-efficient option currently available in Contra Costa County, the EQC passed a unanimous motion at its June 2014 meeting requesting that the City Council consider a resolution requesting that MCE conduct a membership analysis for El Cerrito. Additionally, Community Development staff, in partnership with the City of Albany, successfully applied for a small grant ($15,000 per city) from the World Wildlife Fund to contract with MCE to complete the membership analysis. On July 15, 2014 the City Council adopted Resolution 2014-28, authorizing the Mayor to submit a letter to MCE requesting that it conduct a membership analysis for El Cerrito, and authorizing the City Manager to execute a contract with MCE for $18,000 to conduct the membership analysis and to participate in El Cerrito community meetings. DISCUSSION MCE Membership Analysis for El Cerrito: The MCE Applicant Analysis for the City of El Cerrito (Attachment 1) was completed in October and presented to the MCE Board on October 21, 2014. The analysis indicates that expansion of MCE membership to include El Cerrito would result in “an approximate 1% rate reduction for MCE customers, including all existing and prospective accounts.” It is important to note that, for the purpose of determining rate impacts, the analysis assumed “that any rate/financial impacts were based wholesale electricity pricing at the time the analysis was completed. Such pricing is subject to change. Actual rate/financial impacts will be based on wholesale electricity pricing that is offered to MCE at the time of power supply contract execution” (see Attachment 1, p.1). In terms of environmental benefits, the analysis indicated that including El Cerrito in MCE’s membership would increase the amount of renewable energy being used in California’s energy market by approximately 16,000 megawatt hours (MWh) per year resulting in a greenhouse gas (GHG) emissions reduction of approximately 5 million pounds of CO2e per year. ---PAGE BREAK--- Agenda Item No. 7 Page 3 Because the analysis demonstrates that expansion of MCE membership to El Cerrito would be beneficial to MCE’s current and prospective rate payers, El Cerrito may move forward with the membership process (detailed on page However, the rate impact analysis, the primary criteria determining eligibility to join MCE, assumes that MCE would be extending service to El Cerrito customers by Spring 2015. If the City Council is interested in joining MCE, but chooses to defer joining MCE after MCE has entered into this year’s energy contracts, this would delay El Cerrito’s membership until the following year, early 2016. At that point, organizational and market conditions may have changed and El Cerrito’s membership analysis would need to be updated, at an additional cost. Since the time MCE was formed in 2010, several local governments have contracted with third parties to review legal and organizational issues associated with joining the MCE JPA. In 2010, the legal firm of Davis Wright Tremaine reviewed for the City of Mill Valley the potential legal risks and liabilities associated with participation in MCE. In 2011, the energy consulting firm MRW & Associates conducted a Risk Assessment for the City of Richmond.1 Finally, the City of Benicia, which is currently evaluating joining MCE, contracted with these firms to update their assessments (see Attachment 2, Davis Wright Tremaine Letter and Attachment 3, MRW Risk Assessment). As the conclusions of these reports also pertain to El Cerrito, below is a discussion of the most salient points for the City to consider. Benefits of Joining MCE: If the City were to join MCE, the following services and programs would be available to El Cerrito electricity rate payers. A more detailed assessment of these and other benefits can be found in Attachment 3, MRW Risk Assessment, p.4. • Consumer Choice: Joining MCE would provide El Cerrito residents and businesses with a choice in regard to their energy provider and the degree to which their energy comes from renewable and non-nuclear sources. See Attachment 4, MCE and PG&E Power Mix Comparison, for more details. • Competitive Electricity Rates: MCE customers are currently receiving cleaner electricity at rates that are lower than those of PG&E (see Attachment 5, “Electricity Rate Comparison,” for the 2014 rate comparison). While lower rates are not guaranteed from year-to-year, it is reasonable to anticipate rate savings to persist into 2015 because PG&E’s electricity generation rates are projected to increase (Attachment 3, MRW Risk Assessment, p. 23). Rate savings to MCE customers could be compounded by favorable rate impacts projected by the expansion in MCE territory. • Renewable Incentive Programs: MCE offers a solar net energy metering (NEM) program that provides better terms than comparable PG&E programs. This program would be available to all current PG&E NEM customers in El Cerrito. See Attachment 6, NEM Program Comparison, for more details. • Access to PG&E and MCE Energy Efficiency Programs: Because PG&E still provides MCE customers with transmission and generation services, they are 1 Both assessments are available in the Community Development Department for review. ---PAGE BREAK--- Agenda Item No. 7 Page 4 also PG&E customers and will still have access to the energy efficiency and other programs provided by PG&E. In addition, MCE operates energy efficiency programs that are more specifically targeted to the constituents in its territory. • Support of Community Programs and Projects: As a non-profit public agency, MCE allocates a portion of revenues to local projects and programs within its service area. Risks of Joining MCE: The Davis Wright Tremaine Letter and the MRW Risk Assessment review three inter-related areas of risks: those related to MCE being able to procure electricity at competitive rates over the long term; how these risks may affect the City’s electricity consumers; and any potential financial obligations by the City to MCE. The MRW Risk Assessment also discusses MCE’s organizational soundness and MCE/PGE rate comparison for reasonableness. It is worth noting that Sections 1-3 (assessing benefits and risks) of the MRW report is an update to similar sections from the 2011 Richmond Assessment, whereas Section 4 was more recently developed for the City of Benicia. This latter section evaluates many of the same risks discussed in the first sections, but contains less equivocal statements on the relative importance of these risks. • JPA Debts and Liabilities: Pursuant to Government Code section 6508.1, MCE has limited the liability of their members by including in the JPA agreement a provision explicitly stating that the debts, liabilities and obligations of the JPA shall not be debts, liabilities and obligations of the individual members. While this provision limits the risks of liability to members, it does not insulate them from all risk. A discussion of these risks is contained in Attachment 2, Davis Wright Tremaine Letter. That discussion identifies the two primary forms of potential liability for the City, despite the provision in the JPA. First, Government Code section 895.2 excludes tort liability from the general rule that JPA members cannot be held liable for the acts of the JPA. If MCE were sued for negligence or other wrongful acts or omissions, and a court ruled in favor of the plaintiff, the individual members of the JPA could be held liable. Second, the general “alter ego theory” which allows the owners of a corporation to be held liable for the acts of the business also applies to JPA’s. As outlined in the Davis Wright Tremaine Letter, the standard is high for a plaintiff to meet, and the City Attorney notes that this theory is not well developed in case law as it would apply to JPA's. Those risks are potentially significant in particular circumstances. As required by the JPA agreement, MCE has obtained significant insurance coverage for its risks and pursuant to the agreement would provide a defense to members. In most circumstances, the City would not need to provide its own defense or incur the associated legal fees, and MCE’s insurance would be sufficient to protect against any adverse judgment. The El Cerrito City Attorney’s view is that the risks to the City are greatest in the event of a significant disruption in the energy market. If history is a guide, plaintiffs’ attorneys and significant investors would view such a disruption as an opportunity to recover losses through litigation. They might view MCE and its public agency members as a potential pocket for recovery. Such litigants would be likely to include both tort claims and allegations to support application of the alter ego theory as a ---PAGE BREAK--- Agenda Item No. 7 Page 5 means of increasing their likelihood of success on at least one theory. If a court ruled in their favor and MCE’s insurance were insufficient to cover the liability, then the City and other members of the JPA might be required to contribute toward the monetary judgment. Although that scenario requires a number of conditions to be satisfied, it is something that was considered by the original members of MCE at the time of formation. Ultimately, all of the agencies in Marin County decided to accept the risk. • MCE’s Organizational Soundness: The MRW Risk Assessment concludes that MCE’s governance structure is reasonable, the management is experienced and competent, and the finances are sound. MCE has been able to increase its operating reserves consistently from year to year; and while its long-term financial plan may be optimistic in certain years, less optimistic assumptions also result in net surplus revenues (Attachment 3, MRW Risk Assessment, p. 30). • Competitive Rates: Currently MCE rates are less than PG&E’s rates. Due to a variety of regulatory, environmental, and market factors, MCE may not always be able to provide rates that “meet or beat” PG&E’s rates. The converse is also true: PG&E’s rates are influenced by similar, as well as separate, price pressures that may make their rates higher in any given season. These factors are discussed at length on page 23 of the MRW Risk Assessment, which concludes, “Given all the factors that drive rate changes, it cannot be stated with certainty that the relationship between PG&E and MCE rates observed in August 2014 [where MCE rates were lower] will continue year-to-year; however, it is reasonable to expect that MCE rates on average will remain competitive with PG&E’s” and likely be lower in 2015 (Attachment 3, MRW Risk Assessment, p. 23). Other Considerations Prior to Joining MCE: • JPA Participation and Voting Share: If the City were to join MCE, assuming it did so for the 2015 procurement cycle, one El Cerrito City Councilmember would represent the City on the MCE Board of Directors. El Cerrito would have equal participation rights as any city in Marin. Pursuant to the MCE Joint Powers Agreement (Attachment 7, MCE JPA Agreement), each member is given a weighted voting share based on two factors: pro rata, so that each member, regardless of energy usage or size, is awarded an equal weight; and annual energy usage, so that each member is awarded a voting weight determined by annual energy consumption. As a function of the weighted voting formula, El Cerrito’s JPA voting share would be 5.34% of the total JPA2. The relative voting weights are provided below in Figure 1. Figure 1: JPA Voting Shares if El Cerrito Joins Community kWh (2013) Pro- Rata Energy Usage Voting Share Belvedere 9,973,170 3.13% 0.20% 3.33% Ross 13,529,793 3.13% 0.27% 3.40% 2 With the new membership of the City of Benicia, the voting shares for all members will be less. ---PAGE BREAK--- Agenda Item No. 7 Page 6 Fairfax 24,700,647 3.13% 0.50% 3.62% Tiburon 40,913,144 3.13% 0.83% 3.95% San Anselmo 46,642,417 3.13% 0.94% 4.07% Sausalito 48,099,763 3.13% 0.97% 4.10% Corte Madera 62,093,107 3.13% 1.25% 4.38% Larkspur 63,174,199 3.13% 1.27% 4.40% Mill Valley 69,176,164 3.13% 1.40% 4.52% San Pablo 97,383,170 3.13% 1.96% 5.09% El Cerrito 109,836,169 3.13% 2.22% 5.34% Novato 286,565,119 3.13% 5.78% 8.91% Unincorp. Marin 330,023,521 3.13% 6.66% 9.78% San Rafael 347,362,327 3.13% 7.01% 10.13% Unincorp. Napa 348,095,521 3.13% 7.02% 10.15% Richmond 581,012,267 3.13% 11.72% 14.85% 16 2,478,580,498 50.00% 50.00% 100.00% • JPA Culture and El Cerrito Time Commitment: Participating in a new JPA requires a certain level of commitment on the part of both staff and Councilmembers. As such, it is a consideration to know if the culture of MCE as an organization and its Board is compatible with that of the City of El Cerrito. As a public entity, MCE shares a similar responsibility to conduct its business in a professional and transparent way. MCE invites all interested members of the public to attend any of its Board, Technical, and Executive Committee meetings, which are posted on their website http://www.marincleanenergy.org/meetings. All Board meetings are recorded and are available for web viewing, which may be a good way for City Council to gauge the culture of the JPA. Another important consideration is staff and Councilmember time. If El Cerrito joins MCE, El Cerrito’s Council liaison would be expected to attend one Board meeting per month. It is anticipated that there will be a need to provide staff support to the El Cerrito MCE board member. MCE staff provides most of the support needed, but staff from the City of Richmond estimates that approximately 2 to 4 hours of city staff time per month is required once the program is fully operational. • Impacts on Municipal Accounts: As an electric customer and ratepayer, the City of El Cerrito would have the choice of purchasing electricity for municipal accounts from MCE or Pacific Gas & Electric. In 2013, the City spent nearly $305,000 on electricity bills, excluding the City’s solar accounts, and used 1,304,000 kilowatt hours with PG&E. Because electric rates change several times per year, staff recommends that the City complete a thorough rate comparison for the City’s municipal accounts prior to enrolling municipal accounts into MCE. Using current electric rate comparisons, staff estimates that the annual potential financial impact could result in a 3.8% cost decrease of approximately $11,700. Using current emissions factors, enrolling municipal accounts in MCE would reduce GHG emissions by 82 tons of CO2e, or about 10% of the tons needed to reach our 2020 municipal GHG reduction goal of 803 tons. In addition, the city currently has 5 solar ---PAGE BREAK--- Agenda Item No. 7 Page 7 NEM accounts. Given the complexity of solar NEM rates, the actual benefit of enrolling these in MCE would need further analysis. • Environmental Compliance: The City has received a letter from the law firm of Adams Broadwell Joseph and Cardoza on behalf of the International Brotherhood of Electrical Workers (IBEW), contending that joining a CCA requires completion of an Environmental Impact Report (Attachment 8, IBEW Letter). The letter said that the core purpose of joining a CCA is to cause customers to purchase electricity from a different electricity provider and that this could result in a change in the environment. This same letter was sent to almost all jurisdictions considering CCAs. The contention was subsequently dismissed by those that have gone through the CCA adoption process. Below paraphrases the analysis used by MCE, Napa County, and the City of San Pablo3 regarding joining a CCA and CEQA compliance, to which the El Cerrito City Attorney concurs: The action of a local government to join MCE is an administrative action that will not result in a direct physical change to the environment or a reasonably foreseeable indirect change to the environment, and thus is not a project as defined by the California Environmental Quality Act (CEQA) Guideline Section 15378. CEQA Guidelines Section 15378(b)(5) states that a project does not include "Organization or administrative activities of governments that will not result in direct or indirect physical changes in the environment." Per CEQA Guidelines Section 15378, there cannot be a project unless the proposed action will result in "either a direct physical change in the environment or a reasonably foreseeable indirect physical change in the environment." The instant action also does not commit the City to any action that would have a significant effect on the environment per CEQA Guideline Section 15061. A local government joining MCE will not directly change the present amount of power produced or purchased for the city, will not directly result in construction (or removal) of any power generating facility, and, therefore, will not result in a direct physical change to the environment. Decisions by MCE as to what power to purchase for an unknown number of City residents in an unknown quantity, where such power is produced, and for how long a term, are market driven decisions that occur over a period of months and years. To the extent new power supplies might be needed in the future to meet MCE's power demands, or existing facilities need to modify their operations outside their current operating permits, such actions would be subject to further site-specific CEQA evaluation. As those potential future actions are unknowable and speculative, it is impossible to conduct any meaningful CEQA analysis about them. It is not reasonably foreseeable that the City’s decision to join MCE would result in an indirect physical change to the environment. Finally, PG&E operates in the identical marketplace, and decisions made by PG&E as to their future power supply for the City of El Cerrito are likewise unknowable and speculative. Forming or joining a CCA presents no foreseeable significant adverse impact to the environment over PG&E because California regulations such 3 City of San Pablo City Council Meeting. August 4, 2014. Agenda Item 14, Attachment 4, “MCE Response to Napa IBEW Letter.” ---PAGE BREAK--- Agenda Item No. 7 Page 8 as the Renewable Portfolio Standard (RPS) and Resource Adequacy (RA) requirements equally apply to CCAs and IOUs. Potential Next Steps and Policy Considerations: If City Council finds MCE membership to be beneficial and elects to proceed, next steps would include: • A community engagement process to solicit community comments on joining CCA; • A public hearing to adopt a resolution formally requesting membership in MCE and to conduct the first reading of an ordinance approving the MCE JPA Agreement and authorizing the implementation of a CCA program; • A second reading of the ordinance; and • Signing onto the MCE JPA Agreement as a party and assigning a City Councilmember to sit on the MCE Board. Upon completion of the steps described above, MCE would begin procuring additional electricity supplies and begin the community outreach process to provide El Cerrito customers the option of remaining with PG&E service. The community outreach process takes several months, and includes the mailing of five multi-lingual notices and other public workshops to educate the community on their new electricity options. Costs of community outreach at that point are borne by MCE. Staff is seeking policy direction from City Council on the following: 1. Should the City continue pursuing membership in MCE? 2. If yes, should the City pursue an accelerated timeline to join MCE in order to be included in the MCE 2015 procurement cycle? 3. Are there any areas that staff should further investigate or clarify? Because MCE will be expanding its electricity service this year to include Napa, San Pablo, and possibly Benicia, MCE must begin its annual procurement cycle by the beginning of the year. This accelerates El Cerrito’s timeline if the City Council wishes to join the 2015 procurement cycle. In this scenario, City Council would need to hold the public hearing to adopt the CCA ordinance on December 16, 2014. This would give staff one month between tonight’s meeting and the December meeting to gain feedback from the public and prepare for the City Council hearings. While this timeline is not ideal, staff has made all the necessary arrangements to immediately launch public outreach and get feedback from the community through the Open El Cerrito portal on the City’s website and a public workshop (tentatively scheduled for Wednesday, December If City Council wishes to join, but elects to defer participation until the 2016 procurement cycle in order to extend the public input process, the Membership Analysis would need to be updated, at an additional cost and future terms, conditions, and rights of MCE membership for new communities may be different than they are today. STRATEGIC PLAN CONSIDERATIONS Goal F, “Foster environmental sustainability citywide,” of the El Cerrito Strategic Plan contains an objective to implement the City’s Climate Action Plan by facilitating ---PAGE BREAK--- Agenda Item No. 7 Page 9 “energy and water efficiency and greater adoption of clean energy.” Because CCAs in the Bay Area are being formed to procure electricity from renewable energy sources, joining a CCA is identified in the CAP as one of the more powerful and cost-effective strategies for reducing greenhouse gas emissions in El Cerrito. There is no other strategy in the CAP that provides a similar magnitude of reductions at a similar cost. If the City joined MCE, GHG emissions reductions are estimated to be 2,500 tons of CO2e in the first year of full enrollment – providing an additional 1.7 percentage points annually towards the City’s 2020 15% emissions reduction target. By 2020 this reduction is likely to increase and was estimated by the CAP to be approximately 4,200 tons. ENVIRONMENTAL CONSIDERATIONS As discussed above, if El Cerrito did ultimately join MCE, this would be an administrative action that will not result in a direct physical change to the environment or a reasonably foreseeable indirect change to the environment, and thus is not a project as defined by the California Environmental Quality Act (CEQA) Guideline Section 15378. FINANCIAL CONSIDERATIONS There are no direct financial impacts to the City’s General Fund if the City Council elects to join the MCE. MCE electricity and programs are funded by ratepayers that choose to participate in MCE. If City Council wishes to further pursue MCE membership by early 2015, no additional outside expenses are anticipated. If it elects to pursue membership in 2016, an additional membership analysis would need to be funded and conducted. The cost of community outreach to assist community members in understanding the opt-out system, once the City joins, would be borne by MCE. However, there may be internal expenses related to legal review of the JPA agreement and other related documents, as well as staff time to support El Cerrito’s JPA member, as discussed above. LEGAL CONSIDERATIONS The City Attorney has reviewed the two risk assessment documents prepared for the City of Benicia and generally agrees with their conclusions, with the additional comments included in this report under the JPA Debts and Liabilities section above. The process for joining MCE is as described in this report. The City Attorney has reviewed the MCE JPA Agreement, the template resolution for requesting membership in MCE, and the template ordinance for implementing the CCA in El Cerrito by participating as a member of MCE and for approving the JPA agreement. If Council elects to further pursue membership, staff will bring these documents to Council at the time of the public hearings for the Council’s consideration. ---PAGE BREAK--- Agenda Item No. 7 Scott Hanin, City Manager Attachments: 1. Marin Clean Energy Applicant Analysis for the City of El Cerrito (MCE Applicant Analysis) 2. Letter to City of Benicia from Davis Wright Tremaine, October 22, 2014 (Davis Wright Tremaine Letter) 3. Risk Assessment ofParticipation in the Marin Clean Energy Community Choice Aggregation Program on Behalf of the City of Benicia. Prepared by MR W and Associates, October 2014 (MR W Risk Assessment) 4. MCE and PG&E Power Mix Comparison 5. Electricity Rate Comparison 6. Net Energy Metering Program Comparison 7. MCE Joint Powers Authority Agreement (JPA Agreement) 8. Letter to City of El Cerrito City Council from Adams Broadwell Joseph and Cardozo on behalf of the International Brotherhood of Electrical Workers. May 16,2014 (JBEW Letter) ---PAGE BREAK--- Marin Clean Energy, 2014 Page 1 of 8 Marin Clean Energy Applicant Analysis for the City of El Cerrito October 7, 2014 SUMMARY MCE’s currently effective policy regarding new membership requires the completion of a quantitative analysis as part of the preliminary evaluative process. The primary focus of the quantitative analysis is to determine the anticipated net rate impacts that would affect MCE’s existing customer base following the addition of the prospective new community – in particular, the quantitative analysis must demonstrate that the addition of the prospective new community will result in a projected net rate reduction for MCE’s existing customer base; this is a threshold requirement that must be met before proceeding with further membership activities. In addition, the quantitative analysis addresses the projected environmental impacts that would result from offering CCA service to the prospective new community. More specifically, the analysis prospectively determines whether or not the new community will accelerate greenhouse gas (GHG) reductions (beyond those reductions already achieved by MCE’s existing membership) while increasing the amount of renewable energy being used within California’s energy market. MCE has been in discussion with the city of El Cerrito periodically since September of 2013. In July of 2014, MCE received a formal letter from the city of El Cerrito requesting consideration as a member of MCE. The electric accounts to be considered as part of this membership request include all accounts located within the city of El Cerrito. On September 4, 2013, the MCE Board of Directors authorized completion of a quantitative membership analysis related to El Cerrito’s membership request. This analysis has been completed and the results are discussed below in this summary report. In general, the quantitative analysis indicated that rate benefits would likely accrue to existing MCE customers following the addition of prospective CCA accounts located within the city of El Cerrito. The additional customer base within El Cerrito would likely result in an approximate 1% rate reduction for MCE customers, including all existing and prospective accounts. The analysis also indicated that including El Cerrito in MCE’s membership would increase the amount of renewable energy being used in California’s energy market by approximately 16 thousand MWh per year while reducing GHG emissions by an estimated 5 million pounds of carbon dioxide equivalent per year.1 ANALYSIS MCE conducted an analysis of the potential new electric customers to estimate the revenues and costs associated with extending MCE service to El Cerrito. The analysis incorporated historical electric usage data provided by PG&E for all current electric customers located within the city of El 1 GHG emission reduction estimates are based on MCE’s actual 2012 emission factor of 373 lbs CO2e/MWh and PG&E’s reported 2012 emission factor of 445 lbs CO2e/MWh, as released in June 2014: http://www.pgecurrents.com/2014/02/06/new-numbers-confirm-pge%E2%80%99s-energy-among-the-cleanest- in-nation/. The projected GHG savings of 72 lbs CO2e/MWh (based on the difference between MCE’s emission factor and PG&E’s emission factor) was multiplied by the projected increase in MCE’s annual sales volume resulting from the addition of CCA customers located within El Cerrito, a volume approximating 64,000 MWh/year. Note that these projections are subject to change. Agenda Item No. 7 Attachment 1 ---PAGE BREAK--- Marin Clean Energy, 2014 Page 2 of 8 Cerrito. The data indicate the potential for over 11,500 new MCE customers with a potential increase in annual electricity sales approximating 80,000 MWh per year. The aggregate peak demand of these customers is estimated at 14 MW.2 Table 1: 2013 El Cerrito Electricity Data Classification Accounts Annual Energy (MWh) Per Account (KWh) Residential 10,778 45,460 351 Small Commercial 654 11,203 1,428 Medium Commercial 60 9,422 13,086 Large Commercial & Industrial 29 13,644 39,207 Agricultural and Pumping 0 0 0 Street Lighting 61 820 1,121 Total 11,582 80,550 580 Peak Demand (MW) 14 2 These figures are for all electric customers of PG&E within the City of El Cerrito. These figures are unadjusted for expected customer participation rates. ---PAGE BREAK--- Marin Clean Energy, 2014 Page 3 of 8 As compared to the current MCE customer base shown in Table 2 below, El Cerrito includes proportionately more residential and fewer commercial and agricultural accounts. Those residential accounts make up more than half of the energy usage in El Cerrito. Power usage per customer in all classes is also lower across El Cerrito than in MCE’s current communities. Table2: 2013 MCE Electricity Data (Including Napa and San Pablo) Classification Accounts Annual Energy (MWh) Per Account (KWh) Residential 126,665 730,136 480 Small Commercial 14,126 243,692 1,438 Medium Commercial 1,158 214,681 15,455 Large Commercial 452 259,144 47,771 Industrial 21 134,704 543,253 Agricultural and Pumping 1,466 19,286 1,096 Street Lighting 1,058 15,700 1,237 Total 144,944 1,617,343 930 Peak Demand (MW) 276 In regards to seasonal consumption patterns, El Cerrito electric usage peaks during the winter months consistent with the current MCE load profile. Comparison of Figure 1 and Figure 2 below shows a very similar seasonal consumption pattern between El Cerrito and the existing MCE program. ---PAGE BREAK--- Marin Clean Energy, 2014 Page 4 of 8 Figure 1: El Cerrito Hourly Load Profile (KW) ---PAGE BREAK--- Marin Clean Energy, 2014 Page 5 of 8 Figure 2: MCE Hourly Load Profile (KW) RATE IMPACTS For purposes of the rate impact analysis, it was assumed that service would be initiated to El Cerrito customers in May, 2015 and that 80% of customers who would be offered CCA service would elect to participate in the MCE program. This would equate to an increase in annual MCE electricity sales of 64,440 MWh or approximately The rate impact was examined beginning with the 2015/2016 fiscal year, with the new service accounts switched to MCE service during the month of May (May 1st through May 31th, depending on each customer’s scheduled meter reading schedule).3 It is important to note that any rate/financial impacts were based on wholesale electricity pricing at the time the quantitative analysis was completed. Such pricing is subject to change. Actual rate/financial impacts will be based on wholesale electricity pricing that is offered to MCE at the time of power supply contract execution. Incremental revenues and costs were quantified for the additional El Cerrito customers, and the revenue surplus (based on the difference between projected revenues and costs directly related to the addition of El Cerrito customers) was also calculated for the year. The surplus is assumed to offset a share of MCE’s fixed costs and can be used to reduce overall MCE rates. The incremental cost analysis accounts for ongoing costs related to additional power supplies, customer billing, customer service support (call 3 During the first year, the increase in annual sales volume is lower, estimated at 59,153 MWh, due to the gradual transfer of accounts to MCE service during the first month. ---PAGE BREAK--- Marin Clean Energy, 2014 Page 6 of 8 center), and PG&E service fees associated with the additional customers. One-time costs associated with the expansion of MCE to El Cerrito are not included in these figures and are discussed below. Table 3 presents the estimated rate impact for the 2015/2016 fiscal year. Table 3: FY2015/2016 MCE Rate Impact from El Cerrito Volume (MWh) 59,153 Revenue $ 4,754,861 Costs Power Supply Cost $ 3,473,502 Billing and Other Costs $ 222,734 Total Cost $ 3,696,236 Rate Benefit $ 1,058,624 MCE Rate Impact 1% The rate impact analysis indicates that the addition of El Cerrito customers to MCE’s total customer base would provide benefits to MCE ratepayers; it is estimated that expanding MCE service to El Cerrito would allow for MCE rates to be 1% lower than without such customers. Additional costs related to the expansion would be incurred prior to initiation of service to the new customers. These costs would be incurred for regulatory, resource planning and procurement activities that would be necessary to incorporate the new member community and its customers into MCE as well as for communication and outreach to the new customers. The projected implementation costs related to an El Cerrito expansion are expected to be less than the $250,000 expended in preparation for the expansion to Richmond. This appears to be a reasonable assumption because existing staff (previously added to support the Richmond expansion) and technical resources can be leveraged to support the El Cerrito expansion; the number of prospective customer accounts within El Cerrito is also less than a third of the prospective customer base that was transitioned to MCE service during the Richmond expansion. It should also be noted that the regulatory, resource planning and procurement costs would not be entirely attributable to El Cerrito if there are other new members brought into MCE at the same time. To the extent that other municipalities are contemporaneously added, such activities could be performed jointly rather than at separate times for each new member. RENEWABLE ENERGY IMPACTS Renewable energy requirements were calculated for El Cerrito to ensure compliance with the statewide Renewables Portfolio Standard (RPS) as well as the more aggressive MCE renewable energy content standards adopted by MCE. The total renewable energy requirement associated with prospective expansion to El Cerrito would be approximately 32 thousand MWh annually. This renewable energy volume is equivalent to the energy produced by 4 MW of geothermal capacity (or a similar baseload renewable generating technology using a fuel source such as biomass or landfill gas) or approximately 12 MW to 18 MW of solar generating capacity, depending upon location and technology. Including El Cerrito’s electric customers in MCE service will increase the amount of renewable energy being used in ---PAGE BREAK--- Marin Clean Energy, 2014 Page 7 of 8 California’s energy market by approximately 16 thousand MWh annually based on the increased renewable energy procurement targets voluntarily adopted by MCE’s governing Board relative to California’s then-current RPS mandate (which must be followed by PG&E). GHG IMPACTS With regard to projected GHG emission reductions that would result from the expansion of MCE service to El Cerrito, estimates were derived by comparing the most current, validated emission statistics related to the MCE and PG&E electric supply portfolios. With regard to these statistics, PG&E and MCE both recently reported their respective emission statistics for the 2012 calendar year. Due to typical timelines affecting the availability of such information, PG&E’s current statistics (focused on the 2012 calendar year) will generally reference data related to utility operations occurring 12 to 24 months prior to the current calendar year. This waiting period is necessary to facilitate the compilation of final electric energy statistics customer energy use and renewable energy deliveries) and to allow sufficient time for data computation, review and third-party audit before releasing such information to the public. As noted by PG&E, its 2012 emission factor was determined to be 445 lbs CO2/MWh. By comparison, MCE’s aggregate portfolio emission factor for the 2012 calendar year was determined to be 373 lbs CO2e/MWh, a difference of 19%. MCE’s 2012 emission factor was derived by using publicly available emission statistics determined by the California Air Resources Board (CARB) for certain unspecified electricity purchases included within the MCE supply portfolio as well as assumed zero carbon emission rates for various renewable energy purchases and deliveries from non-polluting power sources, such as hydroelectric generators. With regard to electricity purchases from unspecified sources, or “system power,” as reported on a California retail electricity seller’s annual Power Content Label, CARB has assigned an emissions rate of 943.58 lbs CO2e/MWh. This emission rate can be referenced in section 95111(b)(1) of CARB’s February 2014 update to the Regulation for the Mandatory Reporting of Greenhouse Gas Emissions: http://www.arb.ca.gov/cc/reporting/ghg-rep/regulation/mrr-2013-clean.pdf. PG&E appears to have applied a similar factor when calculating emissions associated with unspecified generating sources. In 2012, MCE’s supply portfolio was heavily weighted towards non-carbon emitting resources. In fact, over 60% of MCE’s energy supply was attributable to various renewable energy and hydroelectric purchases, which do not emit GHGs (MCE’s 2013 and 2014 procurement percentages reflect similar ratios). When determining MCE’s aggregate portfolio emission factor, the aforementioned CARB statistic of 943.58 lbs CO2e/MWh was applied to MCE’s system energy purchases, which totaled 225,593 MWh during the 2012 calendar year. All other non-emitting resources were assigned an emission factor of zero. As such, MCE’s portfolio emissions for the 2012 calendar year totaled approximately 213 million pounds. This emission total was divided by MCE’s aggregate sales volume of 570,144 MWhs, resulting in an MCE portfolio emissions rate of 373 lbs/MWh, for the 2012 calendar year. The following table provides additional detail regarding these emissions computations for MCE’s 2012 supply portfolio. ---PAGE BREAK--- Marin Clean Energy, 2014 Page 8 of 8 Table 4: MCE 2012 Greenhouse Gas Emissions 2012 Calendar Year MWh Purchased/Sold % Total Emission Rate (lbs CO2e/MWh) Total Emissions (lbs) Total Renewable Energy 304,551 53.4% 0 0 RPS – Eligible 166,522 29.2% 0 0 Non-RPS Eligible Renewable 138,029 24.2% 0 0 Zero Carbon 40,000 7.0% 0 0 System Power 225,593 39.6% 944 212,864,133 Totals 570,144 100% 373 212,864,133 To estimate the projected GHG emissions reductions that would likely result from the addition of prospective CCA customers located within the city of El Cerrito, MCE calculated the difference between its own emission factor (373 lbs CO2e/MWh) and the related metric reported by PG&E (445 lbs CO2/MWh): 72 lbs CO2/MWh. This difference was multiplied by the projected increase in annual electricity sales that would result from the addition of El Cerrito’s CCA customers (64,440 MWh), resulting in a projected GHG emissions savings related to the transition of El Cerrito’s customers to MCE’s cleaner electricity supply. The projected emissions savings/reduction related to this service transition (from PG&E to MCE) was determined to be approximately 5 million pounds of carbon dioxide equivalent per year. It is noteworthy that the future emission factors reported by MCE and PG&E will likely differ from the statistics applied in this analysis – this is due to a variety of factors, including planned/unplanned changes in renewable energy procurement (including planned increases in California’s RPS procurement requirements), variations in hydroelectric power production (which may change substantially from year to year based on prevailing regional hydrological conditions) and changes/adjustments in the general procurement policies of each service provider as well as many other factors. Also note that MCE has committed to assembling a power supply portfolio that not only exceeds the renewable energy content offered by PG&E but also provides customers with a “cleaner” energy alternative, as measured by a comparison of the portfolio GHG emission rate (or emission factor) published by each organization. As such, MCE plans to continue procuring electricity from non-GHG emitting resources in sufficient quantities to maintain an emission rate that is continually lower than PG&E’s. ---PAGE BREAK--- Agenda Item No. 7 Attachment 2 ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- Risk Assessment of Participation in the Marin Clean Energy Community Choice Aggregation Program On Behalf of the City of Benicia MRW & Associates, LLC 1814 Franklin Street, Suite 720 Oakland, CA 94612 October 29, 2014 Agenda Item No. 7 Attachment 3 ---PAGE BREAK--- October 29, 2014 i MRW & Associates, LLC Contents 1. Introduction and Background 1 1.1 Background on Marin Clean Energy 1 1.2 Background on Potential MCE Membership for Benicia 1 1.3 Scope of Assignment 2 2. Benefits of Participation in MCE 4 3. Risks of Participation 6 3.1 Procurement-Related Risks 7 3.1.1 Background on MCE’s Power Procurement Program 8 3.1.2 Uncertainty in Amount of Power to Procure 9 3.1.3 MCE’s Current Power Supply Agreement May Not be Able to Accommodate the City’s (or Other Cities’) Loads at Comparable Prices 10 3.1.4 Term of Power Supply Agreement 10 3.1.5 Approach for Providing “Green” Power 10 3.2 Regulatory and Policy Risks 11 3.2.1 Departing Load Fee 11 3.2.2 CCA Bonding Obligation 11 3.2.3 Meaning of MCE’s Commitment to “Meet or Beat” PG&E Rates 12 3.2.4 CARE (Low-Income) Rate Policies 12 3.2.5 Timing and Rates for Customers Taking Service in Later Phases of MCE’s Development 13 3.2.6 Planned For And Existing MCE Service Expansions 13 3.3 Potential Risks Faced by the City’s Electric Consumers 16 3.3.1 MCE May Be Unable to Procure Power for its Incremental Light Green Customers at Prices that Meet or Beat PG&E 16 3.3.2 Uncertainty in Exit 16 3.3.3 CARE Customer Issues 17 3.3.4 Regulatory Changes Adversely Affect MCE Customers 18 3.4 City’s Potential Financial Obligations to MCE 18 3.4.1 Need for City to Provide Backstop Support to MCE Power Suppliers 18 3.4.2 Lenders Requiring MCE Members to Provide Balance Sheet Guarantees for Generation Assets 18 3.4.3 Contingency for Dissoving MCE 19 3.4.3 Impacts on Utility Franchise Fee and Tax Collections and Remittances 19 ---PAGE BREAK--- October 29, 2014 ii MRW & Associates, LLC 4. Review of MCE Rate Comparison and Applicant Analyses 21 4.1 MCE Rate Comparison Analysis 22 4.1.1 Key Factors 23 4.1.2 Rate Comparison Conclusions 25 4.2 MCE Applicant Analysis 25 4.3 Organizational Soundness (Long-Term Viability) 26 4.3.1 The Marin Clean Energy Joint Powers Agreement 27 4.3.2 Marin Clean Energy Management Structure 28 4.3.3 Current Financial Position of Marin Clean Energy 28 4.3.4 Projections 29 4.3.5 MCE Debt 31 4.3.6 Conclusions Concerning Long-Term Viability 32 5. Conclusions 33 Appendix 1: MRW and Sage Qualifications 34 MRW & Associates 34 Sage Renewables 36 Appendix 2: Sage Renewables Assessment of the Risks to the City’s Net Energy Metered Solar Accounts 38 ---PAGE BREAK--- October 29, 2014 iii MRW & Associates, LLC Acronyms Used CARE California Alternate Rates for Energy CCA Community Choice Aggregation CAISO California Independent System Operator CPUC California Public Utilities Commission CRS Responsibility Surcharge GHG greenhouse gas JPA Joint Powers Authority kWh kilowatt-hour MCE Marin Clean Energy MEA Marin Energy Authority MRW MRW & Associates, LLC NEM Net Energy Metering PCIA Power Charge Indifference Amount PPA Power Purchase Agreement PG&E Pacific Gas & Electric PV Photovoltaic RPS Renewable Portfolio Standard SENA Shell Energy North America ---PAGE BREAK--- October 29, 2014 iv MRW & Associates, LLC Executive Summary Marin Clean Energy (MCE), formerly the Marin Energy Authority (MEA), is a Joint Powers Authority (JPA) consisting of the City of Belvedere, Town of Corte Madera, Town of Fairfax, City of Larkspur, City of Mill Valley, City of Novato, City of Richmond, Town of Ross, Town of San Anselmo, City of San Rafael, City of Sausalito, Town of Tiburon, and the County of Marin. MCE is considering allowing the City of Benicia to become a member of the JPA and participate in the MCE Community Choice Aggregation (CCA) program. Benicia retained MRW & Associates, LLC to examine the risks associated with joining MCE and review the “Marin Clean Energy Applicant Analysis for the City of Benicia” as part of its due diligence related to participation in MCE. MRW’s scope of work consists of the following tasks: Risk Assessment. MRW developed an independent assessment of the following: • Potential risks to City electricity customers including residents and businesses if Benicia joins MCE. • Potential risks to the City itself including, potential financial issues/obligations if it chooses to join, including but not limited to: a. earnings expectations and assumptions of customer base b. investments, debt, and reserve goals and strategies, c. Utility User Tax collections and remittance, and d. Franchise Fees collection and remittance. • Planned for and existing MCE service expansions. • Status of MCE electricity generation projects and debt issued/owed associated with these projects. • California Alternative Rates for Energy (CARE) customer issues. Review of MCE Membership Analysis: For this task, MRW reviewed the analyses provided by MCE and assessed: • reasonableness of assumptions and approaches used in the analysis; • appropriateness of the analysis undertaken; • reasonableness and completeness of the conclusions from the analysis including the revenue surplus predicted if Benicia joins; and • the organizational capacity, stability, and long-term viability of MCE as a business/organization considering its guiding documents and financial statement, including but not limited to: a. earnings expectations and assumptions of customer base, b. ability to maintain its net metering credit payout program, and c. investments, debt, and reserve goals and strategies. Assess the impact of MCE membership on City solar accounts: For this task, Sage Renewables, a subcontractor to MRW, evaluated: ---PAGE BREAK--- October 29, 2014 v MRW & Associates, LLC • Anticipated annual electrical energy costs for transitioning the ten City electrical accounts that currently have solar PV systems from PG&E to MCE. • MCE’s evaluation indicating that approximately $60,000/year may be paid to the City under MCE’s Net Energy Metering (NEM) program. • Ability of MCE to maintain its net metering credit payout program • Impacts to net-metering solar rates particularly as they relate to AB327. Participation in MCE does not come without risks. However, remaining a customer of PG&E also involves risks, although those risks may be less easily identifiable. It is up to the policymakers of Benicia to determine if the benefits associated with participation in MCE justify the risks. If Benicia joins MCE, it would allow its citizens and businesses the opportunity to take commodity electric service from MCE. By law, if a customer does not make the conscious choice to opt out from the program and remain with PG&E for commodity electricity service, then they would, by default, become a customer of MCE. The opt-out requirement effectively means that despite the many opt-out notices that MCE is required to send out, some customers could become MCE customers without necessarily intending to do so. This could be a problem because different stakeholders have different values and risk preferences. For example, one customer might be extremely price-sensitive and would not tolerate higher rates for electric service, while another customer might be willing to pay more for electric service in order to obtain power from renewable energy sources. According to MCE, participation in MCE can provide the citizens and businesses of Benicia with certain benefits. These include:  Greater levels of power supply from renewable energy sources than offered by PG&E at competitive costs  Reduced greenhouse gas emissions as a result of participation in MCE  Alternative power supply opportunities for MCE customers, including self-generation of renewable energy through MCE-sponsored feed-in tariffs  Development of local renewable resources to supply power to MCE  Economic development benefits resulting in more jobs and tax revenues  Rebates to encourage investments in energy efficiency improvements in homes and businesses  Greater local control over power supply decisions and rate setting. MRW generally concurs with these benefits, although as will be discussed at length, “competitive costs” may not always be achieved, while other elements, such as local economic development, are difficult if not impossible to quantify. MRW has identified a wide range of potential risks that the City of Benicia, its residents and businesses (if they do not opt out of service from MCE) would face were it to join MCE. Some of these risks are more significant while others are less so. The types of risks fall into several broad categories: ---PAGE BREAK--- October 29, 2014 vi MRW & Associates, LLC  Procurement Risks: This broad category of risks relates to the ability of MCE to procure power at reasonable costs, to avoid significant under- or over-procurement, and the future success of MCE at renewing power supply agreements.  Regulatory Risks: These risks consist of uncertainty in regulatory decisions by the California Public Utilities Commission (CPUC) that could adversely affect the costs that customers have to pay to take service from MCE, such as exit fees paid by customers and bonding requirements for MCE.  MCE Policy Risks: While all JPA members have a voice on the MCE Board, no single city can control policy. Thus, given Benicia’s differing demographic, economic, and business composition relative to Marin County and Richmond, Benicia might find that the interests of its citizens and businesses are not always well served by decisions of the MCE Board.  Customer Cost Risks: These risks consist of the uncertainty in exit fees, whether MCE can continue to “meet or beat” PG&E’s costs of service, how MCE will handle adding different tranches of customers in the future, and the uncertainty in costs that are passed through directly from the CCA’s power supplier to customers. This also includes the risk that MCE may not be willing, or able, to provide low-income customers rates that will be no higher than PG&E’s.  City-Specific Risks: These risks relate to risks that Benicia might bear simply by becoming a member of MCE, separate and apart from any risks that it might bear as a customer purchasing power from MCE. The table on the following page summarizes the risks discussed in greater detail in the body of the report. The table categorizes the risks based on the type of risk procurement, customer costs), the entity that bears the risk (citizens or the City) as well as the relative importance of the risk in terms of the impact that it might have on customer costs or viability of the CCA. While MRW expects that MCE will in general be able to offer competitive prices, the most significant risk is still whether MCE will ultimately be able to provide long-term power supplies at costs that are less than PG&E could provide. Thus, if the City’s customers are highly price sensitive, then this risk may be of greater concern and would indicate that the City should place a premium on ensuring the its citizens and businesses are fully informed about the opt-out requirements of MCE. Based on the legal analysis prepared by the Town of Ross and Davis Wright Tremaine, MRW does not believe that the City would have any financial liability in the event that MCE fails. ---PAGE BREAK--- October 29, 2014 vii MRW & Associates, LLC Description of Risk Magnitude or Importance of Risk Procurement Risks Volume Risk: Uncertainty in load can cause under- or over-procurement Medium Future Price Risk: MCE cannot procure power for incremental customers at competitive costs Medium Expansion of CCA: Can current contract accommodate all new customers? low Contract Renewal: MCE cannot procure power at competitive prices at end of current agreement High Regulatory and Policy Risks Adverse CPUC Decisions: Exit Fees and bonding costs may be higher than expected Medium MCE’s lack of low-income ratepayer policy Low Benicia’s interests may not always align with that of other JPA members Medium Customer Cost Risks PG&E Exit Fees: Who bears risk of changes in exit fees? High Uncertainty in Departing Load Fees: How much must customers pay to exit CCA after opt-out period ends? Low MCE Pricing Commitment: Will MCE meet or beat PG&E’s rates? High MCE Pricing Commitment: Will MCE guarantee CARE customers won’t pay more with MCE than they would have with PG&E? High City-Specific Risks Supplier Guarantees: City must provide guarantees to power suppliers Low New Generation Guarantees: City must provide support to obtain financing for new generation Low Financial liability if MCE fails Low With respect to the impact of MCE service on the City’s solar accounts, Sage Renewables found:  The City can expect between $40,000 to $80,000 in annual excess net energy metered (NEM) bill credit payments from MCE for the solar NEM accounts;  While MCE’s policy of paying for excess NEM bill credits will remain in place for at least the short term, it is at higher risk of change over time than other MCE rate policies; and ---PAGE BREAK--- October 29, 2014 viii MRW & Associates, LLC  The greatest short term risk to the value of solar PV generated energy is PG&E’s proposal to limit its solar-friendly A-6 rate to only small commercial customers. This risk exists whether the City remains a PG&E customer or elects to transition solar PV accounts to MCE. (MCE is expected to mirror changes to PG&E’s A-6 tariff with changes to its COM-6 tariff). ---PAGE BREAK--- October 29, 2014 1 MRW & Associates, LLC 1. Introduction and Background Marin Clean Energy (MCE), formerly the Marin Energy Authority (MEA) is a Joint Powers Authority (JPA) consisting of the City of Belvedere, Town of Corte Madera, Town of Fairfax, City of Larkspur, City of Mill Valley, City of Novato, City of Richmond, Town of Ross, Town of San Anselmo, City of San Rafael, City of Sausalito, Town of Tiburon, and the County of Marin. MCE is considering allowing the City of Benicia to become a member of the JPA and participate in the MCE Community Choice Aggregation (CCA) program. The City has asked MRW & Associates, LLC (MRW) to provide an assessment of the risks and benefits inherent in joining MCE. 1.1 Background on Marin Clean Energy MCE is a Community Choice Aggregation (CCA) program. As a CCA program, MCE provides commodity electric service and other energy-related services to its customers. MCE, the first fully functioning CCA in California, has been providing these services to a subset of the customers in its service area since May 2010. Full service throughout all its initial Marin County service area was completed by July 2012. It began service to the City of Richmond in July 2013, and projects to begin service Napa County in February 2015, and to the City of San Pablo in May 2015. Presently, MCE offers two electric supply products: 1. The Light Green product, which provides electric service that has a greater penetration of California Certified renewable resources (50%) than does the incumbent electric utility, Pacific Gas & Electric (PG&E). MCE contends that this energy supply option is cost- competitive with PG&E’s retail rates. 2. The Deep Green product, which provides 100% California Certified renewable resources for a $0.01 per kWh surcharge on top of the charges for the Light Green product. 1.2 Background on Potential MCE Membership for Benicia After its successful expansion to the City of Richmond, a number of other cities and towns approached MCE about membership. In response, the MCE Board of Directors (MCE Board) adopted Policy 007, which laid out the requirements of new affiliate membership. These include: 1. All applicable membership criteria (listed below) are satisfied; 2. New community is located in a county that is not more than 30 miles from MCE existing jurisdiction; and 3. Customer base in new community is 40,000 or less. In some circumstances, MCE will consider allowing a special consideration member to join if all membership criteria are met and the community is more than 30 miles from MCE’s existing jurisdiction or the customer base in the new community is greater than 40,000. ---PAGE BREAK--- October 29, 2014 2 MRW & Associates, LLC MCE’s membership criteria include:  Allowing for MCE service in new community will result in a projected net rate reduction for existing customer base;  Offering service in new community will enhance the strength of local programs, including an increase in distributed generation, and will accelerate greenhouse gas reductions on a larger scale;  Including new community in MCE service will increase the amount of renewable energy being used in California’s energy market;  There will be an increase in opportunities to launch and operate MCE energy efficiency programs to reduce energy consumption and reliance on fossil fuels;  New opportunities are available to deploy local solar and other distributed renewable generation through the MCE Net Energy Metering Tariff and Feed-In Tariff;  Greater demand for jobs and economic activity is likely to result from service in new community; and  The addition of the new community is likely to create a stronger voice for MCE at the State regulatory level. The “Marin Clean Energy Applicant Analysis for the City of Benicia” report (MCE Applicant Analysis), dated August 29, 2014, demonstrates compliance with the first criterion. The remaining criteria are qualitative, but we have no reason to believe that Benicia’s application would fail any of them. 1.3 Scope of Assignment The office of Benicia’s City Manager approached MRW to conduct an independent third-party analysis of the potential risks to Benicia associated with joining MCE. The Scope of MRW’s analysis includes the following: Risk Assessment: MRW developed an independent assessment of the following:  Potential risks to City electricity customers including residents and businesses if Benicia joins MCE;  Potential risks to the City itself, including potential financial issues/obligations if it chooses to join;  Planned and existing MCE service expansions;  Status of MCE electricity generation projects and debt issued/owed associated with these projects; and  California Alternative Rates for Energy (CARE) customer issues. Review of MCE Membership Analysis: For this task, MRW reviewed the analysis provided by MCE and assessed:  Reasonableness of assumptions and approaches used in the analysis; ---PAGE BREAK--- October 29, 2014 3 MRW & Associates, LLC  Appropriateness of the analysis undertaken;  Reasonableness and completeness of the conclusions from the analysis including the revenue surplus predicted if Benicia joins; and  The organizational capacity, stability, and long-term viability of MCE as a business organization, considering its guiding documents and financial statement, including but not limited to: o Earnings expectations and assumptions of customer base; o Ability to maintain its net metering credit payout program; and o Investments, debt, and reserve goals and strategies. In addition, attached to this report as Appendix 2 is a supplement prepared by Sage Renewables addressing the impact of changing electric energy service providers from PG&E to MCE for the ten City electricity accounts that have solar PV systems currently installed. Appendix 1 summarizes MRW’s and Sage Renewables qualifications related to this assignment. It is important to note that this report cannot attempt to evaluate or quantify all possible benefits and risks to all possible Benicia stakeholders residential customers, businesses, municipal accounts) or all associated benefits and risks of remaining on PG&E service. The perspectives of all that might be impacted are too diverse and unforeseeable events can occur. As such, the assessment must be viewed as being only one part of the assessment of participation by Benicia in MCE. One additional point must be stressed: If Benicia decides to join MCE, the City is merely providing its citizens and businesses with the opportunity to take service from MCE: customers have the ability to opt-out from MCE and to remain customers of PG&E. However, customers must take conscious action to remain with PG&E; if they do nothing, they will become customers of MCE. MCE is required, by law, to provide at two notices prior to starting service (post-cards, flyers, etc.) to all potential MCE customers informing them of this opt-out option. After MCE begins service, customers’ bills will clearly identify MCE as their power provider. Again by law, customers then have an additional 60 days to opt-out with no consequences. Once a CCA is in place, new electric customers starting service in the CCA’s area are automatically enrolled in MCE service. Both PG&E and MCE notify the new customer that they are automatically an MCE customer, and informed that that have 60 days to opt-out of MCE service. Customers may opt out after 60 days of MCE service, but are subject to an MCE charge of $5 (residential) or $25 (non-residential) and cannot return to MCE service for one year. Even with the opt-out notices, it is likely that some citizens or businesses would become MCE customers effectively without their knowledge or consent. This could be a problem for Benicia’s policymakers if the potential benefits and risks of participation in MCE are not consistent with the risk preferences and other goals of the citizens and businesses that become MCE customers by default. ---PAGE BREAK--- October 29, 2014 4 MRW & Associates, LLC 2. Benefits of Participation in MCE Since its inception, and even prior to delivering its first kilowatt-hour, MEA and then MCE has outlined the benefits it sees to its members of joining MCE and taking service from MCE. This section reiterates and comments upon these benefits. Some of the primary benefits potentially offered by MCE to Benicia include: Greater levels of power supply from renewable energy sources than offered by PG&E at competitive costs. It is clear that MCE’s policy and supply portfolio is designed to, and will likely achieve, greater renewable penetration than is projected to be achieved by PG&E. It will likely be able to do so at costs comparable to, or less than, PG&E. Currently PG&E does not offer an equivalent “deep green” option. However, it has proposed a Green Option program that would provide 100% renewable power to customers. That program has not been approved by the CPUC and the proposed participation fee will likely be higher than MCE’s rates for 100% renewable electricity. Competition between electric service providers will lead to more competitive rates and prices for Benicia residents and businesses. In theory, competition among suppliers will reduce prices to consumers and offer a wider variety of products in the marketplace. MCE, through its light- green and dark-green products, clearly is providing customers greater choice, but it is uncertain whether it will necessarily result in more competitive rates. Reduced greenhouse gas emissions as a result of participation in MCE. Again, it is clear that MCE’s policy and supply portfolio is designed to, and will likely achieve, a net reduction in greenhouse gas (GHG) emissions associated with electricity supply to its customers. This is because the average GHG emissions from the CCA would be lower than the marginal emissions from PG&E the actual incremental emissions that PG&E would incur if it were serving that load). However, because PG&E has large amounts of carbon-free (but not necessarily “renewable” according to the Renewable Portfolio Standard (RPS)) generation (large hydroelectric dams and the Diablo Canyon nuclear plant), PG&E’s average GHG emissions rate may at times be lower than MCE’s average emissions, even if MCE has more qualifying “renewable” generation. Even so, as long as fossil fuel is on PG&E’s generation margin, which it will be for the foreseeable future, MCE’s policies would result in reduced GHG emissions. Provision of more robust incentives to businesses and residents to sell power back to MCE and thus stimulate the local economy. Both PG&E and MCE offer net energy metering and feed-in- tariffs for small renewables generators. However, the rates paid by MCE to small renewables generators through its feed-in-tariff are greater than those offered by PG&E, and its net energy metering program is less restrictive. To the extent that MCE can maintain this price advantage over PG&E, and do so with lower transaction costs fewer “hoops” to jump through), incremental local renewable development should occur, providing local economic stimulus. Attraction of more green businesses to locate in Benicia and thus increase business-related revenues to the City and create jobs for residents, and the creation of more employment opportunities for Benicia residents and contractors through the CCA power procurement contracts. To the extent that MCE has local purchase preferences and green businesses are attracted to MCE’s offerings, incremental economic development in Benicia may occur. ---PAGE BREAK--- October 29, 2014 5 MRW & Associates, LLC Greater local control over power supply decisions and rate setting. Given that its policies are set by MCE’s Board of Directors, MCE would offer greater local control of procurement and rate-making decisions. This is in contrast to PG&E, which not only has a very large service area beyond the general Bay Area but also must comport to specific procurement orders from the CPUC. While the CPUC has some legislatively directed authority over MCE, such as setting resource adequacy or renewable standards applicable to all utilities and CCAs, the CPUC cannot dictate to MCE which power resources it can or cannot use or how to set rates. Furthermore, MCE offers more local control of the energy efficiency and distributed generation rooftop solar) programs and policies that its member cities’ residents and businesses can participate in. This can be seen, for instance, in MCE’s more favorable net energy metering policies. On the other hand, since Benicia would only have a single vote on the MCE Board, it might find that the interests of the City and its residents and businesses are not always well served by Board decisions, especially in cases where Benicia’s interests do not align with those of the other MCE members. ---PAGE BREAK--- October 29, 2014 6 MRW & Associates, LLC 3. Risks of Participation This section presents MRW’s assessment of the major risks facing customer groups and the City as a result of participation in MCE. It then examines potential risks faced by City residents if the City joins MCE. It concludes by examining potential risks to the City itself if the City were to join MCE. The following table summarizes the risks discussed in the following sections. The table categorizes the risks based on the type of risk volume, procurement, customer costs), the entity that bears the risk citizens or the City) as well as the relative importance of the risk in terms of the impact that it might have on customer costs or viability of the CCA. ---PAGE BREAK--- October 29, 2014 7 MRW & Associates, LLC Table 1 Risk Summary Description of Risk Magnitude or Importance of Risk Procurement Risks Volume Risk: Uncertainty in load can cause under- or over-procurement Medium Future Price Risk: MCE cannot procure power for incremental customers at competitive costs Medium Expansion of CCA: Can current contract accommodate all new customers? low SENA Contract Expiration: MCE cannot procure power at competitive prices at end of current agreement High Regulatory and Policy Risks Adverse CPUC Decisions: Exit Fees and bonding costs may be higher than expected Medium MCE’s lack of low-income ratepayer policy Low Benicia’s interests may not always align with that of other JPA members Medium Customer Cost Risks PG&E Exit Fees: Who bears risk of changes in exit fees? High Uncertainty in Departing Load Fees: How much must customers pay to exit CCA after opt-out period ends? Low MCE Pricing Commitment: Will MCE meet or beat PG&E’s rates? High MCE Pricing Commitment: Will MCE guarantee CARE customers won’t pay more with MCE than they would have with PG&E? High City-Specific Risks Supplier Guarantees: City must provide guarantees to power suppliers Low New Generation Guarantees: City must provide support to obtain financing for new generation Low Financial liability if MCE fails Low 3.1 Procurement‐Related Risks In late 2011, MRW provided an assessment of risks to the City of Richmond related to participation in MCE. At that time, MRW identified a number of risks that existed in the agreements and policies of MCE. Since then, MCE has extended its power supply agreement with Shell Energy North America (SENA), entered into numerous PPAs with renewable generating facilities to procure power to satisfy its customer load base, established a Feed-In ---PAGE BREAK--- October 29, 2014 8 MRW & Associates, LLC Tariff program to purchase power from small renewable generators located in the MCE service area, and begun to establish processes and procedures for resource acquisition after the end of the SENA agreement.1 This section discusses the status of the major risks that MRW identified in its review for the City or Richmond (although not all are relevant anymore). 3.1.1 Background on MCE’s Power Procurement Program MCE is responsible for procuring sufficient electrical energy, capacity, ancillary services and transmission rights to meet its customers’ needs. When MCE began serving customers, MCE outsourced most of these services to SENA under a 5-year agreement. Under that agreement, SENA would provide energy, capacity, ancillary services, scheduling coordination services, and other services to allow MCE to meet its customers’ needs and to comply with requirements associated with the State’s Renewable Portfolio Standard, the CPUC’s Resource Adequacy requirements, the California Independent System Operator’s (CAISO’s) scheduling requirements, and other requirements. The specific agreement with SENA consisted of an overarching form agreement and a set of “confirmations” that specified the key provisions of the agreement price of products, quantities, obligations for under- or over-procurement). The agreement was flexible in that it allowed MCE to substitute its own resources power purchased from parties other than SENA) for products formerly purchased from SENA. MCE’s initial rollout consisted of serving a small subset of MCE’s customers. After this “Phase MCE expanded the number of customers being served in Marin Phase 2a), which was also a small expansion of the load being served by MCE. With the final expansion of MCE’s first set of customers Phase 2b), MCE was serving all customers in its service territory that had not opted out. It is important to note that Phase 2b did NOT include the expansion to serve City of Richmond. With each expansion, MCE and SENA negotiated amended confirmations to its initial agreement. Since it started serving customers, MCE has been evaluating different power supply options (consistent with its agreement with SENA). At the present time, MCE has purchase agreements with 23 different entities. These different entities provide a variety of services renewable or non-renewable energy, capacity, renewable energy certificates2). Some of these arrangements are short-term one year) and others are long-term more than 10 years). These agreements are discussed in MCE’s latest Integrated Resource Plan.3 1 MCE entered into a second amended and restated confirmation with SENA on February 2, 2012. This amended and restated confirmation extended the term of SENA’s energy supply obligation and scheduling coordination agreement through the end of 2017. At the same time, MCE entered into a confirmation with SENA to provide capacity through December 31, 2015. Although not mentioned in the Board package, it appears that SENA provides renewable energy through 2016 to MCE under the same confirmations. The purpose of the amended and restated confirmation for energy and scheduling coordination services appears to be to lock in low non-renewable prices through the end of 2017. It is not clear why the capacity confirmation was not extended except that it appears that MCE wanted to have separate agreements for these two services, which is consistent with industry practices. To see the source documents, click on this link. 2 Renewable energy certificates (RECs) represent the renewable attribute associated with renewable generation. As part of meeting its RPS requirements, MCE is required to “retire” RECs. Once a REC is retired, it cannot be used again to meet RPS obligations. 3 MCE Integrated Resource Plan, November 7, 2013, pp. 10-12. ---PAGE BREAK--- October 29, 2014 9 MRW & Associates, LLC 3.1.2 Uncertainty in Amount of Power to Procure Based on the draft confirmation approved by the MEA Board in February 2012, SENA provides full non-renewable requirements to MCE.4 In addition, SENA provides a pre-specified quantity of renewable energy to MCE.5 Thus, MCE had to specify the quantity of renewable energy that it would receive from the supplier. In order to ensure that it received adequate renewable energy to meet its obligations, MCE either had to establish some other mechanism whereby its renewable energy requirement would be met or be willing to have SENA purchase renewable energy on a short-term basis and face price uncertainty associated with those incremental renewable purchases. This was a concern because in the event that MCE over-procures, it has to resell its excess supplies into the market (at unknown prices) and could face significant costs (or gains) from those sales. On the other hand, if MCE under-procures, then it needs to purchase power in the future at unknown rates, which could be higher (or lower) than the fixed prices specified in its Agreement when originally signed. MCE’s average retention rate since its initial customer enrollments has been 77%.6 However, MCE’s customer retention rate has increased with the last phase of its rollout to the City of Richmond (about 85%).7 MCE notes that once a new set of customers is enrolled, the customer base shows considerable stability. Thus, the largest uncertainty regarding participation levels appears to be linked to opt-outs during the initial enrollment period. While there is still significant uncertainty associated with customer opt-outs8, this uncertainty may not be as much of a risk to MCE as it was in the past. This is because the renewable portion of the SENA contract, which required specific levels of renewable purchases, is ending at the end of 2015. While MCE might enter into another agreement with SENA or another supplier, MCE notes that it is “continuing a transition from the initial full requirements contract that was used to launch MCE” and that MCE “has put into place a robust renewable energy buying program that now supplies the majority of the MCE renewable energy supplies,” and that MCE “is similarly developing an independent buying program for non-renewable energy and capacity.”9 While this program is not in place for non-renewable resources as yet, MCE appears intent on developing this capability, which might give MCE somewhat more flexibility to manage opt-out risk.10 4 A “full requirements” contract obligates the seller to meet all requirements of the buyer. In the case of SENA’s agreement with MCE, it appears that the full requirements obligation is for non-renewable energy. There is likely a price specified for the power supplied under this agreement. However, it is not possible to be certain about this since the key attachments to the confirmations were not included in the Board package. 5 The quantity is redacted from the draft agreement. 6 MCE Integrated Resource Plan, November 7, 2013, p. 7. 7 Ibid. 8 When MCE first started operations, it had assumed a 25% opt-out rate but found that its opt-out rate was actually 20%. The last tranche of customers from Richmond had an opt-out rate of 15%. Thus, while the percentage of opt- outs is decreasing, MCE is still being conservative in its assessment of opt-outs, which means that it could be over- procuring power. 9 MCE Integrated Resource Plan, November 7, 2013, pp. 7-8. 10 Under a full requirements agreement, MCE likely has to specify a quantity of energy that it wants to procure and a price for that energy. If its loads are higher than expected, then the supplier SENA) would procure power on behalf of MCE and MCE would be obligated to pay market price for that extra power. Similarly, if loads are less than expected, then SENA would have to sell MCE’s excess energy and MCE would be a risk for the difference between the contract price and the market price. If MCE were to have its own buying program, then MCE would likely have more flexibility to determine how much or little of its power supply it would need to hedge how ---PAGE BREAK--- October 29, 2014 10 MRW & Associates, LLC 3.1.3 MCE’s Current Power Supply Agreement May Not be Able to Accommodate the City’s (or Other Cities’) Loads at Comparable Prices As specified in the renegotiated contract between MCE and its power supplier (SENA), the power supplier has an obligation to serve all of MCE’s non-renewable power requirements services. However, the agreement only specifies a fixed quantity of renewable energy that the power supplier must provide. Thus, there is some uncertainty as to the pricing of power for MCE if it is successful in recruiting Benicia and other cities or counties (such as El Cerrito or Albany) because the confirmation that was signed in 2012 did not anticipate MCE’s expansion to other cities or counties.11 This has not proven to be a problem for MCE, since it has procured a significant amount of renewable energy outside of the agreement with SENA.12 In fact, MCE’s most recent amended and restated confirmation with SENA is supposed to have renewable prices that are much lower than the original confirmation. 3.1.4 Term of Power Supply Agreement The MCE agreement with SENA for non-renewable and renewable energy has been extended until 2017 and 2016, respectively. As discussed above, it does not appear that MCE plans to enter into another full requirements arrangement with a power supplier after the end of the SENA agreement. Whether or not MCE enters into another agreement with SENA or another full requirements supplier, there is still some uncertainty over the price of power that MCE will pay to supply its customers after 2017, since MCE’s “Net Open”13 position goes from 56 GWh in 2017 to 1,001 GWh in 2018 from total energy contract coverage of 96% in 2017 to 19% in 2018).14 If other cities or counties join MCE, then the Net Open position will be even larger in 2018. The pricing of the power needed to cover this Net Open position is unknown. Thus, there is some uncertainty regarding the ability of MCE to “meet or beat” PG&E’s price when it is time to renew the MCE power purchase agreement (PPA). This is because the price for market-based non-renewable energy (which is what MCE will be purchasing to satisfy its Net Open position) is highly dependent on volatile natural gas prices. PG&E’s power supply portfolio has a significant amount of generation that is not linked to natural gas prices its hydroelectric system and its nuclear generation). 3.1.5 Approach for Providing “Green” Power MCE uses a variety of approaches for providing a power supply that has a lower carbon footprint than PG&E. It purchases physical certified renewable power (that helps MCE meet its RPS much of its supply would have fixed price). Unlike with a full requirements agreement, this quantity could change over time as market conditions evolve. 11 The confirmation was amended in February of 2012 explicitly to serve Phase 2b of MCE’s load. This was several months before Richmond requested to join MCE. Thus, it is clear that the 2012 amended and restated confirmations did not anticipate the expansion of MCE. 12 In MCE’s 2013 Integrated Resource Plan, MCE had a total of 282 GWh of renewable resources, of which a total of 175 GWh were attributable to SENA. The remainder of MCE’s renewables in 2013 107 GWh) were attributable to agreements entered into outside of the SENA agreement. By 2015, MCE projects that SENA will supply only 140 GWh out of MCE’s total renewable requirements of 307 GWh. 13 The “Net Open” position is the difference between the expected load and the amount of energy that is either under contract or to be generated by MCE. Thus, a small Net Open position means that almost all of the expected load will be served by existing agreements. Conversely, a large Net Open position means that MCE does not currently have agreements in place to serve much of its expected load. 14 MCE Integrated Resource Plan, November 7, 2013, Appendix A, p. 23. ---PAGE BREAK--- October 29, 2014 11 MRW & Associates, LLC obligations), it purchases carbon-free power power from large hydroelectric facilities that is not eligible to meet MCE’s RPS requirements), and unbundled renewable energy certificates (RECs), which may or may not help MCE meet its RPS obligation in the long-run. This approach is reasonable. However, customers should be aware that purchasing RECs to “supply” renewable energy is not exactly the same as purchasing physical renewable energy. When MCE purchases RECs, it also must obtain “null energy,” which is typically not renewable. There is nothing unusual about this approach but Benicia may wish to make this distinction clear.15 3.2 Regulatory and Policy Risks This section addresses two areas. First, there are the risks to the CCA and its customers of changes in State policies, in particular the regulatory decisions made at the California Public Utilities Commission (CPUC). Second, there are the risks to the JPA member cities and their residents and businesses associated with MCE policies. We raise this second risk area because while all JPA member cities have a voice on the MCE Board, no single city can control policy. Thus, given Benicia’s differing demographic, economic and business composition relative to Marin County, Benicia’s needs and policy preferences might not be fully addressed in MCE Board decisions. 3.2.1 Departing Load Fee MCE has entered into a number of long-term PPAs for renewables, and per its integrated resource plan, intends to enter into more PPAs in the next few years. Furthermore, to undertake any future construction programs, MCE will issue debt (as is typically the case for other utilities). MCE developing its own resources or entering into long-term PPAs means it would have fixed debt service obligations to pay for its renewable resources. When MCE customers choose to leave MCE’s service after the end of the opt-out period, then either the departing customers must pay a fee to MCE or the electric rates for remaining customers could increase. MCE’s current fee for returning back to PG&E service is $5 for residential customers and $25 for commercial customers. This fee would be only applicable to customers who did not opt out during the four month opt-out window and then subsequently, at some later date, chose to take electric service from someone other than MCE.16 The current fee covers MCE’s administrative costs to return the customer to PG&E service. In the future this could include fixed MCE costs that otherwise would have to be borne by the remaining MCE customers. (PG&E’s exit fee charged to CCA customers covers such costs). 3.2.2 CCA Bonding Obligation Pursuant to CPUC Decision 05-12-041, a new CCA must include in its registration packet evidence of insurance or bond that will cover such costs as potential re-entry fees, i.e., the cost to PG&E if the CCA were to suddenly fail and be forced to return all its customers back to PG&E 15 RECs are essentially an accounting mechanism. They can either be combined with physical generation Bundled RECs) or can be separated from the physical power and used for RPS compliance Unbundled RECs). Under California’s RPS law, MCE can only use a limited number of Unbundled RECs for RPS compliance. However, there is no limitation on the use of Unbundled RECs for other purposes to “green” non-renewable power). 16 Also note that if an MCE customer returns to PG&E service after the end of the opt-out period, that customer would not continue to pay Exit Fees to PG&E; they would only have to pay Departing Load Fees to MCE. ---PAGE BREAK--- October 29, 2014 12 MRW & Associates, LLC bundled service. Currently, a bond amount for CCAs is set at $100,000, which has already been met by MCE. This $100,000 is an interim amount. In 2009, a Settlement was reached in CPUC Docket 03-10- 003 between the three major California electric utilities (including PG&E), two potential CCAs (San Joaquin Valley Power Authority and the City of Victorville) and The Utility Reform Network (TURN) concerning how a bonding amount would be calculated. The settlement was vigorously opposed by MCE and San Francisco, and never adopted. Since then, the issue of CCA bond requirements has not been revisited by the CPUC. If it is, the bonding requirement will likely follow that set for Energy Service Providers (ESPs) serving direct access customers. This ESP bond amount covers PG&E’s administrative cost to reintegrate a failed ESP’s customers back into bundled service, plus any positive difference between market-based costs for PG&E to serve the unexpected load and PG&E’s retail generation rates. Since the ESP bonding requirement has been in place, retail rates have always exceeded wholesale market prices, and thus the ESP’s bond requirement has been simply the modest administrative costs. If the ESP bond protocol is adopted for CCAs, during normal conditions, the CCA Bond amount will not be a concern. However, during a wholesale market price spike, the MCE’s bond amount could potentially increase to millions of dollars. But the high bond amount would likely be only short term, until more stable market conditions prevailed. Also it is important to note that high power prices (that would cause a high bond requirement) would also depress PG&E’s exit fee and would also raise PG&E rates, which would in turn likely provide MCE sufficient headroom to handle the higher bonding requirement and keep its customers’ overall costs competitive with what they would have paid had they remained with PG&E. Per Section 3.4, MCE JPA member entities would not be individually liable for any increase in the bond amount. 3.2.3 Meaning of MCE’s Commitment to “Meet or Beat” PG&E Rates MCE has stated that one of the benefits for customers is “Costs at or below PG&E.”17 In discussions with MRW, MCE has clarified that this is based on the projected overall costs of MCE versus forecast of PG&E’s tariffed generation rate. In other words, the following inequality must occur for MCE to sign the Agreements: MCE Power Supply Costs + Customer Exit Fees + MCE Overhead < PG&E Gen Rate18 At current rates, the total MCE cost of service (including the exit fees) is less than the PG&E generation rate. However, as discussed later, this has not always been the case, nor is it guaranteed to be so in the future. 3.2.4 CARE (Low‐Income) Rate Policies To protect low-income households against escalating electricity bills, the CPUC froze rates for the California Alternate Rates for Energy (CARE) program at July 2001 levels. Currently the effective CARE discounts now range from 35% in the lowest residential rate tier up to 52% in Tier 3. While ongoing Commission action is moving to adjust its rate design to narrow this gap, 17 E.g., MEA presentation, October 2009, p. 12. 18 MEA Power Supply Costs, Customer Exit Fees, MEA Overheads, and PG&E Gen Rate are all forecasted values in early February 2010. ---PAGE BREAK--- October 29, 2014 13 MRW & Associates, LLC CARE customers will continue to receive significant discounts relative to other residential customers. The CARE discounts are administered through the “Conservation Incentive Adjustment”(CIA) element of PG&E’s residential tariffs. The CIA rate element is paid by all residential customers in PG&E’s service area, no matter if PG&E or MCE provides their power. This means that the absolute discount amount (in ¢/kWh) is independent of whether the customer is served by MCE or PG&E. However, if MCE’s residential generation rate plus the exit fee19 rate is greater than PG&E’s generation rate, the CARE customer on MCE could end up paying more than they would had they taken service from PG&E. MCE can address this issue by either recouping any incremental amount from its remaining customers or use any cash reserves to ensure that CARE customers pay no more than they would have under PG&E service. Additional CARE issues this from the customer perspective are discussed in Section 3.3.3. 3.2.5 Timing and Rates for Customers Taking Service in Later Phases of MCE’s Development MCE initially procured power for its 8,000 Phase I customers in May 2010. It has since successfully added three additional blocks of customers: 5,000 Marin County accounts were added in August, 2011; the remainder of the Marin County accounts (32,650)in July 2012, and the City of Richmond (74,000 accounts) in July 2013. This experience demonstrates that MCE can expand its customer base without adverse impacts. Furthermore, per Board Policy 007, MCE will not accept additional memberships unless it results in lower rates for the current members. This would preclude MCE from adding members at power prices higher than its existing power cost. What this means is that the risk of higher rates from additional members is very low, but that the timing of additions is more uncertain: if a community desires to join MCE but the prevailing power markets do not allow for it to do so at a net benefit for the current MCE members, it cannot do so until power market conditions change. 3.2.6 Planned For And Existing MCE Service Expansions In July 2013, the City of Richmond became the first municipality outside of Marin County to receive power from MCE. MCE will further expand its program to municipalities outside of Marin County in the near future, with plans to begin delivering power to Napa County in February 2015, and the City of San Pablo in May 2015. Presently, several other municipalities outside of Marin County are also considering membership in MCE. Like the City of Benicia, the City of El Cerrito has also taken formal steps to consider joining MCE’s service territory in 2015.20 The City of Albany has also taken formal steps to join MCE, and was approved to begin the membership analysis process by the MCE Board at the same time as Napa County in February of 2014.21 However, Albany postponed its efforts to join MCE due to the possibility 19 In PG&E’s Tariff the Exit Fee is the Power Charge Indifference Amount (PCIA). 20 Comments of Marin Clean Energy Regarding California Compliance Plan for U.S. EPA Proposed Carbon Pollution Emissions Guidelines, Marin Clean Energy, September 23, 2014, p. 2. 21 Board of Directors Meeting Agenda, Marin Clean Energy, February 2014, p. 8. ---PAGE BREAK--- October 29, 2014 14 MRW & Associates, LLC that the county in which it resides, Alameda County, may vote to form its own CCA program, described in greater detail in the sections below.22 Presently, two municipalities have publicly revealed that they are in the preliminary stages of considering membership in MCE. San Mateo County, for example, has requested information from MCE on how to join Marin’s program, but has not yet passed local legislation to further explore membership.23 The City of Arcata has also expressed the possibility of joining MCE,24 as an alternative to Humboldt County’s Redwood Coast Energy Authority’s potential CCA program.25 Municipalities That Have Decided Against Joining MCE. In recent years, the City of Berkeley and the City and County of San Francisco (CCSF), have each considered joining MCE but ultimately decided against it. Berkeley considered enrolling in MCE after it failed to succeed in forming a CCA with Oakland and Emeryville. Efforts to form a program to include these three cities culminated in September 2008, with the publication of a business plan outlining the proposed CCA.26 In November of 2008, the Emeryville City Council voted to terminate further CCA activities due to the high costs associated with program planning and the lack of City funds to pay for it.27 Oakland and Berkeley Staff also recommended that their respective city councils reject further efforts to form a CCA, due to concerns regarding higher customer costs, and payment and credit guarantees for the formation of a new agency.28 Despite Staff’s recommendations, however, Berkeley and Oakland continued with the next phase of CCA studies, with the Berkeley Energy Commission (BEC) completing a study in June 2010 to inform the Berkeley City Council on the potential benefits and risks of a joint CCA between the two cities.29 The report concluded that the CCA would face potential challenges maintaining rate parity with PG&E if attempting to offer customers electricity with a greater share of renewable generation. Increased rates may lead customers to opt-out of a CCA, making it difficult for the City to recoup its share of pre- implementation expenditures and start-up costs, ranging from $200,000 to $3.3 million. BEC found that risk associated with start-up costs would be minimal to the City if the CCA was able to retain most of its customers in the first five years.30 Overall, however, the report noted that it was difficult to determine the extent of rate parity and financial risks in practice, because at the time of publication, MCE had just started delivering power. The report did cite MCE’s success in securing a contract with SENA to supply more renewable electricity at rates equal to PG&E in its 22 Ibid. 23 Board of Directors Meeting Agenda, Marin Clean Energy, July 3, 2014, p. 16. 24 Memorandum re: Update on Community Choice Aggregation, Arcata City Council, December 19, 2013. 25 Comprehensive Action Plan for Energy, Humboldt County, September 2012, p. 11. 26 East Bay Cities Community Choice Aggregation Business Plan, Prepared by Navigant Consulting, Inc., September 2008. 27 Progress Report – December 2008, Memorandum to Mayor and City Council from City of Emeryville City Manager Patrick D. O’Keeffe, December 2008, p. 1. 28 Memo to Berkeley Energy Commission from City of Berkeley Secretary, October 22, 2008; and Memo to Oakland Office of the City Administrator from the Public Works Agency, December 16, 2008. 29 Potential Benefits and Risks of Implementing Community Choice Energy, City of Berkeley Energy Commission, June 28, 2010. 30 Potential Benefits and Risks of Implementing Community Choice Energy, City of Berkeley Energy Commission, June 28, 2010, pp. 3-4. ---PAGE BREAK--- October 29, 2014 15 MRW & Associates, LLC first year of operation as an early indication that such practice was possible among CCAs.31 The report stated that overall, the greatest financial risks of a CCA would be related to securing the debt necessary for the construction of CCA-owned electricity generation facilities.32 Efforts for a CCA in Oakland quickly extinguished due to city council issues associated with the Great Recession taking precedent over CCA formation.33 Berkeley continued to consider CCA, with the City Council passing a resolution in January 2012 demonstrating Berkeley’s intent to explore CCA with MCE, and East Bay Municipal Utility District (EBMUD), which provides water and/or wastewater services to several East Bay cities.34 However, in December 2012, the EBMUD Board of Directors voted to discontinue further exploration of a CCA, due to concerns regarding EBMUD’s fiscal health, credit rating, and financial reserves.35 After EBMUD decided not to pursue CCA, Berkeley postponed efforts to join MCE or form its own program. In February 2014 at the request of the Alameda County Board of Supervisors, the Berkeley and Oakland climate action coalitions prepared a CCA feasibility study for Alameda County.36 In June 2014, the Alameda County Board of Supervisors approved funding ($1.3 million) for a technical study on CCA program development.37 If Alameda County continues to pursue a CCA, Berkeley, Oakland, and Emeryville would be among the cities that would be serviced by the program. CCSF also considered joining MCE after it initially failed to form its own CCA program. Efforts to form a San Francisco CCA began in June 2007, when the CCSF Board of Supervisors passed an ordinance adopting a CCA program, Revenue Bond Plan, and Draft Implementation Plan.38 In December 2011, the San Francisco Public Utilities Commission (SFPUC), the agency administering the City’s CCA program, CleanPowerSF, approved a PPA between CleanPowerSF and SENA to provide the program’s customers with renewable energy for over 4.5 years.39 However, at a voting meeting held in August 2013, the SFPUC voted 3-2 against approving CleanPowerSF’s proposed not-to-exceed customer rates, due to their high cost.40 In response to the SFPUC’s denial of the program’s not-to-exceed rates, SFPUC President Art Torres, with Commissioners Courtney and Caen, commented that CleanPowerSF was not as environmentally friendly as it could be and that there remained unresolved labor issues. He encouraged the City to explore alternatives to the program.41 31 Potential Benefits and Risks of Implementing Community Choice Energy, City of Berkeley Energy Commission, June 28, 2010, p. 26. 32 Potential Benefits and Risks of Implementing Community Choice Energy, City of Berkeley Energy Commission, June 28, 2010, pp. 3-4. 33 BondGraham, Darwin, When Will We Go Green?, East Bay Express, May 30, 2012. 34 Resolution No. 65,586-N.S., Berkeley City Council, January 12, 2012. 35 Meeting Minutes, EBMUD, December 11, 2012. 36 East Bay Community Choice Energy, Berkeley Climate Action Coalition, Community Choice Working Group, Oakland Climate Action Coalition, and Clean Energy & Jobs Oakland Campaign, February 2014. 37 Board of Directors Meeting Agenda, Marin Clean Energy, July 3, 2014, p. 16. 38 Ordinance No. 07-0501, City and County of San Francisco Board of Supervisors, June 12, 2007. 39 CleanPowerSF Not-to-Exceed Electric Generation Rates Staff Report and Resolution, SFPUC, August 13, 2013. 40 Riley, Neal “PUC fails to set rates for CleanPowerSF,” SFGate, August 13, 2013, 41 Ibid. ---PAGE BREAK--- October 29, 2014 16 MRW & Associates, LLC In April 2014 San Francisco Mayor Ed Lee, who had publicly opposed CleanPowerSF, released a draft budget in which he proposed to allocate the funds set aside by the SFPUC for the CCA to GoSolarSF, a separate program supported by Lee that provided incentives for property owners to install solar panels.42 In May 2014 the CCSF Board of Supervisors approved an ordinance to study the feasibility of implementing a CCA program in San Francisco through joining MCE.43 The ordinance was returned unsigned by Mayor Lee shortly thereafter.44 3.3 Potential Risks Faced by the City’s Electric Consumers As discussed above, there were and continue to be several risks that customers of MCE face. These are discussed below. 3.3.1 MCE May Be Unable to Procure Power for its Incremental Light Green Customers at Prices that Meet or Beat PG&E In 2010, MCE successfully procured power for its Light Green customers at costs that allow those customers to have total energy bills that are less than they would have paid had they remained PG&E customers. However, at that time, PG&E’s rate design for residential customers resulted in high usage customers having very high average electric rates. Thus, MCE was able to target the specific customers in its Phase I efforts that had very high rates. MCE has not been able to use this strategy since that first phase. PG&E rate design changes in 2011 resulted in a “flattening” of PG&E’s generation rate for residential customers, meaning that high usage customers no longer pay higher—sometimes much higher—generation rates than low-usage residential customers. (Note that MCE essentially competes against PG&E’s generation rate.) This risk is discussed in detail in Section 4.1, below. 3.3.2 Uncertainty in Exit Fees Assembly Bill 117, which established the CCA program in California, included a provision that states that customers that remain with the utility should be “indifferent” to the departure of customers from utility service to CCA service. This has been broadly interpreted by the CPUC to mean that the departure of customers to CCA service cannot cause the rates of the remaining utility “bundled” customers to go up. In order to maintain bundled customer rates, the CPUC has instituted an exit fee, known as the “Power Charge Indifference Amount” or “PCIA” that is charged to all CCA customers. The PCIA is intended to ensure that generation costs incurred by PG&E before a customer transitions to CCA service are not shifted to remaining PG&E bundled service customers. Even though there is an explicit formula for calculating the PCIA, forecasting the PCIA is difficult, since many of the key inputs to the calculation are not publically available, and the results are very sensitive to these key assumptions. For PG&E, the PCIA has varied widely; for example, at one time the PCIA was negative. 42 Lagos, Marisa, “SF board to consider deal on clean-energy plan,” SFGate, June 12, 2014. 43 Meeting Minutes, CCSF Board of Supervisors, May 20, 2014, p. 3. 44 Legislation 140415, CCSF Board of Supervisors, May 29, 2014, available at: DFE4756E26B5 ---PAGE BREAK--- October 29, 2014 17 MRW & Associates, LLC MCE’s current policy is that customers bear the financial risk associated with the level of exit fees they will pay to PG&E. Thus, for a customer taking MCE service to be economically better off pay less for electricity), the sum of the MCE charges plus the PCIA must be lower than PG&E’s generation rate. As noted above this has not consistently been the case for MCE residential customers. MCE has intervened vigorously at the CPUC to minimize the size and scope of PG&E’s exit fees. For example in 2009 is co-sponsored testimony in Rulemaking 07-05-025 which revised the PCIA to better account for renewable portfolio standard requirements. It has also petitioned the Commission to open a Rulemaking to reconsider all exit fees and participated the last two “ERRA” proceedings in which the annual exit fees are set. MRW expects MCE to continue to have an active presence at the CPUC, advocating for lower and more limited exit fees. 3.3.3 CARE Customer Issues As mentioned in Section 3.2.4, current MCE policy does not ensure that CARE customers will not pay more under MCE than they would had they taken service from PG&E. The table below shows the generation rates offered by PG&E and MCE for a standard residential CARE customer. MCE’s generation rate for residential customers (including those on CARE service) are 1.6¢/kWh less than PG&E’s rates. However, MCE’s rate does not include PCIA, a rate element that is applicable only to CCA customers. When adding in the PCIA, currently 1.1¢/kWh, the low-income customer taking service from MCE would still be paying a rate below that offered by PG&E. Thus, given current rates, low-income customers are better off with MCE. However, that has not always been the case. When MRW conducted an analogous analysis in 2011 for the City of Richmond, the rates in place at that time would have resulting in CARE customers (using 400 kWh per month) paying approximately $100 more per year on MCE service than on PG&E service. However by the time Richmond joined MCE in 2013, PG&E’s generation rates were greater than MCE’s rate plus exit fee, so the issue of CARE customers paying higher bills under MCE was made moot. Given current rate trends, MRW expects CARE customers to pay less for power with MCE in 2015 than they would with PG&E. Nonetheless, given MCE’s current policies, there is no guarantee this will be the case in all years. Table 2. CARE Rate Comparison (current tariffs), ¢/kWh PG&E Schedule EL‐1 MCE Schedule RES‐1 Difference Generation Rate 9.5 7.9 (1.6) PCIA (Vintage 2014) n/a 1.1 1.1 Total 9.5 9.0 (0.5) ---PAGE BREAK--- October 29, 2014 18 MRW & Associates, LLC Issue: Other Customers Subsidizing CARE Customers If MCE changes its policy and decides to ensure that MCE’s net CARE rate is no higher than PG&E’s CARE rate, then in years when the MCE rate plus exit fee is greater than PG&E’s generation rate, MCE would need either to marginally raise rates for the other MCE customers, or use its reserves to finance the MCE CARE customers. A question that would likely be raised would be, how willing are MCE’s ratepayers in other jurisdictions to subsidize low-income customers in Benicia, and vice versa? MRW does not know the answer to this question but we believe that it could present a political and public relations challenge for Benicia officials as well as MCE. 3.3.4 Regulatory Changes Adversely Affect MCE Customers Regulatory changes could make MCE’s power costs uncompetitive with PG&E. As discussed elsewhere, the CPUC establishes exit fees that customers of MCE have to pay. Such decisions have occurred in the past MCE and others advocated strongly in opposition to PG&E’s effort to flatten its generation rate, but these efforts proved unsuccessful). Also, as discussed above, the CPUC could adopt bonding requirements that would significantly increase the cost of security bonds for MCE, which would also tend to undermine the ability of MCE to provide electricity to its customers at a rate that meets or beats PG&E’s rates. 3.4 City’s Potential Financial Obligations to MCE The City, as a consumer of electricity, faces many of the risks discussed above. However, the City also may face other risks as a participant in MCE. This section discusses those potential risks. 3.4.1 Need for City to Provide Backstop Support to MCE Power Suppliers When MCE was originally established, it needed to fund its startup activities. At that time, it had no customers and no credit rating. Thus, MCE had to borrow funds from third parties, including the County of Marin and a number of individuals. However, shortly after it began operations, MCE was able to acquire a line of credit from River Bank, which it used to consolidate its prior start-up loans. Given its successful debt management, increase in operating reserves, and ability to enter into PPAs without member backstop support (see Section 4.3), MRW does not foresee MCE needing to rely on the City’s credit as a backstop future power supplies. Also, the JPA would insulate City’s from having to use their credit in any transaction between MCE and a power supplier (see legal analysis prepared by Davis Wright Tremaine). 3.4.2 Lenders Requiring MCE Members to Provide Balance Sheet Guarantees for Generation Assets During MRW’s 2010 review of the risks associated with participation in (then) MEA it asked MEA staff about the potential risk of cities needing to (or being forced to) provide balance sheet support to allow construction of generation assets that are owned by MEA. At that time, MRW received assurances that such balance sheet support from MEA members would not be required. This was reiterated by Executive Director Weisz at the September 27, 2010 Novato City Council meeting, where she went on to explain that the JPA structure itself protects the JPA’s members from debts incurred by the JPA. ---PAGE BREAK--- October 29, 2014 19 MRW & Associates, LLC In general, this is a legal issue and is beyond the scope of MRW’s assessment. However, MRW notes that the Town of Ross’s city attorney, Hadden Roth, investigated Ross’s liability should it join MCE. His conclusions were: …that the Town’s general fund will not be responsible for any financial obligations of MEA unless the Ross Town Council first specifically agrees in writing to assume the liability. This protection is provided under both the JPA agreement and State law.45 Therefore, MRW understands that no liability could be placed on Benicia simply by being a member of the JPA. This is consistent with the legal analysis prepared by Davis Wright Tremaine for the City of Benicia. 3.4.3 Contingency for Dissoving MCE Chapter 11 of MCE’s Revised Implementation Plan outlines a contingency for program termination. In general, MCE cannot terminate service without a majority of the Member’ governing bodies boards of supervisors or city councils) explicitly passing an ordinance or resolution to terminate MCE. The MCE Board would then vote on termination (based on the weighted voting shares described above). If the MCE Board approved termination, the Board would disband per the provisions in the JPA agreement. If possible, MCE would provide PG&E and the CPUC one year notice that it was intending to cease service and return its customers to PG&E. Customers would receive notice six months and sixty days prior to being returned to PG&E service. In the event of an unplanned collapse of MCE, all its customers would return to PG&E with no break in service. I.e., customers are at no risk of not having electricity due to the failure of MCE. Furthermore, consistent with the discussion in Sections 3.4.3 and 3.4.3 above, neither Benicia nor any other MCE member would be liable for any debts MCE might have upon its unexpected demise. 3.4.4 Impacts on Utility Franchise Fee and Tax Collections and Remittances PG&E’s Electric Rule 23, Section B.16 explicitly states that “CCA customers shall continue to be responsible to pay all applicable fees, surcharges and taxes as authorized by law. PG&E shall bill customers for franchise fees as set forth in Public Utilities Code Sections 6350 to 6354.” Franchise fees are payments that a public utility makes to a city of county government for the nonexclusive right to install and maintain equipment on the government’s right of ways. For PG&E, this includes the right to install and maintain equipment such as power poles on city sidewalks or gas pipelines underneath city streets. Franchise fees are generally calculated as a fraction of retail sales, typically on the order of a few percent. Since PG&E’s retail sales to CCA customers does not include the generation component of rates, a special adjustment must be made to ensure that a city participating in a CCA receives its fully due franchise fees. For PG&E, this is accomplished through Electric Schedule E-FFS. This 45 Minutes to the Special Meeting Of The Ross Town Council, January 12, 2010. ---PAGE BREAK--- October 29, 2014 20 MRW & Associates, LLC schedule adds 0.06-0.07¢/kWh, which is the equivalent Franchise Fee amount of the value of the power being provided by a CCA such as MCE. Thus, Benicia will receive the same amount of franchise fees under MCE service than it would under PG&E service. On behalf of the City, PG&E also collects a utility users tax equal to 4% of the PG&E bill, which PG&E remits directly to Benicia. Because PG&E would remain responsible for billing customers under MCE service, it would remain the responsible party for collecting and remitting Benicia’s utility users taxes. This is the case for Richmond, where PG&E continues to calculate, charge customers and remit that city’s utility users tax. To the extent that MCE customers’ total bills are different than they would be under PG&E service, the utility users tax would also be different. For example, MCE estimated that based on current rates, Benicia’s residents and businesses would save $1.6 million per year with MCE service. This would translate into a reduction in the utility users tax of $64,000. However this would be partially offset by an estimated annual savings of $42,000 from municipal electric accounts being served by the lower- cost MCE. A potential second order financial impact on the City would be changes to its property tax revenues. Given MCE’s commitment to net energy metered solar, renewable purchase from its Feed-In Tariff and locally-sourced power, MCE membership is more likely to increase property tax revenues (by increasing the tax base) than not. ---PAGE BREAK--- October 29, 2014 21 MRW & Associates, LLC 4. Review of MCE Rate Comparison and Applicant Analyses The MCE rate comparison spreadsheet analysis developed by MCE for the City estimates savings of $1.6 million for Benicia customers from joining the CCA. This amounts to 6.5% savings off the generation portion of Benicia customers’ PG&E bills, with much higher levels of savings for non-residential customers than for residential customers Based on this analysis, nearly all customer types would be expected to benefit from joining the CCA,46 with the largest direct benefiters being Benicia businesses, industries, and municipal accounts (Figure MRW reviewed the key assumptions and methodology used in the rate comparison analysis to evaluate the reasonableness of these benefit projections. Figure 1: Rate Savings under MCE Analysis, by Customer Class47 MRW additionally reviewed the MCE Applicant Analysis, dated August 29, 2014. The primary purpose of the analysis is to assess whether Benicia’s membership in MCE would reduce rates for existing MCE members, as is required for membership eligibility. The analysis for the City of Benicia does make this determination, finding that the added customer base from Benicia would likely reduce MCE rates by MRW reviewed this analysis to evaluate the likelihood of such rate reductions and implications for the rate comparison analysis. 46 Only the traffic control accounts were found to have higher rates under the CCA. 47 Savings percentages are with respect to the generation portion of the electric bill only. ---PAGE BREAK--- October 29, 2014 22 MRW & Associates, LLC 4.1 MCE Rate Comparison Analysis MCE customers are all joint customers of both PG&E and MCE, with PG&E providing delivery services at the same rate as provided to PG&E-only customers and MCE providing generation services at its own rate. In addition to these two rate components, MCE customers must pay an exit fee to PG&E. All three components combine to make up the electricity bill for MCE customers (Figure Figure 2: Comparison of Electricity Charges for PG&E-Only Customers and for MCE- PG&E Customers The rate comparison analysis developed by MCE provides a snapshot, high-level comparison of the annual electricity bills for Benicia residents and businesses under PG&E-only service versus under MCE-PG&E service. The comparison considers PG&E’s generation rates compared to the combination of the MCE generation rates and the PG&E exit fees that are assessed on MCE customers. Since the delivery rates are the same regardless of whether the customer joins MCE, this rate component is not considered. Consideration of only the generation rates and exit fees is appropriate for this analysis. The rate comparison was developed using average rates from August 2014 for each class of customers. For some commercial and industrial customers or residential customers on a time-of- use tariff actual average rates vary depending on electricity usage patterns and may differ substantially from the class average rate.48 For these customers, who represent a large share of the anticipated savings, MCE’s rate comparison provides only an estimated result. Since these estimates are based on average rates specifically in MCE’s service area of Marin County and the City of Richmond, they are likely, on average, to be reasonable approximations of the actual rates paid by Benicia’s customers. To the extent that actual rates differ from the average rates used in the analysis, the overall level of savings could be either higher or lower than the 6.5% savings estimated by MCE but is likely to be roughly in that ballpark. Customers would need to 48 For most residential and some small commercial customers, rates do not vary by usage pattern, and the average rates are equal to customers’ actual rates. These customers comprise one-quarter of electricity usage in Benicia. For remaining customers, rates vary by usage pattern. ---PAGE BREAK--- October 29, 2014 23 MRW & Associates, LLC evaluate their own savings potential based on their particular usage patterns. This 6.5% savings estimate is specific to August 2014 rates. The MCE rate comparison does not indicate whether August 2014 was a typical rate period or whether these savings can be anticipated going forward. This is an important consideration because PG&E’s rates typically change several times a year, and MCE’s rates change at least annually, so the relationship between PG&E’s and MCE’s rates changes frequently. 4.1.1 Key Factors Key factors influencing PG&E’s rates in the short term are the availability of water for hydroelectric generation and the costs of natural gas and renewable power. In the longer-term, a significant uncertainty with regard to PG&E’s rates is the future of the Diablo Canyon nuclear plant. If the plant is shuttered when its licenses expire in 2024 and 2025 (or sooner), the nuclear power is likely to be replaced with more expensive gas-fired and renewable power. If PG&E instead pursues a 20-year license extension for the plant, PG&E will be required to complete expensive plant upgrades in order to meet compliance requirements. On the MCE side, power procurement costs are largely driven by the costs of gas-fired and renewable power. Currently, MCE meets nearly 80% of its resource needs with conventional power, which is nearly all gas-fired power.49 While MCE plans to reduce its dependence on natural gas-fired power over time, MCE’s Integrated Resource Plan for 2013-2022 shows that this will be a slow process, with a 72% dependence on conventional power remaining at the end of the ten-year plan.50 MCE customers are also obligated to pay exit fees to PG&E. In the long-term, these fees should fall, as the contracts and power plants that they support are removed from the exit fee assessment. In the short-term, however, year-to-year variability in either direction should be anticipated based on the price of natural gas and other factors. Given all of the factors that drive rate changes, it cannot be stated with certainty that the relationship between PG&E and MCE rates observed in August 2014 will continue year-to-year; however, it is reasonable to expect that MCE rates will on average remain competitive with PG&E’s. For 2015 in particular, it is reasonable to anticipate rate savings under MCE because PG&E’s generation rates are slated to increase by an estimated 9% in 2015 compared to August 2014.51 Some of this rate increase is due to the California drought, which has severely constrained the availability of water for PG&E’s hydroelectric plants. While MCE relies on some hydroelectric 49 MCE’s power mix is made up of about 80% conventional power and also 50% renewable power. This adds up to 130% because about 30% of power deliveries are made up of conventional power that has been assigned Renewable Energy Certificates. These power deliveries are classified by MCE as renewable but they do not reduce MCE’s dependence on conventional resources. (Renewable Energy Certificates link the renewable attribute of renewable resources that are typically outside of California and not connected to the California electricity grid to physical power deliveries that are made to MCE customers, typically from conventional resources.) 50 Marin Clean Energy. Integrated Resource Plan Annual Update, November 2013, page 23. 51 PG&E’s average generation rate in August 2014 was 9.185 cents per kWh, and PG&E’s current estimate of its January 2015 generation rate is 9.992 cents per kWh. PG&E Advice Letter 4450-E-A, July 22, 2014, Attachment 2A and Advice Letter 4484-E, August 29, 2014, Table 3. ---PAGE BREAK--- October 29, 2014 24 MRW & Associates, LLC plants for its power, we do not expect MCE’s rates to be affected by the drought to the same extent as PG&E because MCE has most of its resources under fixed-price contracts through 2017.52 In subsequent years, the availability of rate savings will likely be driven by water availability, the price of natural gas, and the prices of renewable contracts entered into by MCE compared to those entered into by PG&E. MCE’s rates are likely to generally remain competitive with PG&E’s, but there are risks of higher costs under MCE in some circumstances. For example, while the Diablo Canyon plant is operational and exit fees are still high, an unexpected spike in natural gas prices could increase MCE’s rates above PG&E’s rates. There is little risk of this through 2017 because MCE has contracts in place to supply about 95% of its gas-fired power requirements at fixed prices through this time.53 The longer-term risk depends on MCE’s procurement choices after termination of its contract with SENA. According to MCE’s Integrated Resource Plan, MCE will typically enter into contracts for conventional power and for natural gas that are either short term or medium term, meaning terms of less than five years.54 Medium-term fixed-price contracts would provide security against short-term spikes in natural gas prices; however, MCE’s Integrated Resource Plan does not specify the extent to which it will pursue such contracts and does not mention plans for financial hedging or other mechanisms to cushion rates from potential medium-term or long-term natural gas price increases. Since MCE’s current contract with SENA is a fixed-price contract, it is reasonable to anticipate that MCE is sensitive to gas price variability and will develop plans to cushion rates from this variability; however, this cannot be determined with certainty because MCE’s procurement plans for the period following expiration of the SENA contract in 2017 are still under development. In addition, it would not be reasonable to expect MCE to fully hedge against a long-term sharp increase in natural gas prices. This situation, which is not currently anticipated in the coming decades given shale gas supply estimates, would put more upward pressure on MCE rates than on PG&E rates. MCE appears to have a long-term strategy to reduce this risk by increasing its procurement of renewable resources and reducing its dependence on natural gas-fired power. However, unless MCE significantly ramps up its procurement of renewable resources and/or Diablo Canyon is retired early, MCE is likely to remain more heavily dependent than PG&E on natural gas for the next few decades. This does place additional price risk on MCE, which, in the event of an extended period of high natural gas prices, could mean that MCE’s rates will be higher than PG&E’s. This risk is counterbalanced to some extent by the risk to PG&E from low water years and from nuclear plant outages, and, should MCE choose to do so, it could be partially managed through contractual choices. Moreover, the risk of higher costs under MCE declines over time as exit fees fall off. In the long run, with exit fees reduced to zero and Diablo Canyon retired, it is reasonable to expect that electricity bills through MCE will generally be lower than under PG&E. 52 Renewable energy certificates are excluded from this assessment as they typically cost just a small percent of the cost of physical power and therefore pose much less price risk than physical power requirements. 53 Marin Clean Energy. Integrated Resource Plan Annual Update, November 2013, page 16. 54 Ibid, page 20. ---PAGE BREAK--- October 29, 2014 25 MRW & Associates, LLC 4.1.2 Rate Comparison Conclusions The MCE rate comparison provides a reasonable estimate of rate savings under August 2014 rates, but it does not provide a good indication of how rates under MCE will compare with rates under PG&E going forward. MCE rates, PG&E rates, and exit fees will increase and decrease in the coming years at different rates, driven by different factors, so it cannot be determined whether MCE will continue to provide a rate benefit to Benicia customers in all years. However, given the current estimate of a 6.5% benefit under MCE, and considering the various pressures influencing PG&E and MCE rates as well as the long-term exit fee trends, it is reasonable to anticipate that MCE rates will generally remain competitive with PG&E’s in the long-term, though not necessarily in each and every year and not necessarily at the same rate identified in the MCE rate comparison. The MCE rate comparison was developed assuming full participation by all Benicia customers in the CCA. MRW additionally tested the results under scenarios with high levels of opt-outs. MRW found that applying a 50% opt-out rate to non-residential accounts reduces the Benicia- wide savings rate from 6.5% to 5.6% and that applying a 50% out-out rate to residential customers increases the Benicia-wide savings to 7.1%. MRW also found that should the city’s largest customer choose to opt out of the CCA, substantial savings are still anticipated for remaining customers. Given these results, MRW concludes that while opt-outs could either increase or decrease the average savings for remaining customers, depending on which customers opt out, average savings are likely to remain robust for remaining CCA customers even if significant numbers of opt-outs occur. 4.2 MCE Applicant Analysis The MCE Applicant Analysis found that MCE’s rates would likely fall by 3% with the addition of Benicia customers to the CCA. If this rate decrease does occur, the rate savings for Benicia customers will increase by more than estimated in the rate comparison, all else being equal. MRW evaluated the Applicant Analysis to determine whether these rate savings should be anticipated. The MCE Applicant Analysis is based on an estimate of the revenues from Benicia customers compared to the costs to serve these customers during the fiscal year that begins April 2015. The key assumptions are as follows: 1. Benicia load served by MCE: The analysis assumes a 20% opt-out rate, which is a reasonably conservative assumption. The analysis appropriately takes into account that first year loads will be lower because of the gradual transfer of accounts to MCE service over the course of April 2015 and assumes that 76% of the total electricity usage in Benicia will be served by MCE in this year. 2. Revenue from Benicia customers: The MCE rate comparison analysis was based on MCE’s serving 100% of Benicia’s electricity usage. The MCE Applicant Analysis finds that the revenue from serving 76% of Benicia’s electricity usage will be 74% of the revenue identified in the rate comparison analysis. This appears reasonably conservative. 3. Costs to serve Benicia customers: The MCE report identifies two cost components: power supply costs of $12.5 million and (ii) billing and other costs of $330,000. The ---PAGE BREAK--- October 29, 2014 26 MRW & Associates, LLC power supply cost estimate is equivalent to $60.50 per Megawatt-hour, which is a reasonable estimate given current market prices. The billing and other costs are equivalent to $26 per customer to cover customer billing, customer service support, and PG&E service fees. MEA’s financial statement for 2014 shows the equivalent of less than $14 per customer for Staff Compensation,55 which likely covers customer service support and other functions. The financial statement additionally shows nearly $50 per customer for General and Administration and for Contract Services. These costs cover some cost categories that are likely to increase with each new customer, such as PG&E billing fees of $0.44 - $1.05 per account,56 but more substantial costs that are not likely to grow on a one-to-one basis with the added customer base, such as costs for power solicitations and contract negotiations, for representation at the California Public Utilities Commission and in Sacramento, and for account auditing, legal counsel, office space, and communication and information technology equipment. Using reasonably conservative estimates of 20% of these costs and 100% of the staff compensation costs increasing on a one-to-one basis for each new customer yields an incremental cost of $24 per new customer. MCE’s estimate of $26 per customer therefore appears to be reasonable. MCE’s analysis excludes one-time costs associated with the Benicia expansion, which are estimated at less than $350,000.57 Had these costs been included, the analysis results would not have materially changed. Based on these assumptions, MCE calculated revenue of $16.6 million from Benicia customers and a cost of $12.8 million to serve these customers, providing a net surplus to MCE of $3.8 million. MCE concludes that this surplus will allow MCE rates to be 3% lower than they would be without Benicia customers. This conclusion is reasonable given MCE’s current revenue base. It should be noted, however, that, to MRW’s knowledge, while for the purpose of the analysis MCE assumes that this revenue surplus would be used to reduce MCE’s overall rates, MCE is not obligated to use this revenue surplus to reduce rates and has not committed to doing so.58 MCE could instead use the funds to expand services, increase MCE staff salaries, or for other uses. As a result, while MRW finds this analysis to be reasonable, MRW does not feel it is appropriate to rely on these savings in estimating bill impacts from joining MCE. 4.3 Organizational Soundness (Long‐Term Viability) In considering the organizational soundness and long term viability, MRW examined how the JPA was structured (do members have an appropriate voice in governance?), MCE’s operational management, MCE’s finances to date (including debt), and MCE’s projected revenues and costs. 55 Marin Clean Energy. Financial Statements: Years Ended March 31, 2014 and 2013 with Report of Independent Auditors, page 7. 56 PG&E Electric Schedule E-CCA, October 2014, Sheet 6. 57 These are predominately MCE costs. The PG&E-related fees are $8,000 for a single mass enrollment with a 20% opt-out rate, plus $4,000 for each additional enrollment. PG&E Electric Schedule E-CCA, October 2014, Sheet 2. 58 MCE’s Applicant Analysis appears to take care to avoid making such a commitment. For example, the report states, “The surplus is assumed to offset a share of MCE’s fixed costs and can be used to reduce overall MCE rates” It does not state that the surplus will (or would) be used to reduce overall MCE rates. ---PAGE BREAK--- October 29, 2014 27 MRW & Associates, LLC 4.3.1 The Marin Clean Energy Joint Powers Agreement The MCE JPA stipulates that MCE be governed by a Board of Directors. Each member town, city or county to the JPA appoints one director to the Board. Thus, Board Members of the original MCE members have no more inherent power than those of members added later, such as Benicia. The Operating Rules and Regulations specify the reasons for which an individual Director can be removed, but only for cause. The member that appoints a director has the right to remove him/her at any time, and has the responsibility to fill any vacancy within 90 days. Thus if Benicia joins MCE, it will need to determine how it will select a MCE director and make that selection in a timely manner. The appointing city is also responsible for compensating a director for their work. A majority of the directors appointed to the MCE Board are required to be present for a vote to take place. The Board has the authority to conduct all of the business and activities of MCE in accordance with the rules of the organization. The Board also elects a chair and vice-chair from amongst themselves. When voting on matters relating to the CCA Agreement, each member’s voting share is determined as follows:  Each director has a pro rata voting share equivalent to [1/total number of directors] x 50%  A director has an Annual Energy Use voting share equal to [the appointing party’s Annual Energy Use/Total Annual Energy Use] x 50% o For the first 5 years following the Effective Date of the formation of MCE, a party’s Annual Energy Use is the total kilowatt-hours (kWh) used within the respective party’s jurisdiction. o After the 5th anniversary of the Effective Date, a party’s Annual Energy use is the total kWh used by accounts within a Party’s respective jurisdiction that are served by MCE. o The Total Annual Energy Use is the sum of all party’s Annual Energy Use Adding Benicia’s 2013 Annual Energy Use of 272,731,094 kWh to MCE’s existing 2,368,744,329 kWh Total Annual Energy Use would result in approximately a 5.2% Annual Energy Use voting share and approximately a 3.1% pro rata voting share, for a total voting share of roughly 8.3%. To reach an affirmative decision, all directors voting in the affirmative have a total voting share exceeding 50% of the total voting share, unless a higher threshold is specified. If a vote requires a higher threshold, than at least two directors must vote in the negative to disapprove the matter. When voting on general administrative matters and programs not involving the CCA, each director has one vote, unless otherwise specified. When voting on programs not involving the CCA that require financial contributions, the program shall be approved only by a majority vote of the full membership of the Board. Parties who vote against the program have the right to opt- out of the program. The Board will provide written notice to all members 45 days prior to considering the program that require financial contributions in a board meeting. ---PAGE BREAK--- October 29, 2014 28 MRW & Associates, LLC 4.3.2 Marin Clean Energy Management Structure The MCE Board’s primary duties are to establish program policies, set rates, and provide policy direction to the Executive Officer. The MCE Executive Officer has the general responsibility for program operations. The current Executive Officer is Dawn Weisz. Ms. Weisz has been the Executive Officer since MCE was formed and in fact was involved in the establishment of MEA, going back to as early as 2004. Answering to the Executive Officer are Directors of six departments: Public Affairs, Electric Supply, Energy Efficiency, Legal and Regularly, and Internal Operations. Through its prior reviews of MEA and MCE and through its experience in California electricity regulation and market analysis, MRW has found that the key personnel at MCE to be more than competent. First, Ms. Weisz, as Executive Officer, not only successfully ushered MCE into existence but also led the organization as it expanded beyond its initial membership. MRW has also found Ms. Elizabeth Kelly, the Legal Director, to be a knowledgeable and proactive advocate for MCE at the CPUC. Mr. John Dalessi, a consultant to MCE, successfully negotiated the initial contracts with SENA and continues to administer MCE’s competitive solicitations for power supply and renewable energy. The fact that since 2012 MCE has had lower costs than PG&E is at least partially attributable to Mr. Dalessi. 4.3.3 Current Financial Position of Marin Clean Energy MRW reviewed the last 3 years of MCE’s audited financial statements along with MCE’s 21014 Revised CCA Implementation Plan59 and Addendum No. 1 to that plan.60 Per the audited financial statements, MCE’s net position (total assets minus total liabilities) has improved each of the past three years. The change in net position is summarized in the table below: Table 3. MCE Net Position Fiscal Year Net Position 2011 318,838 2012 3,917,925 2013 7,912,874 2014 9,558,036 Furthermore, MCE has expanded service each year, which has resulted in an increase in cash and receivables, as well as trade liabilities. In July 2013, MCE expanded into the City of Richmond, and grew its customer base from 90,000 to 125,000. This resulted in higher accounts receivables, but has also led to more spending on energy procurement. Net accounts receivables and accrued revenues increased from 2013 to 2014, as did accounts payables, accrued cost of electricity and user taxes/energy surcharges from other governments. 59 To account for the addition of Napa County, dated July 18, 2014. 60 To account for the addition of the City of San Pablo, dated September 16, 2014. ---PAGE BREAK--- October 29, 2014 29 MRW & Associates, LLC MCE incurred no new debt in Fiscal Year 201461 and continued paying down its existing debt. The total notes payable to banks decreased from $3,083,746 to $2,024,308. One issue identified in the financial statements is that the operating margins have been decreasing as the company expands. The past three years of operating revenues, expenses, income and margins are summarized in the table below. Table 4. MCE Operating Income (Fiscal Year) 2014 2013 2012 Operating Revenues 85,561,759 52,579,310 22,918,843 Operating Expenses 83,731,036 48,429,076 19,210,349 Operating Income 1,830,723 4,150,234 3,708,494 Operating Margin 2.14% 7.89% 16.18% It should be noted that actual revenues in the table above are for the 12 months ending on March 31st of the year indicated, and projections as provided in the Updated MCE Implementation Plan are for calendar years. Therefore, while MCE only increased its Net Position by $1.83 million between April 1, 2013 and March 31, 2014, MCE’s latest projection indicates that they expect to increase its net position by $5.27 million during the 2014 calendar year.62 There are two reasons why MCE’s operating margin dropped in FY 2014 and why it is reasonable to expect MCE’s financial performance to improve over the rest of the 2014 calendar year. Both are related to the City of Richmond joining MCE in August 2013. First, there is a one to two month lag between when MCE receives payments from customers after when it has pays its procurement amounts. The expansion of service to Richmond required MCE to use additional working capital to account for this lag. Second, adding Richmond to MCE increased commercial sales by 50%.Commercial sales are subject to seasonal rates, with higher rates from May through October and lower rates from November through April. However, procurement costs are not seasonal. Therefore, MCE must procure electricity to supply Richmond at “full cost” for 5 winter months (November through March) while charging commercial customers lower winter rates. Had Richmond been a customer for an entire 12 months, this factor would have balanced out. 4.3.4 Projections The MCE financial projections in its Updated Implementation Plan Addendum reflect costs and loads through 2019 or 2021 (depending upon the table) and include only the additional load associated with Napa Country and the City of San Pablo. The loads associated with these two new members are not on the same scale as the City of Richmond. The MCE’s total energy requirements grew by 93% between the 2012 and 2013 calendar years, from 603 GWh to 1,166 GWh, most of which is attributable to Richmond joining MCE. From 2013 to 2021 MCE projects the total energy requirements to grow by 47% total, increasing 61 April 2013 through March 2014. 62 September 14, 2014 Implementation Plan Addendum, p. 10. ---PAGE BREAK--- October 29, 2014 30 MRW & Associates, LLC to 1,714 GWh (See Table 5, below).63 This increase occurs in the first two years when service begins for Napa and San Pablo. In 2016 and beyond, no increase in retail sales is projected, and in fact due to distributed generation and energy efficiency, MCE projects net decreases in total load requirement. This is not unreasonable, as retail demand has been relatively flat in California over the past decade, and MCE intends to aggressively pursue both solar distributed generation and energy efficiency. Table 5 Table 6, below, shows MCE’s historic (2013) and projected (2014-2021) annual revenues and costs.64 Consistent with its load projections, revenues and costs both grow markedly from expansion from 2013 through 2016. After 2016, MCE is projecting no changes to revenues (indicating no change in rates or perhaps a very slight increase to account for lower net loads resulting from energy efficiency and solar installations). Administrative and General costs, which constitute less than 10% of MCE’s overall cost of operations, are projected to increase with expansion (although not at the same rate as the cost of energy), and then grow at 1.7% (approximately inflation). In 2017 MCE projects a 0.4% decrease in the cost of energy and a more significant decrease, 5.75% 7 million), in 2018. The only explanation for the significant drop in 2018 is the end of the SENA procurement contract. Thus, MCE is implicitly assuming that it will be able to replace the SENA power at prices that are on average approximately 5% less than that provided by SENA. While this drop is not explained in its current Integrated Resource Plan (See Section 3.1), MRW understands that an updated Integrated Resource Plan will soon be available November 2014) which may explain the drop. Even if MCE can replace the SENA power at the same price (and not a discount) and the cost of energy to MCE remains flat at the 2017 level, net surpluses would still persist. 63 Per September 14, 2014 Implementation Plan Addendum, p. 7. 64 September 14, 2014 Implementation Plan Addendum, p. 10. ---PAGE BREAK--- October 29, 2014 31 MRW & Associates, LLC Table 6 MRW is also skeptical that the cost of energy to MCE would experience no net increase from 2016 to 2021 (albeit with some year-to-year decreases and increases). Nonetheless, in considering these projections, one must keep in mind the following: 1. MCE has rate setting authority. Thus, if in a particular year the cost of energy increases, the Board may either change rates so as to collect those costs or fall back onto its reserves. 2. MCE’s rates must be comparable to PG&E’s in the long term. If the cost of energy to MCE increases markedly due to say an increase in gas prices, then PG&E would also experience a similar increase in its cost of energy. This would allow MCE to increase its rates without necessarily harming its price position relative to PG&E. 3. Similarly, as seen in its early years (2010 and 2011), MCE need not beat PG&E’s prices at all times. A short period where MCE’s prices are marginally above PG&E a few percent) would not likely result in a detrimental loss of load from customers migrating back to PG&E service. The incremental load from Benicia joining MCE would increase both the revenues and cost of energy proportionally. Assuming that MCE could serve the Benicia load at the same average cost as it serves its already established load (a condition for Benicia’s membership in MCE), then the positive operating surplus should be maintained. 4.3.5 MCE Debt MCE’s debt comes from 3 major sources. Prior to the 2010-11 fiscal year, MCE received $540,000 in interest free loans from Marin County and $750,000 from three individuals at a ---PAGE BREAK--- October 29, 2014 32 MRW & Associates, LLC 5.75% interest rate. This was to be paid back by August 1, 2011, which it was. In April 2010 MCE received a $1.45 million from the River City Bank, with interest computed at the greater of 2% plus the Base Commercial Loan Rate (3.25% at date of agreement) or 5% per year. In January 2011 MCE took out a new $2.3 million loan from River City Bank, at a 5.25% interest rate. This loan also retired the previous loan from the bank. In July 2012 MCE received another $3 million loan from River City Bank, repayable by October 2017 at a 4.5% interest rate. MCE currently owes $3.093 million of principal, and $3.326 million total. 4.3.6 Conclusions Concerning Long‐Term Viability MRW finds the governance structure of the MCE JPA to be reasonable. All member entities are represented on the Board, with key voting provisions reflecting both the number of members and the size of each member. The current management is experienced and competent. The finances of MCE are, to date, sound. Quickly after startup, MCE was able to acquire a line of credit so as to consolidate its private startup debt. It has consistently increased its net position and operating reserves. While its cost of power beyond 2017 may be optimistic, given the positive operating margins shown in its projections as well as the Board’s ratemaking authority, MRW sees no red flags in its financial projections. ---PAGE BREAK--- October 29, 2014 33 MRW & Associates, LLC 5. Conclusions MRW has identified various benefits and risks associated with the City’s participation in MCE. The most significant benefit is local control over ratemaking, power procurement and energy efficiency/solar policies. The most significant risk is whether MCE will ultimately be able to provide long-term power supplies at costs that are less than PG&E generation rates. Thus, even though MRW believes that MCE will be able to offer competitive rates, if the City’s customers are highly price sensitive, then this risk may be of concern On the other hand, if the City’s residents and businesses are more concerned about local control and the level of renewable resources used to generate their electric supply, then such an assessment is less important. MRW found the MCE Member Analysis to be accurate but limited as it was based on a snapshot of current MCE and PG&E rates and did not attempt to project either into the future. With respect to solar issues, Sage Renewables found:  The City can expect between $40,000 to $80,000 in annual excess net energy metered (NEM) bill credit payments from MCE for the solar NEM accounts;  While MCE’s policy of paying for excess NEM bill credits will remain in place for at least the short term, it is at higher risk of change over time than other MCE rate policies; and  The greatest short term risk to the value of solar PV generated energy is PG&E’s proposal to limit its solar-friendly A-6 rate to only small commercial customers. This risk exists whether the City remains a PG&E customer or elects to transition solar PV accounts to MCE. (MCE is expected to mirror changes to PG&E’s A-6 tariff with changes to its COM-6 tariff). It is beyond the scope of this assessment to quantitatively assign either potential costs or probability of occurrence to the risks identified here. In addition, this assessment does not identify or attempt to quantify all potential benefits associated with participation in MCE. Benicia’s policymakers will need to weigh and balance the potential risks and benefits of participation in MCE given the risk and policy preferences of Benicia’s citizens and businesses. ---PAGE BREAK--- October 29, 2014 34 MRW & Associates, LLC Appendix 1: MRW and Sage Qualifications MRW & Associates Established in Oakland, California in 1986, MRW early on built a solid reputation for delivering local insights on power and fuel markets in the western United States as well as intervening successfully in legislative and regulatory proceedings on clients’ behalf. Today, MRW continues to deliver high-quality market insights, analysis, and client support on a national and international level. The company has undertaken engagements in more than twenty different states, including nearly every state in the western U.S. The company maintains a strong focus on California markets and regulatory structures. The location of the company office in Oakland, California, facilitates our active participation in proceedings at the CPUC, the California Energy Commission, and the CAISO. MRW’s client base includes major financial institutions, private power developers, consumer advocates, power marketers, municipalities, Fortune 500 industrial companies, commercial end- users, natural gas pipelines and storage service providers, regulatory agencies, and other strategic players in the energy sector. MRW’s team of professionals include specialists in renewable energy, power market modeling, financial analysis, regulatory processes, utility rate design, legislative analysis, commodity procurement, energy use analysis, contract negotiations, transmission planning and pricing, and strategic planning. On related CCA matters, in the spring of 2005, Navigant Consulting, pursuant to a California Energy Commission grant, issued a series of CCA feasibility studies for the County of Marin and the cities of Berkeley, Oakland and Emeryville. A similar report was issued for the Kings River Conservation District a few months later. The basic reports were nearly identical, differing only in how the customer and load characteristics of each jurisdiction affected the various data tables. MRW, along with JBS Energy, provided an independent third-party review of these studies on behalf of the studies’ recipients. The reviews focused on the reasonableness of the analytical approach and assumptions used by the reports’ authors, identifying areas that were either unreasonable or would need updating if a particular jurisdiction were to investigate CCA formation in greater detail. The review also identified key risks that would have to be addressed, including such factors as regulatory risk impact of changes to PG&E rate design) and environmental compliance costs. As a result of these third-party assessments, Navigant ultimately made significant changes to the preliminary feasibility studies. In late 2008, MRW conducted an independent review of the reports and documents associated with Marin County’s Community Choice Aggregation efforts. This review focused on the “Marin CCA Business Plan” (April 2008), PG&E’s comments on the Plan, and responses to Marcus’ and PG&E’s comments. MRW’s review concentrated on two main areas: the factors that were most important making a CCA financially viable and the major risk factors that would affect potential participants in the CCA. These included:  the reasonableness of the power procurement strategy proposed in the Plan;  the reasonableness of the procured power costs forecast in the Plan;  hedging and risk management activities proposed in the Plan;  underlying natural gas and wholesale power price projections; ---PAGE BREAK--- October 29, 2014 35 MRW & Associates, LLC  the consistency of rate and procurement costs with those underlying gas price projections;  the reasonableness of the Plan’s estimates of the non-bypassable charges including the CCA Cost Responsibility Surcharge (CRS);  the depth and appropriateness of any sensitivity analysis; and  the forecasts of utility rates (and rate designs) against which the CCA’s rates would compete, including the consistency of assumptions underlying the utility rate projection and the CCA rate projection. In late 2009, the County and City/Town Managers again retained MRW to review the draft service agreements that MEA was proposing to enter into with Shell Energy North America. This review concentrated on identifying the risks to MEA, the Cities, Towns, and the County that were not sufficiently addressed in the MEA-Shell agreement, and provided suggested changes and amendments to the agreements to mitigate those risks. Many of MRW’s suggestions were subsequently incorporated in the final contract. The primary authors of this assessment are Mark Fulmer, William Monsen, and Laura Norin. In late 2010, the office of Richmond’s City Manager retained MRW to conduct an independent third-party analysis of the risks associated for Richmond to join the MEA. The Scope of MRW’s analysis included:  Determining potential risks to City residents and businesses if Richmond joins the MEA, in particular, the rate risk to the community  Determining potential risks to the City itself if it chooses to join the MEA  Commenting upon the Dalessi Management Consulting load and resource requirement analysis  Provide qualitative comments on any materials MEA provides to Richmond MRW presented its at a Richmond City Council meeting and where Mr. Fulmer and Mr. Monsen responded to questions from City staff and Council members. Mark Fulmer is a Principal at MRW & Associates, LLC, with over twenty years of experience in the energy industry. Much of this work has been in the regulatory arena, advising customers, trade groups, municipalities, utilities and state public utility commissions on resource planning, energy efficiency and rate matters. He has submitted testimony before FERC and utility commissions in Arizona, California, Hawaii, New Mexico, Rhode Island and Washington, as well as supporting testimony in ten other states and Canadian provinces. With respect to CCA matters, Mr. Fulmer was the lead author of a CCA feasibility assessment in Southern California Edison’s service area and contributed to the peer reviews of the CCA feasibility studies for Marin, Berkeley, Oakland, Emeryville and the Kings River Conservation District. He also served as an expert witness before the California PUC on behalf of the City and County of San Francisco on CCA matters, including the rules under which CCA would operate and the fees that PG&E would be allowed to charge CCAs for the various services the utility would have to provide. In 2009, Mr. Fulmer was one of three witnesses sponsored jointly by the Marin Energy Authority, the City and County of San Francisco, and the Direct Access parties in the CPUC proceeding addressing the correct calculation of the Cost Responsibility Surcharge for departing load (CCA and DA) customers. Mr. Fulmer holds a Master’s Degree in Engineering from Princeton University, where he ---PAGE BREAK--- October 29, 2014 36 MRW & Associates, LLC conducted graduate research at the Center for Energy and Environmental Studies, and a Bachelors’ Degree in Engineering from the University of California, Irvine. William A. Monsen, a Principal with MRW & Associates, LLC, has been providing technical and economic analysis for the energy industry for more than 30 years. He is an expert in utility resource planning, retail power procurement, power market evaluations, due diligence for power generation projects, and independent power issues. He has helped municipalities and other end- users understand present and future consumption needs and reduce energy costs through competitive commodity procurement and efficiency improvements. With respect to CCA matters, Mr. Monsen was the Principal in Charge for detailed peer reviews of the CCA feasibility studies forRichmond, Marin, Berkeley, Oakland, Emeryville and the Kings River Conservation District. He also led MRW’s work in reviewing Marin Energy Authority’s business plan and draft service agreements that MEA was proposing to enter into with Shell Energy North America. He also provided professional review on behalf of the City and County of San Francisco of the proposed contracts between the city and a potential (but eventually rejected) supplier for their proposed CCA and was a co-author of the Southern California CCA feasibility study MRW conducted in 2008. Mr. Monsen holds a Master’s degree in Mechanical Engineering from the Solar Energy Laboratory at the University of Wisconsin-Madison and a Bachelor’s degree in Engineering Physics from the University of California at Berkeley. Sage Renewables Sage Renewables is an independent renewable energy consulting and project development firm that provides expert, customized professional consulting services across the public and private sectors. Sage recently completed a comprehensive evaluation of City of Benicia’s solar PV systems under contract to the California Energy Commission (CEC) through the Energy Partnership Program. The evaluation included site analysis to verify that all PV systems were built to contract, were performing as designed and that workmanship is appropriate. Sage also worked with the City to evaluate and model existing and expected financial performance of the PV systems, and to identify an appropriate Operations and Maintenance (O&M) contractor to provide necessary ongoing system support. Sage also performed PG&E tariff modeling to confirm that the Pool and Pump Station 2 accounts were configured with the correct PG&E tariff. Through this work, Sage gained an intimate knowledge of the City’s solar PV systems and formed a strong working relationship with City staff. Sage has developed custom modeling tools to evaluate financing, renewable resources, and project sizing and design, and we own industry standard equipment and software for assessing resources in the field. Sage’s key personnel are our three founding Principals. Each Principal has extensive experience working with public agencies from small rural special districts, to large, multi-campus CA K-12 public school districts, to city and county governments. We work as a team to provide expert energy efficiency services, site evaluations, production, financial and environmental analyses, and renewable energy project development and asset management services. ---PAGE BREAK--- October 29, 2014 37 MRW & Associates, LLC Tom Williard is Principal and CEO of Sage Renewable Energy Consulting and has worked in the renewable energy industry since 2001. Prior to founding Sage, Tom was a Principal at energy consulting firms Sustainergy Systems and System Design. In 2005, Tom co-founded Solmetric, Inc., where he was Director of Research and Development for the initial SunEye product. Tom has expertise in modeling tool development, renewable energy finance, hardware and software engineering and growing engineering organizations and early stage companies. Previously, Tom spent twenty years in the electronics industry as a management consultant, senior technologist, and senior hardware and software engineer for a number of imaging and communications companies, most recently as Director of Software Engineering at Ascend Communications, establishing and managing engineering centers around the world. Tom takes an active role in his community, having served on several boards and foundations in Marin County, CA, and as an elected Trustee of a CA public school district for seven years. Brent Johnson, PE, LEED AP, is Principal and co-founder of Sage Renewable Energy Consulting. Brent has 15 years of experience as a Civil-Environmental Engineer, with five years in the renewable energy sector. During his time at Sage, he has developed custom financial and energy modeling tools and managed all aspects of renewable generation projects including feasibility studies, system design, project bids and construction, commissioning, and environmental credits management. Brent has worked on over 100MW of renewable projects encompassing a number of technologies such as solar PV, solar thermal, wind, fuel cells, and hydropower. His previous experience, both in the US and overseas, has included design of large municipal facilities, computer modeling, construction management, operational support, and CEQA permitting. Through this experience, he has overseen all aspects of project development, from concept to commissioned facilities, including serving as a construction manager on a complex, $170M multi-year linear project. Brent holds an M.S. in Civil-Environmental Engineering from UC Berkeley, is a registered Professional Engineer (PE) in California and has his LEED certification from the US Green Building Council. He currently services as a director for his local water and fire district. David Williard, LEED, Principal and co-founder of Sage Renewable Energy Consulting, David has nine years of experience in the energy and green building industries. David's work has included commercial and residential energy auditing, energy code compliance, green materials specification, renewable energy system design and implementation, greenhouse gas emissions inventory and monitoring, greenhouse gas emissions reduction plans, environmental site assessment, renewable resource assessment, and renewable energy project management. Additionally, David has participated in extensive field projects with an emphasis on environmental assessment and GIS mapping utilizing GPS systems. He has experience coordinating with city and county government agencies and other organizations through his work. In February 2005, David founded Sustainergy Systems Consulting & Design, which became Sage Renewables in August 2009. David holds a B.S. in Civil Energy Management and Design from Sonoma State University and has his LEED certification from the US Green Building Council. ---PAGE BREAK--- October 29, 2014 38 MRW & Associates, LLC Appendix 2: Sage Renewables Assessment of the Risks to the City’s Net Energy Metered Solar Accounts ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 1 of 7 October 28, 14 Task 3 Executive Summary Project Overview Sage Renewables, as subcontractor to MRW & Associates, evaluated the impact of changing electrical energy service providers from PG&E to MCE for the ten City electricity accounts that have solar PV systems currently installed. City of Benicia’s contract with MRW, Task 3, listed the follow evaluations to be performed: • Anticipated changes in annual electrical energy costs and credits; • MCE’s evaluation indicating that approximately $60,000/year may be paid to the City under MCE’s Net Energy Metering (NEM) program; • Ability of MCE to maintain its net metering credit payout program; • Impacts to net‐metering solar rates particularly as they relate to AB327. To perform this evaluation Sage reviewed City of Benicia’s PG&E historical electricity usage source data for PV system sites and MCE’s Rate Comparison spreadsheet for accuracy and completeness. Sage performed tariff analysis modeling on four separate PV system electrical accounts to confirm MCE modeling and determine the impact of switching to MCE on overall electricity cost including the purchase of residual energy. This modeling was based on tariff information from MCE1 and PG&E2, in addition to historical electricity usage information for the sites. Sage also evaluated AB‐327, the CPUC Proposed Decision R.12‐11‐005 concerning NEM grandfathering, and PG&E’s 2014 General Rate Case II that is currently being litigated at the CPUC. Sage spoke with representatives of MCE, City of Benicia, PG&E and Crossborder Energy (lead consultants for SEIA in the PG&E 2014 General Rate Case Phase II litigation) in the course of researching these issues. High Level Findings 1. City of Benicia can expect between $40,000 to $80,000 in annual excess NEM bill credit payments from MCE for the solar PV NEM accounts given current usage patterns and tariff rates. PG&E does not pay for annual excess bill credits. 2. MCE’s policy of paying for excess NEM bill credits will remain in place for at least the short term, but is at higher risk of change over time than other MCE rate policies. 3. The greatest short term risk to the value of solar PV generated energy is PG&E’s proposal to cap the A‐6 tariff to 75kW peak demand proposed in their 2014 General Rate Case (GRC) Phase II. This risk exists whether the City remains a PG&E customer or elects to transition solar PV accounts to MCE. MCE is expected to mirror changes to PG&E 2014 General Rate Case (GRC) Phase II6 tariff. 4. City of Benicia should be able to change energy providers from PG&E to MCE and vice versa without jeopardizing the 20‐year NEM 1.0 transition (grandfathering) period of existing systems. Findings are discussed in detail in the next section. 1 MCE tariff information: http://www.mcecleanenergy.org/wp-content/uploads/MCE%20Commercial%20Rates.pdf 2 PG&E tariff information: http://www.pge.com/tariffs/tm2/pdf/ELEC_SCHEDS_A-6.pdf ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 2 of 7 October 28, 14 Task 3 Findings 1. Anticipated changes in annual electrical energy costs and credits to solar PV accounts with MCE: MCE’s tariffs closely mirror PG&E tariffs in structure and pricing. This is done to allow for ease of billing, to comply with CPUC requirements and to allow easy comparison of MCE vs. PG&E electricity rates. MCE endeavors to provide energy with higher renewable content below the cost of similar tariffs from PG&E. Because the tariffs are very close, anticipated annual electrical energy costs between MCE and PG&E will be similar. MCE diverges significantly from PG&E in offering to monetize excess NEM bill credits at the end of each 12‐month true up period, and by providing a $0.01/kWh premium for excess solar PV energy exported to the grid3. PG&E does not monetize excess NEM bill credits or pay a premium for exported energy; any excess bill credits are lost at the end of the true up period. Excess bill credits from City of Benicia’s solar PV NEM accounts are the primary source of energy cost savings from MCE vs. PG&E. PG&E’s higher A‐6 generation rates can provide greater value for solar PV produced energy if the PV systems are nearly offsetting the annual electrical bill with no annual excess bill credits. The analysis performed on 2013‐2014 usage data showed that three of the ten City PV accounts did not have excess bill credits at the end of the year. Two of those accounts would save money vs. MCE, but one of the accounts, the Pool, would cost more vs.MCE due to the lower annual offset. The relatively higher cost of PG&E energy at the Pool offset savings at the other two sites. 2. MCE’s evaluation indicating that approximately $60,000/year may be paid to the City under MCE’s Net Energy Metering (NEM) program: MCE’s modeling is correct for the PG&E data that was available to MCE. Sage recovered missing PG&E data for the analysis period and confirmed MCE’s modeling using proprietary tariff modeling tools. Sage also ran the models with two years (~2013 and 2014) of PG&E data for Pump Station 3 to find the impact of significantly less usage at that site in 2014. Note that changes in usage for Pump Station 3 were largely associated with ongoing drought conditions. We anticipate that Pump Station 3 usage would be similar to 2013 in years with normal or above precipitation. Calculated NEM excess bill credit payments are as follows: • MCE annual NEM bill credit payment (2013 usage data): $59,743 • Sage annual NEM bill credit payment (2013 usage data): $58,574 • Sage annual NEM bill credit payment (2014 usage, Pump Station $81,665 See Appendix A, B and C for detailed modeling results. 3. Ability of MCE to maintain its net metering credit payout program: The main risk to MCE’s policy of NEM excess bill credit monetization is potential cost to other MCE ratepayers. MCE has a stated goal of providing energy costs at less than PG&E’s rates with greater renewable content. If MCE is no longer able to meet that goal due to changes in 3 See Premium Benefits section: http://www.mcecleanenergy.org/business-solar/ ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 3 of 7 October 28, 14 legislation, energy procurement and/or management costs, the NEM excess bill credit monetization policy could be at risk. A related risk is that as MCE’s NEM customer base grows, monetization of excess bill credits may at some time become a significant cost, causing changes to the policy. Given that the $0.01 per kWh of excess generation policy is not found in MCE’s NEM tariff and that their NEM bill credit cash out is a significant departure from PG&E policy, there is a higher risk of change compared to other MCE pricing policies. According to MCE staff, there are no plans to modify MCE’s monetization of excess bill credits policy. Given that MCE is reasonably solid financially, and that their current policy explicitly limits the size of PV systems that can be installed relative to past load, there is little short term risk of this policy changing. 4. Recent and anticipated legislation affecting NEM and solar tariffs: a. AB‐327 (2013/Perea) AB‐3274, signed into law in October, 2013, directed the CPUC to create a new NEM tariff/policy (NEM 2.0) that replaces the current NEM 1.0 tariff/policy and removes the limitation on NEM aggregate size of NEM accounts. NEM 2.0 policy is to be finalized by the CPUC by December 31, 2015 and implemented on January 1, 2017 at the latest. The CPUC has not issued any proposed rulings or guidance concerning NEM 2.0, but they have issued a Preliminary Ruling that addresses grandfathering of existing NEM 1.0 customers, discussed in Finding 4.b. b. CPUC Proposed Decision R.12‐11‐005 CPUC Proposed Decision R.12‐11‐0055 states that existing NEM 1.0 customers will be allowed to maintain NEM 1.0 tariff policy for 20 years following interconnection and permission to operate (PTO) the energy generating system. This grandfathering policy is referred to as the NEM transition period. How this policy would be affected by transition from PG&E to MCE is discussed below in Finding 5. c. PG&E 2014 General Rate Case Phase II In PG&E’s 2014 GRC Phase II6, PG&E proposed capping the solar‐friendly A‐6 tariff to maximum customer demand of 75kW. This change would lower the current A‐6 demand cap from 499kW and would result in many small and medium scale PG&E commercial NEM customers with solar PV systems becoming ineligible for the A‐6 tariff, forcing those accounts to move to A‐10 or E‐19 tariffs. The result would be significant loss of value from the energy generated by the solar PV systems affected as the A‐10 and E‐19 tariffs both would add demand charges and offer lower time of use energy charges compared to the A‐6 tariff. This change would impact approximately seven of the ten solar PV installations owned by City of Benicia. Note that this risk exists whether the City remains a PG&E customer or elects to transition solar PV accounts to MCE. 4 AB-327 (2013-Perea, chaptered): 5 CPUC Proposed Decision 12-11-005, NEM grandfathering: http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M089/K245/89245777.PDF 6 II_Test_PGE_20130816_284307.pdf ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 4 of 7 October 28, 14 The issue of A‐6 tariff demand cap is currently being litigated at the CPUC. Hearings are being held in October, 2014 and briefs should be available in November, 2014. A Proposed Decision on the issue is anticipated in early‐mid Q1 2015, with a Final Decision late Q1 2015. At this time it is unclear how this will be resolved, but there is significant risk that the value of solar PV generated energy for accounts using PG&E’s A‐6 tariff will be diminished somewhat. Sage spoke with Justin Kudo, Manger of Account Services at MCE, about this scenario to determine MCE’s response to future changes in PG&E’s A‐6 tariff. MCE, while supportive of the solar‐friendly A‐6 tariff, would likely follow PG&E’s lead by matching significant changes to A‐6 such as capping eligibility at 75kW peak demand with changes to their COM‐6 tariff. 5. Impacts to net‐metering solar rates particularly as they relate to AB327: An important consideration is whether changing City of Benicia’s solar PV accounts from PG&E to MCE or vice versa during the NEM transition (grandfathered) period will affect eligibility for grandfathering of NEM 1.0 accounts. Changing energy providers will not affect NEM 1.0 grandfathering for two reasons: a. City of Benicia’s solar PV accounts would remain PG&E accounts. If City of Benicia selects MCE to provide electricity, the accounts remain PG&E accounts. PG&E continues to manage and bill the accounts, but the energy (called generation) portion of the electrical bill will be routed to MCE. b. CPUC Proposed Decision 12‐11‐005, Section 5.3.2, Transferability of Transitional Treatment – Conclusion, states7: “…systems that qualify to remain on their pre‐existing NEM tariff for the transition period will remain eligible for the complete transition period if transferred to a new owner, operator, or utility account at the original location.” Task 3 Appendices Appendix A: MCE Annual NEM Excess Bill Credit Payment Estimates Appendix B: Sage Annual MCE Excess Bill Credit Payment Estimates Appendix C: Sage Annual MCE Excess Bill Credit Payment Estimates, 2014 Pump Station 3 7 See Section 5.3: http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M089/K245/89245777.PDF ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 5 of 7 October 28, 14 Appendix A: Detailed MCE Annual NEM Excess Bill Credit Payment Estimates ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 6 of 7 October 28, 14 Appendix B: Sage Annual MCE Excess Bill Credit Payment Estimates ---PAGE BREAK--- MCE Solar PV Analysis MRW & Associates, LLC – City of Benicia MCE Analysis, Task 3 Page 7 of 7 October 28, 14 Appendix C: Sage Annual MCE Excess Bill Credit Payment Estimates, 2014 Pump Station 3 ---PAGE BREAK--- Attachment 4 Power Mix Comparison Marin Clean Energy and Pacific Gas and Electric Agenda Item No. 7 Attachment 4 ---PAGE BREAK--- Attachment 5 Electricity Rate Comparison Marin Clean Energy and Pacific Gas and Electric Agenda Item No. 7 Attachment 5 ---PAGE BREAK--- Agenda Item No. 7 Attachment 6 Net Energy Metering Program Comparison The following table compares the Net Energy Metering programs of MCE and PG&E. MCE NEM Program PG&E NEM PROGRAM All generation credited as Deep Green (retail rate + $0.01/kWh) All generation and usage credited at standard rates settlement of generation charges; PG&E delivery charges still settled annually Annual settlement of all charges Perpetual rollover of excess credits Excess credits are lost at annual true-up Annual cash out for credit balances over $100 at full retail rate Compensation based on net kWh of generation at below wholesale rate Program rules set by MCE Board at public meetings; public workshops are utilized to gather input and refine program elements Program rules set in standard regulatory process based on input from IOUs and CPUC ---PAGE BREAK--- Marin Energy Authority - Joint Powers Agreement - Effective December 19, 2008 As amended by Amendment No. 1 dated December 3, 2009 As further amended by Amendment No. 2 dated March 4, 2010 As further amended by Amendment No. 3 dated May 6, 2010 As further amended by Amendment No. 4 dated December 1, 2011 As further amended by Amendment No. 5 dated July 5, 2012 As further amended by Amendment No. 6 dated September 5, 2013 As further amended by Amendment No. 7 dated December 5, 2013 As further amended by Amendment No. 8 dated September 4, 2014 Among The Following Parties: City of Belvedere Town of Corte Madera Town of Fairfax City of Larkspur City of Mill Valley City of Novato City of Richmond Town of Ross Town of San Anselmo City of San Pablo City of San Rafael City of Sausalito Town of Tiburon County of Marin County of Napa Agenda Item No. 7 Attachment 7 ---PAGE BREAK--- MARIN ENERGY AUTHORITY JOINT POWERS AGREEMENT This Joint Powers Agreement (“Agreement”), effective as of December 19, 2008, is made and entered into pursuant to the provisions of Title 1, Division 7, Chapter 5, Article 1 (Section 6500 et seq.) of the California Government Code relating to the joint exercise of powers among the parties set forth in Exhibit B (“Parties”). The term “Parties” shall also include an incorporated municipality or county added to this Agreement in accordance with Section 3.1. RECITALS 1. The Parties are either incorporated municipalities or counties sharing various powers under California law, including but not limited to the power to purchase, supply, and aggregate electricity for themselves and their inhabitants. 2. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act, which mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels. The California Air Resources Board is promulgating regulations to implement AB 32 which will require local government to develop programs to reduce greenhouse emissions. 3. The purposes for the Initial Participants (as such term is defined in Section 2.2 below) entering into this Agreement include addressing climate change by reducing energy related greenhouse gas emissions and securing energy supply and price stability, energy efficiencies and local economic benefits. It is the intent of this Agreement to promote the development and use of a wide range of renewable energy sources and energy efficiency programs, including but not limited to solar and wind energy production. 4. The Parties desire to establish a separate public agency, known as the Marin Energy Authority (“Authority”), under the provisions of the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”) in order to collectively study, promote, develop, conduct, operate, and manage energy programs. 5. The Initial Participants have each adopted an ordinance electing to implement through the Authority Community Choice Aggregation, an electric service enterprise agency available to cities and counties pursuant to California Public Utilities Code Section 366.2 (“CCA Program”). The first priority of the Authority will be the consideration of those actions necessary to implement the CCA Program. Regardless of whether or not Program Agreement 1 is approved and the CCA Program becomes operational, the parties intend for the Authority to continue to study, promote, develop, conduct, operate and manage other energy programs. ---PAGE BREAK--- AGREEMENT NOW, THEREFORE, in consideration of the mutual promises, covenants, and conditions hereinafter set forth, it is agreed by and among the Parties as follows: ARTICLE 1 CONTRACT DOCUMENTS 1.1 Definitions. Capitalized terms used in the Agreement shall have the meanings specified in Exhibit A, unless the context requires otherwise. 1.2 Documents Included. This Agreement consists of this document and the following exhibits, all of which are hereby incorporated into this Agreement. Exhibit A: Definitions Exhibit B: List of the Parties Exhibit C: Annual Energy Use Exhibit D: Voting Shares 1.3 Revision of Exhibits. The Parties agree that Exhibits B, C and D to this Agreement describe certain administrative matters that may be revised upon the approval of the Board, without such revision constituting an amendment to this Agreement, as described in Section 8.4. The Authority shall provide written notice to the Parties of the revision of any such exhibit. ARTICLE 2 FORMATION OF MARIN ENERGY AUTHORITY 2.1 Effective Date and Term. This Agreement shall become effective and Marin Energy Authority shall exist as a separate public agency on the date this Agreement is executed by at least two Initial Participants after the adoption of the ordinances required by Public Utilities Code Section 366.2(c)(10). The Authority shall provide notice to the Parties of the Effective Date. The Authority shall continue to exist, and this Agreement shall be effective, until this Agreement is terminated in accordance with Section 7.4, subject to the rights of the Parties to withdraw from the Authority. 2.2 Initial Participants. During the first 180 days after the Effective Date, all other Initial Participants may become a Party by executing this Agreement and delivering an executed copy of this Agreement and a copy of the adopted ordinance required by Public Utilities Code Section 366.2(c)(10) to the Authority. Additional conditions, described in Section 3.1, may apply to either an incorporated municipality or county desiring to become a Party and is not an Initial Participant and (ii) to Initial Participants that have not executed and delivered this Agreement within the time period described above. ---PAGE BREAK--- 2.3 Formation. There is formed as of the Effective Date a public agency named the Marin Energy Authority. Pursuant to Sections 6506 and 6507 of the Act, the Authority is a public agency separate from the Parties. The debts, liabilities or obligations of the Authority shall not be debts, liabilities or obligations of the individual Parties unless the governing board of a Party agrees in writing to assume any of the debts, liabilities or obligations of the Authority. A Party who has not agreed to assume an Authority debt, liability or obligation shall not be responsible in any way for such debt, liability or obligation even if a majority of the Parties agree to assume the debt, liability or obligation of the Authority. Notwithstanding Section 8.4 of this Agreement, this Section 2.3 may not be amended unless such amendment is approved by the governing board of each Party. 2.4 Purpose. The purpose of this Agreement is to establish an independent public agency in order to exercise powers common to each Party to study, promote, develop, conduct, operate, and manage energy and energy-related climate change programs, and to exercise all other powers necessary and incidental to accomplishing this purpose. Without limiting the generality of the foregoing, the Parties intend for this Agreement to be used as a contractual mechanism by which the Parties are authorized to participate as a group in the CCA Program, as further described in Section 5.1. The Parties intend that subsequent agreements shall define the terms and conditions associated with the actual implementation of the CCA Program and any other energy programs approved by the Authority. 2.5 Powers. The Authority shall have all powers common to the Parties and such additional powers accorded to it by law. The Authority is authorized, in its own name, to exercise all powers and do all acts necessary and proper to carry out the provisions of this Agreement and fulfill its purposes, including, but not limited to, each of the following: 2.5.1 make and enter into contracts; 2.5.2 employ agents and employees, including but not limited to an Executive Director; 2.5.3 acquire, contract, manage, maintain, and operate any buildings, works or improvements; 2.5.4 acquire by eminent domain, or otherwise, except as limited under Section 6508 of the Act, and to hold or dispose of any property; 2.5.5 lease any property; 2.5.6 sue and be sued in its own name; 2.5.7 incur debts, liabilities, and obligations, including but not limited to loans from private lending sources pursuant to its temporary borrowing powers such as Government Code Section 53850 et seq. and authority under the Act; 2.5.8 issue revenue bonds and other forms of indebtedness; 2.5.9 apply for, accept, and receive all licenses, permits, grants, loans or other aids from any federal, state or local public agency; ---PAGE BREAK--- 2.5.10 submit documentation and notices, register, and comply with orders, tariffs and agreements for the establishment and implementation of the CCA Program and other energy programs; 2.5.11 adopt rules, regulations, policies, bylaws and procedures governing the operation of the Authority (“Operating Rules and Regulations”); and 2.5.12 make and enter into service agreements relating to the provision of services necessary to plan, implement, operate and administer the CCA Program and other energy programs, including the acquisition of electric power supply and the provision of retail and regulatory support services. 2.6 Limitation on Powers. As required by Government Code Section 6509, the power of the Authority is subject to the restrictions upon the manner of exercising power possessed by the County of Marin. 2.7 Compliance with Local Zoning and Building Laws. Notwithstanding any other provisions of this Agreement or state law, any facilities, buildings or structures located, constructed or caused to be constructed by the Authority within the territory of the Authority shall comply with the General Plan, zoning and building laws of the local jurisdiction within which the facilities, buildings or structures are constructed. ARTICLE 3 AUTHORITY PARTICIPATION 3.1 Addition of Parties. Subject to Section 2.2, relating to certain rights of Initial Participants, other incorporated municipalities and counties may become Parties upon the adoption of a resolution by the governing body of such incorporated municipality or such county requesting that the incorporated municipality or county, as the case may be, become a member of the Authority, the adoption, by an affirmative vote of the Board satisfying the requirements described in Section 4.9.1, of a resolution authorizing membership of the additional incorporated municipality or county, specifying the membership payment, if any, to be made by the additional incorporated municipality or county to reflect its pro rata share of organizational, planning and other pre-existing expenditures, and describing additional conditions, if any, associated with membership, the adoption of an ordinance required by Public Utilities Code Section 366.2(c)(10) and execution of this Agreement and other necessary program agreements by the incorporated municipality or county, payment of the membership payment, if any, and satisfaction of any conditions established by the Board. Notwithstanding the foregoing, in the event the Authority decides to not implement a CCA Program, the requirement that an additional party adopt the ordinance required by Public Utilities Code Section 366.2(c)(10) shall not apply. Under such circumstance, the Board resolution authorizing membership of an additional incorporated municipality or county shall be adopted in accordance with the voting requirements of Section 4.10. ---PAGE BREAK--- 3.2 Continuing Participation. The Parties acknowledge that membership in the Authority may change by the addition and/or withdrawal or termination of Parties. The Parties agree to participate with such other Parties as may later be added, as described in Section 3.1. The Parties also agree that the withdrawal or termination of a Party shall not affect this Agreement or the remaining Parties’ continuing obligations under this Agreement. ARTICLE 4 GOVERNANCE AND INTERNAL ORGANIZATION 4.1 Board of Directors. The governing body of the Authority shall be a Board of Directors (“Board”) consisting of one director for each Party appointed in accordance with Section 4.2. 4.2 Appointment and Removal of Directors. The Directors shall be appointed and may be removed as follows: 4.2.1 The governing body of each Party shall appoint and designate in writing one regular Director who shall be authorized to act for and on behalf of the Party on matters within the powers of the Authority. The governing body of each Party also shall appoint and designate in writing one alternate Director who may vote on matters when the regular Director is absent from a Board meeting. The person appointed and designated as the Director or the alternate Director shall be a member of the governing body of the Party. 4.2.2 The Operating Rules and Regulations, to be developed and approved by the Board in accordance with Section 2.5.11, shall specify the reasons for and process associated with the removal of an individual Director for cause. Notwithstanding the foregoing, no Party shall be deprived of its right to seat a Director on the Board and any such Party for which its Director and/or alternate Director has been removed may appoint a replacement. 4.3 Terms of Office. Each Director shall serve at the pleasure of the governing body of the Party that the Director represents, and may be removed as Director by such governing body at any time. If at any time a vacancy occurs on the Board, a replacement shall be appointed to fill the position of the previous Director in accordance with the provisions of Section 4.2 within 90 days of the date that such position becomes vacant. 4.4 Quorum. A majority of the Directors shall constitute a quorum, except that less than a quorum may adjourn from time to time in accordance with law. ---PAGE BREAK--- 4.5 Powers and Function of the Board. The Board shall conduct or authorize to be conducted all business and activities of the Authority, consistent with this Agreement, the Authority Documents, the Operating Rules and Regulations, and applicable law. 4.6 Executive Committee. The Board may establish an executive committee consisting of a smaller number of Directors. The Board may delegate to the executive committee such authority as the Board might otherwise exercise, subject to limitations placed on the Board’s authority to delegate certain essential functions, as described in the Operating Rules and Regulations. The Board may not delegate to the Executive Committee or any other committee its authority under Section 2.5.11 to adopt and amend the Operating Rules and Regulations. 4.7 Commissions, Boards and Committees. The Board may establish any advisory commissions, boards and committees as the Board deems appropriate to assist the Board in carrying out its functions and implementing the CCA Program, other energy programs and the provisions of this Agreement. 4.8 Director Compensation. Compensation for work performed by Directors on behalf of the Authority shall be borne by the Party that appointed the Director. The Board, however, may adopt by resolution a policy relating to the reimbursement of expenses incurred by Directors. 4.9 Board Voting Related to the CCA Program. 4.9.1. To be effective, on all matters specifically related to the CCA Program, a vote of the Board shall consist of the following: a majority of all Directors shall vote in the affirmative or such higher voting percentage expressly set forth in Sections 7.2 and 8.4 (the “percentage vote”) and the corresponding voting shares (as described in Section 4.9.2 and Exhibit D) of all such Directors voting in the affirmative shall exceed 50%, or such other higher voting shares percentage expressly set forth in Sections 7.2 and 8.4 (the “percentage voting shares”), provided that, in instances in which such other higher voting share percentage would result in any one Director having a voting share that equals or exceeds that which is necessary to disapprove the matter being voted on by the Board, at least one other Director shall be required to vote in the negative in order to disapprove such matter. 4.9.2. Unless otherwise stated herein, voting shares of the Directors shall be determined by combining the following: an equal voting share for each Director determined in accordance with the formula detailed in Section 4.9.2.1, below; and an additional voting share determined in accordance with the formula detailed in Section 4.9.2.2, below. 4.9.2.1 Pro Rata Voting Share. Each Director shall have an equal voting share as determined by the following formula: (1/total number of ---PAGE BREAK--- Directors) multiplied by 50, and 4.9.2.2 Annual Energy Use Voting Share. Each Director shall have an additional voting share as determined by the following formula: (Annual Energy Use/Total Annual Energy) multiplied by 50, where “Annual Energy Use” means, with respect to the first 5 years following the Effective Date, the annual electricity usage, expressed in kilowatt hours (“kWhs”), within the Party’s respective jurisdiction and (ii) with respect to the period after the fifth anniversary of the Effective Date, the annual electricity usage, expressed in kWhs, of accounts within a Party’s respective jurisdiction that are served by the Authority and “Total Annual Energy” means the sum of all Parties’ Annual Energy Use. The initial values for Annual Energy use are designated in Exhibit C, and shall be adjusted annually as soon as reasonably practicable after January 1, but no later than March 1 of each year 4.9.2.3 The voting shares are set forth in Exhibit D. Exhibit D may be updated to reflect revised annual energy use amounts and any changes in the parties to the Agreement without amending the Agreement provided that the Board is provided a copy of the updated Exhibit D. 4.10 Board Voting on General Administrative Matters and Programs Not Involving CCA. Except as otherwise provided by this Agreement or the Operating Rules and Regulations, each member shall have one vote on general administrative matters, including but not limited to the adoption and amendment of the Operating Rules and Regulations, and energy programs not involving CCA. Action on these items shall be determined by a majority vote of the quorum present and voting on the item or such higher voting percentage expressly set forth in Sections 7.2 and 8.4. 4.11 Board Voting on CCA Programs Not Involving CCA That Require Financial Contributions. The approval of any program or other activity not involving CCA that requires financial contributions by individual Parties shall be approved only by a majority vote of the full membership of the Board subject to the right of any Party who votes against the program or activity to opt-out of such program or activity pursuant to this section. The Board shall provide at least 45 days prior written notice to each Party before it considers the program or activity for adoption at a Board meeting. Such notice shall be provided to the governing body and the chief administrative officer, city manager or town manager of each Party. The Board also shall provide written notice of such program or activity adoption to the above-described officials of each Party within 5 days after the Board adopts the program or activity. Any Party voting against the approval of a program or other activity of the Authority requiring financial contributions by individual Parties may elect to opt-out of participation in such program or activity by ---PAGE BREAK--- providing written notice of this election to the Board within 30 days after the program or activity is approved by the Board. Upon timely exercising its opt-out election, a Party shall not have any financial obligation or any liability whatsoever for the conduct or operation of such program or activity. 4.12 Meetings and Special Meetings of the Board. The Board shall hold at least four regular meetings per year, but the Board may provide for the holding of regular meetings at more frequent intervals. The date, hour and place of each regular meeting shall be fixed by resolution or ordinance of the Board. Regular meetings may be adjourned to another meeting time. Special meetings of the Board may be called in accordance with the provisions of California Government Code Section 54956. Directors may participate in meetings telephonically, with full voting rights, only to the extent permitted by law. All meetings of the Board shall be conducted in accordance with the provisions of the Ralph M. Brown Act (California Government Code Section 54950 et seq.). 4.13 Selection of Board Officers. 4.13.1 Chair and Vice Chair. The Directors shall select, from among themselves, a Chair, who shall be the presiding officer of all Board meetings, and a Vice Chair, who shall serve in the absence of the Chair. The term of office of the Chair and Vice Chair shall continue for one year, but there shall be no limit on the number of terms held by either the Chair or Vice Chair. The office of either the Chair or Vice Chair shall be declared vacant and a new selection shall be made if: the person serving dies, resigns, or the Party that the person represents removes the person as its representative on the Board or the Party that he or she represents withdraws form the Authority pursuant to the provisions of this Agreement. 4.13.2 Secretary. The Board shall appoint a Secretary, who need not be a member of the Board, who shall be responsible for keeping the minutes of all meetings of the Board and all other official records of the Authority. 4.13.3 Treasurer and Auditor. The Board shall appoint a qualified person to act as the Treasurer and a qualified person to act as the Auditor, neither of whom needs to be a member of the Board. If the Board so designates, and in accordance with the provisions of applicable law, a qualified person may hold both the office of Treasurer and the office of Auditor of the Authority. Unless otherwise exempted from such requirement, the Authority shall cause an independent audit to be made by a certified public accountant, or public accountant, in compliance with Section 6505 of the Act. The Treasurer shall act as the depositary of the Authority and have custody of all the money of the Authority, from whatever source, and as such, shall have all of the duties and responsibilities specified in Section 6505.5 of the Act. The Board may require the Treasurer and/or Auditor to ---PAGE BREAK--- file with the Authority an official bond in an amount to be fixed by the Board, and if so requested the Authority shall pay the cost of premiums associated with the bond. The Treasurer shall report directly to the Board and shall comply with the requirements of treasurers of incorporated municipalities. The Board may transfer the responsibilities of Treasurer to any person or entity as the law may provide at the time. The duties and obligations of the Treasurer are further specified in Article 6. 4.14 Administrative Services Provider. The Board may appoint one or more administrative services providers to serve as the Authority’s agent for planning, implementing, operating and administering the CCA Program, and any other program approved by the Board, in accordance with the provisions of a written agreement between the Authority and the appointed administrative services provider or providers that will be known as an Administrative Services Agreement. The Administrative Services Agreement shall set forth the terms and conditions by which the appointed administrative services provider shall perform or cause to be performed all tasks necessary for planning, implementing, operating and administering the CCA Program and other approved programs. The Administrative Services Agreement shall set forth the term of the Agreement and the circumstances under which the Administrative Services Agreement may be terminated by the Authority. This section shall not in any way be construed to limit the discretion of the Authority to hire its own employees to administer the CCA Program or any other program. ARTICLE 5 IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS 5.1 Preliminary Implementation of the CCA Program. 5.1.1 Enabling Ordinance. Except as otherwise provided by Section 3.1, prior to the execution of this Agreement, each Party shall adopt an ordinance in accordance with Public Utilities Code Section 366.2(c)(10) for the purpose of specifying that the Party intends to implement a CCA Program by and through its participation in the Authority. 5.1.2 Implementation Plan. The Authority shall cause to be prepared an Implementation Plan meeting the requirements of Public Utilities Code Section 366.2 and any applicable Public Utilities Commission regulations as soon after the Effective Date as reasonably practicable. The Implementation Plan shall not be filed with the Public Utilities Commission until it is approved by the Board in the manner provided by Section 4.9. ---PAGE BREAK--- 5.1.3 Effect of Vote On Required Implementation Action. In the event that two or more Parties vote to approve Program Agreement 1 or any earlier action required for the implementation of the CCA Program (“Required Implementation Action”), but such vote is insufficient to approve the Required Implementation Action under Section 4.9, the following will occur: 5.1.3.1 The Parties voting against the Required Implementation Action shall no longer be a Party to this Agreement and this Agreement shall be terminated, without further notice, with respect to each of the Parties voting against the Required Implementation Action at the time this vote is final. The Board may take a provisional vote on a Required Implementation Action in order to initially determine the position of the Parties on the Required Implementation Action. A vote, specifically stated in the record of the Board meeting to be a provisional vote, shall not be considered a final vote with the consequences stated above. A Party who is terminated from this Agreement pursuant to this section shall be considered the same as a Party that voluntarily withdrew from the Agreement under Section 7.1.1.1. 5.1.3.2 After the termination of any Parties pursuant to Section 5.1.3.1, the remaining Parties to this Agreement shall be only the Parties who voted in favor of the Required Implementation Action. 5.1.4 Termination of CCA Program. Nothing contained in this Article or this Agreement shall be construed to limit the discretion of the Authority to terminate the implementation or operation of the CCA Program at any time in accordance with any applicable requirements of state law. 5.2 Authority Documents. The Parties acknowledge and agree that the affairs of the Authority will be implemented through various documents duly adopted by the Board through Board resolution, including but not necessarily limited to the Operating Rules and Regulations, the annual budget, and specified plans and policies defined as the Authority Documents by this Agreement. The Parties agree to abide by and comply with the terms and conditions of all such Authority Documents that may be adopted by the Board, subject to the Parties’ right to withdraw from the Authority as described in Article 7. ---PAGE BREAK--- ARTICLE 6 FINANCIAL PROVISIONS 6.1 Fiscal Year. The Authority’s fiscal year shall be 12 months commencing July 1 and ending June 30. The fiscal year may be changed by Board resolution. 6.2 Depository. 6.2.1 All funds of the Authority shall be held in separate accounts in the name of the Authority and not commingled with funds of any Party or any other person or entity. 6.2.2 All funds of the Authority shall be strictly and separately accounted for, and regular reports shall be rendered of all receipts and disbursements, at least quarterly during the fiscal year. The books and records of the Authority shall be open to inspection by the Parties at all reasonable times. The Board shall contract with a certified public accountant or public accountant to make an annual audit of the accounts and records of the Authority, which shall be conducted in accordance with the requirements of Section 6505 of the Act. 6.2.3 All expenditures shall be made in accordance with the approved budget and upon the approval of any officer so authorized by the Board in accordance with its Operating Rules and Regulations. The Treasurer shall draw checks or warrants or make payments by other means for claims or disbursements not within an applicable budget only upon the prior approval of the Board. 6.3 Budget and Recovery Costs. 6.3.1 Budget. The initial budget shall be approved by the Board. The Board may revise the budget from time to time through an Authority Document as may be reasonably necessary to address contingencies and unexpected expenses. All subsequent budgets of the Authority shall be prepared and approved by the Board in accordance with the Operating Rules and Regulations. 6.3.2 County Funding of Initial Costs. The County of Marin shall fund the Initial Costs of the Authority in implementing the CCA Program in an amount not to exceed $500,000 unless a larger amount of funding is approved by the Board of Supervisors of the County. This funding shall be paid by the County at the times and in the amounts required by the Authority. In the event that the CCA Program becomes operational, these Initial Costs paid by the County of Marin shall be included in the customer charges for electric services as provided by Section 6.3.4 to the extent permitted by law, and the County of Marin shall be reimbursed from the ---PAGE BREAK--- payment of such charges by customers of the Authority. The Authority may establish a reasonable time period over which such costs are recovered. In the event that the CCA Program does not become operational, the County of Marin shall not be entitled to any reimbursement of the Initial Costs it has paid from the Authority or any Party. 6.3.3 CCA Program Costs. The Parties desire that, to the extent reasonably practicable, all costs incurred by the Authority that are directly or indirectly attributable to the provision of electric services under the CCA Program, including the establishment and maintenance of various reserve and performance funds, shall be recovered through charges to CCA customers receiving such electric services. 6.3.4 General Costs. Costs that are not directly or indirectly attributable to the provision of electric services under the CCA Program, as determined by the Board, shall be defined as general costs. General costs shall be shared among the Parties on such basis as the Board shall determine pursuant to an Authority Document. 6.3.5 Other Energy Program Costs. Costs that are directly or indirectly attributable to energy programs approved by the Authority other than the CCA Program shall be shared among the Parties on such basis as the Board shall determine pursuant to an Authority Document. ARTICLE 7 WITHDRAWAL AND TERMINATION 7.1 Withdrawal. 7.1.1 General. 7.1.1.1 Prior to the Authority’s execution of Program Agreement 1, any Party may withdraw its membership in the Authority by giving no less than 30 days advance written notice of its election to do so, which notice shall be given to the Authority and each Party. To permit consideration by the governing body of each Party, the Authority shall provide a copy of the proposed Program Agreement 1 to each Party at least 90 days prior to the consideration of such agreement by the Board. 7.1.1.2 Subsequent to the Authority’s execution of Program Agreement 1, a Party may withdraw its membership in the Authority, effective as of the beginning of the Authority’s fiscal year, by giving no less than 6 ---PAGE BREAK--- months advance written notice of its election to do so, which notice shall be given to the Authority and each Party, and upon such other conditions as may be prescribed in Program Agreement 1. 7.1.2 Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its membership in the Authority following an amendment to this Agreement in the manner provided by Section 8.4. 7.1.3 Continuing Liability; Further Assurances. A Party that withdraws its membership in the Authority may be subject to certain continuing liabilities, as described in Section 7.3. The withdrawing Party and the Authority shall execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, as determined by the Board, to effectuate the orderly withdrawal of such Party from membership in the Authority. The Operating Rules and Regulations shall prescribe the rights if any of a withdrawn Party to continue to participate in those Board discussions and decisions affecting customers of the CCA Program that reside or do business within the jurisdiction of the Party. 7.2 Involuntary Termination of a Party. This Agreement may be terminated with respect to a Party for material non-compliance with provisions of this Agreement or the Authority Documents upon an affirmative vote of the Board in which the minimum percentage vote and percentage voting shares, as described in Section 4.9.1, shall be no less than 67%, excluding the vote and voting shares of the Party subject to possible termination. Prior to any vote to terminate this Agreement with respect to a Party, written notice of the proposed termination and the reason(s) for such termination shall be delivered to the Party whose termination is proposed at least 30 days prior to the regular Board meeting at which such matter shall first be discussed as an agenda item. The written notice of proposed termination shall specify the particular provisions of this Agreement or the Authority Documents that the Party has allegedly violated. The Party subject to possible termination shall have the opportunity at the next regular Board meeting to respond to any reasons and allegations that may be cited as a basis for termination prior to a vote regarding termination. A Party that has had its membership in the Authority terminated may be subject to certain continuing liabilities, as described in Section 7.3. In the event that the Authority decides to not implement the CCA Program, the minimum percentage vote of 67% shall be conducted in accordance with Section 4.10 rather than Section 4.9.1. 7.3 Continuing Liability; Refund. Upon a withdrawal or involuntary termination of a Party, the Party shall remain responsible for any claims, demands, damages, or liabilities arising from the Party’s membership in the Authority through the date of its withdrawal or involuntary termination, it being agreed that the Party shall not be responsible for any claims, demands, damages, or liabilities arising after the date of the Party’s withdrawal or involuntary termination. In addition, such ---PAGE BREAK--- Party also shall be responsible for any costs or obligations associated with the Party’s participation in any program in accordance with the provisions of any agreements relating to such program provided such costs or obligations were incurred prior to the withdrawal of the Party. The Authority may withhold funds otherwise owing to the Party or may require the Party to deposit sufficient funds with the Authority, as reasonably determined by the Authority, to cover the Party’s liability for the costs described above. Any amount of the Party’s funds held on deposit with the Authority above that which is required to pay any liabilities or obligations shall be returned to the Party. 7.4 Mutual Termination. This Agreement may be terminated by mutual agreement of all the Parties; provided, however, the foregoing shall not be construed as limiting the rights of a Party to withdraw its membership in the Authority, and thus terminate this Agreement with respect to such withdrawing Party, as described in Section 7.1. 7.5 Disposition of Property upon Termination of Authority. Upon termination of this Agreement as to all Parties, any surplus money or assets in possession of the Authority for use under this Agreement, after payment of all liabilities, costs, expenses, and charges incurred under this Agreement and under any program documents, shall be returned to the then-existing Parties in proportion to the contributions made by each. ARTICLE 8 MISCELLANEOUS PROVISIONS 8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts to settle all disputes arising out of or in connection with this Agreement. Should such efforts to settle a dispute, after reasonable efforts, fail, the dispute shall be settled by binding arbitration in accordance with policies and procedures established by the Board. 8.2 Liability of Directors, Officers, and Employees. The Directors, officers, and employees of the Authority shall use ordinary care and reasonable diligence in the exercise of their powers and in the performance of their duties pursuant to this Agreement. No current or former Director, officer, or employee will be responsible for any act or omission by another Director, officer, or employee. The Authority shall defend, indemnify and hold harmless the individual current and former Directors, officers, and employees for any acts or omissions in the scope of their employment or duties in the manner provided by Government Code Section 995 et seq. Nothing in this section shall be construed to limit the defenses ---PAGE BREAK--- available under the law, to the Parties, the Authority, or its Directors, officers, or employees. 8.3 Indemnification of Parties. The Authority shall acquire such insurance coverage as is necessary to protect the interests of the Authority, the Parties and the public. The Authority shall defend, indemnify and hold harmless the Parties and each of their respective Board or Council members, officers, agents and employees, from any and all claims, losses, damages, costs, injuries and liabilities of every kind arising directly or indirectly from the conduct, activities, operations, acts, and omissions of the Authority under this Agreement. 8.4 Amendment of this Agreement. This Agreement may be amended by an affirmative vote of the Board in which the minimum percentage vote and percentage voting shares, as described in Section 4.9.1, shall be no less than 67%. The Authority shall provide written notice to all Parties of amendments to this Agreement, including the effective date of such amendments. A Party shall be deemed to have withdrawn its membership in the Authority effective immediately upon the vote of the Board approving an amendment to this Agreement if the Director representing such Party has provided notice to the other Directors immediately preceding the Board’s vote of the Party’s intention to withdraw its membership in the Authority should the amendment be approved by the Board. As described in Section 7.3, a Party that withdraws its membership in the Authority in accordance with the above-described procedure may be subject to continuing liabilities incurred prior to the Party’s withdrawal. In the event that the Authority decides to not implement the CCA Program, the minimum percentage vote of 67% shall be conducted in accordance with Section 4.10 rather than Section 4.9.1. 8.5 Assignment. Except as otherwise expressly provided in this Agreement, the rights and duties of the Parties may not be assigned or delegated without the advance written consent of all of the other Parties, and any attempt to assign or delegate such rights or duties in contravention of this Section 8.5 shall be null and void. This Agreement shall inure to the benefit of, and be binding upon, the successors and assigns of the Parties. This Section 8.5 does not prohibit a Party from entering into an independent agreement with another agency, person, or entity regarding the financing of that Party’s contributions to the Authority, or the disposition of proceeds which that Party receives under this Agreement, so long as such independent agreement does not affect, or purport to affect, the rights and duties of the Authority or the Parties under this Agreement. 8.6 Severability. If one or more clauses, sentences, paragraphs or provisions of this Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby agreed by the Parties, that the remainder of the Agreement shall not be affected thereby. Such clauses, sentences, paragraphs or provision shall be deemed reformed so as to be lawful, valid and enforced to the maximum extent possible. ---PAGE BREAK--- 8.7 Further Assurances. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement. 8.8 Execution by Counterparts. This Agreement may be executed in any number of counterparts, and upon execution by all Parties, each executed counterpart shall have the same force and effect as an original instrument and as if all Parties had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. 8.9 Parties to be Served Notice. Any notice authorized or required to be given pursuant to this Agreement shall be validly given if served in writing either personally, by deposit in the United States mail, first class postage prepaid with return receipt requested, or by a recognized courier service. Notices given personally or by courier service shall be conclusively deemed received at the time of delivery and receipt and by mail shall be conclusively deemed given 48 hours after the deposit thereof (excluding Saturdays, Sundays and holidays) if the sender receives the return receipt. All notices shall be addressed to the office of the clerk or secretary of the Authority or Party, as the case may be, or such other person designated in writing by the Authority or Party. Notices given to one Party shall be copied to all other Parties. Notices given to the Authority shall be copied to all Parties. ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- Exhibit A To the Joint Powers Agreement Marin Energy Authority -Definitions- “AB 117” means Assembly Bill 117 (Stat. 2002, ch. 838, codified at Public Utilities Code Section 366.2), which created CCA. “Act” means the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) “Administrative Services Agreement” means an agreement or agreements entered into after the Effective Date by the Authority with an entity that will perform tasks necessary for planning, implementing, operating and administering the CCA Program or any other energy programs adopted by the Authority. “Agreement” means this Joint Powers Agreement. “Annual Energy Use” has the meaning given in Section 4.9.2.2. “Authority” means the Marin Energy Authority. “Authority Document(s)” means document(s) duly adopted by the Board by resolution or motion implementing the powers, functions and activities of the Authority, including but not limited to the Operating Rules and Regulations, the annual budget, and plans and policies. “Board” means the Board of Directors of the Authority. “CCA” or “Community Choice Aggregation” means an electric service option available to cities and counties pursuant to Public Utilities Code Section 366.2. “CCA Program” means the Authority’s program relating to CCA that is principally described in Sections 2.4 and 5.1. “Director” means a member of the Board of Directors representing a Party. “Effective Date” means the date on which this Agreement shall become effective and the Marin Energy Authority shall exist as a separate public agency, as further described in Section 2.1. ---PAGE BREAK--- “Implementation Plan” means the plan generally described in Section 5.1.2 of this Agreement that is required under Public Utilities Code Section 366.2 to be filed with the California Public Utilities Commission for the purpose of describing a proposed CCA Program. “Initial Costs” means all costs incurred by the Authority relating to the establishment and initial operation of the Authority, such as the hiring of an Executive Director and any administrative staff, any required accounting, administrative, technical and legal services in support of the Authority’s initial activities or in support of the negotiation, preparation and approval of one or more Administrative Services Provider Agreements and Program Agreement 1. Administrative and operational costs incurred after the approval of Program Agreement 1 shall not be considered Initial Costs. “Initial Participants” means, for the purpose of this Agreement, the signatories to this JPA as of May 5, 2010 including City of Belvedere, Town of Fairfax, City of Mill Valley, Town of San Anselmo, City of San Rafael, City of Sausalito, Town of Tiburon and County of Marin. “Operating Rules and Regulations” means the rules, regulations, policies, bylaws and procedures governing the operation of the Authority. “Parties” means, collectively, the signatories to this Agreement that have satisfied the conditions in Sections 2.2 or 3.2 such that it is considered a member of the Authority. “Party” means, singularly, a signatory to this Agreement that has satisfied the conditions in Sections 2.2 or 3.2 such that it is considered a member of the Authority. “Program Agreement 1” means the agreement that the Authority will enter into with an energy service provider that will provide the electricity to be distributed to customers participating in the CCA Program. “Total Annual Energy” has the meaning given in Section 4.9.2.2. ---PAGE BREAK--- Exhibit B To the Joint Powers Agreement Marin Energy Authority -List of the Parties- City of Belvedere Town of Corte Madera Town of Fairfax City of Larkspur City of Mill Valley City of Novato City of Richmond Town of Ross Town of San Anselmo City of San Pablo City of San Rafael City of Sausalito Town of Tiburon County of Marin County of Napa ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- Agenda Item No. 7 Attachment 8 ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK--- ---PAGE BREAK---