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HomeMy WebLinkAboutCM Marin Clean Energy Program ParticipationCITY OF�� SAN Department: CITY MANAGER Prepared by: Ken Agenda Item No: 7 Meeting Date: January 4, 2010 COUNCIL AGENDA REPORT City Manager Approval: SUBJECT: CONSIDERATION OF CONTINUED PARTICIPATION IN THE MARIN ENERGY AUTHORITY'S MARIN CLEAN ENERGY PROGRAM 1. REVIEW OF MCE CONTRACTS (POWER PURCHASE AGREEMENTS) FOR RENEWABLE ELECTRIC POWER 2. FINAL DECISION WHETHER TO REMAIN IN, OR WITHDRAW, FROM THE MARIN ENERGY AUTHORITY AND MARIN CLEAN ENERGY PROGRAM RECOMMENDATION: Staff recommends that the City Council review and provide direction on the final MCE draft Power Purchase Agreement documents. After PPA review, should the City Council wish to not proceed, a formal action is required to withdraw from the Marin Clean Energy Program. BACKGROUND: In 2002, AB 117 legislation became State, law that allowed the creation of "Community Choice Aggregation" (CCA). Local government agencies under the CCA law could purchase electricity on their own, instead of through a sole provider, such as Pacific Gas & Electric (PG&E). In 2004, the County of Marin and local water districts began a study to assess the feasibility of a CCA organization in Marin. The 2005 study concluded that a CCA program was indeed feasible in Marin. Later that year, the County and local jurisdictions formed a Local Government Task Force to track the development of a Business Plan to form a Marin CCA. The Business Plan was prepared through contracts with consultants and subject matter experts. The Marin Community Choice Aggregation Business Plan (completed in April 2008) sets forth an outline for a countywide agency -- established through a Joint Powers Agreement (JPA) among the County and participating cities -- that would provide electrical energy to its members. The CCA, now labeled as "Marin Clean Energy" (MCE), was formed through the adoption of a JPA for a Marin Energy Authority (MEA). The JPA established a governing board of representatives from the County and participating cities. The JPA ordinance and related documents were thoroughly reviewed by the City Managers, City Attorneys and other agencies' staff as needed. The Business Plan assumed adoption of the JPA by potential member agencies as of December 2008. FOR CITY CLERK ONLY File No.: Council Meeting: Disposition: SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 2 City Participation in Marin Energy Authority: To maximize opportunities for education about Marin Clean Energy, and the related fiscal, organizational and political implications for the City of San Rafael, a full schedule of education sessions, public input opportunities, and City Council review meetings were proposed and approved by the City Council in May 2008. Since that date, the following has occurred. •b A comprehensive and open education and information process happened from May through November 2008. The City conducted outreach efforts by discussing MCE in several Snapshot postings, and developed a link on the City's website to a number of important references and documents. Our outreach work over this time period produced an enormous amount of e-mails, letters, faxes, and other correspondence regarding MEA and Marin Clean Energy. Anyone wishing to peruse these writings can contact the City Clerk's office and review what has been submitted. ❖ On June 24, 2008, the Community and City Council heard a proposal from Dawn Weisz, County of Marin. Dawn summarized the details of the MCE business plan, including assumptions regarding renewable portfolio goals, customer rates, and projected green house gas (GHG) emission reductions. Additionally, PG&E provided its comments and concerns regarding the proposed MCE business plan. Lastly, representatives from the California Public Utilities Commission (CUP) offered a statewide perspective on energy and climate change policies. ❖ Three neighborhood meetings were conducted. The principal focus of these meetings was to allow the public to direct their comments, suggestions and ideas to the City Council in connection with its consideration of whether to join the JPA and MCE program. The cumulative attendance at these meetings was approximately 100 participants. ❖ A Special Meeting of the City Council was held on November 18, 2008, to allow for additional input on MEA, the CCA program and the Business Plan. This session also provided feedback from a review of the Business Plan as developed and published by MRW and Associates. •b A formal City Council public hearing was conducted on November 24`h, 2008, for the express purpose of San Rafael considering becoming a member of the Marin Energy Authority JPA. The City Council adopted an ordinance that evening, approving the Marin Energy Authority Joint Powers Agreement, and authorizing the implementation of a Community Choice Aggregation Program. New State Regulations AB 32 - AB 32 requires local governments to limit greenhouse gas (GHG) emissions from government operations and potentially from some sectors in the community as well. Statewide GHG emissions must be reduced to 1990 levels by 2020. SB 375 - SB 375 builds on the existing regional transportation planning process (which is overseen by local elected officials with land use responsibilities) to connect the reduction of greenhouse gas (GHG) emissions from cars and light trucks to land use and transportation policy. AB 32 set the stage for SB 375. Accordingly, SB 375 has three goals: (1) to use the regional transportation planning process to help achieve AB 32 goals; (2) to use CEQA streamlining as an incentive to encourage residential projects which help achieve AB 32 goals to reduce GHG emissions; and (3) to coordinate the regional housing needs allocation process with the regional transportation planning process. SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 3 San Rafael's Climate Change Action Plan (CCAP): In 2005, San Rafael was one of the early signatories to the U.S. Conference of Mayors Climate Protection Agreement, committing the City to working to meet the goals of the Kyoto Protocol. The City Council directed the preparation of a Climate Change Action Plan to chart a path toward greenhouse gas (GHG) reductions. In March 2008 the City Council appointed a 14 -member Green Ribbon Committee composed of volunteers with diverse expertise, but a common interest in sustainability, to prepare a draft plan with extensive community input. In addition, the Council appointed four Green Teams, composed of additional volunteer subject experts, to brainstorm ideas for possible City actions in the areas of: Energy conservation and production, • Purchasing and Recycling, Land Use/Transportation/Green Building and Urban Forest, and • Adaptation to Sea Level Rise. The result of this community planning effort produced the San Rafael Climate Change Action Plan (CCAP) which was adopted by the City Council on April 20, 2009. The Climate Change Plan targets a total GHG reduction of 25% by 2020, to be achieved as actions at other levels of government, technological improvements and local educational efforts continue to spur residents and businesses to reduce their carbon footprints. The City will have to periodically update the Plan to achieve both this 2020 goal and the ambitious 80% State reductions by 2050. As noted in the CCAP report, the Transportation Sector is by far the largest emitter (61.3%) of the greenhouse gas emissions in the San Rafael community. Emissions from the Residential and Commercial/ Industrial Sectors account for a combined 34.1%, and the remaining 4.6% is the result of emissions from waste sent to landfill. The Plan identifies strategies and programs by which the City can reduce greenhouse gas generation in its municipal buildings and operations, as well as ways that the City can influence our residential and business community to reduce their climate impacts. Specific to this staff report, one of the recommended programs coming from the CCAP is: BU1: Support efforts of Marin Energy Authority to increase the proportion of renewable power offered to residents and businesses and to provide financial and technical assistance for energy efficiency upgrades. ANALYSIS: To take action on Marin's GHG emissions and begin implementation of GHG reduction measures, the Marin Energy Authority (MEA), was launched on December 19, 2008. The MEA Board is composed of nine elected representatives, one from each of the member jurisdictions as follows: Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San Rafael, Sausalito, Tiburon, and the County of Marin. The purpose of MEA is to address climate change by reducing energy related greenhouse gas emissions and securing energy supply, price stability, energy efficiencies and local economic and workforce benefits. It is the intent of MEA to promote the SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 4 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 at competitive rates for customers. Since the formation of MEA, a calendar of specific tasks and events has been scheduled over 2009. The initial focus of work was to develop energy supply contracts (known as Power Purchase Agreements) through a competitive bidding process. As lifted from the MEA website, the following activities have been completed in 2009 or remain to be accomplished over the next few months. Some details regarding specific tasks and accomplishments of MEA follows the table listed below. On May 7th the MEA Board approved and released a Request for Proposal (RFP) for `full requirements' electricity supply. This competitive solicitation process resulted in 12 bids for power with prices in the expected range described in Marin's CCA business plan. The power costs projected in the bid proposals would be at or below PG&E's projected rates for the light green option (starting at 25% renewable energy, growing to 50% in four years). The deep green option (100% renewable energy) would also be available to customers for a slight premium above PG&E's projected rates. On September 3`'; the MEA Board selected three of the twelve bidders for contract negotiations. On October 1St, the MEA Board approved and released a draft contract for power purchase. The general terms of the contract are as follows: • The contract is based on the industry -standard Edison Electric Institute (EEI), Master Power Purchase and Sale Agreement • The contract insulates municipal funds/budgets before, during and after the delivery period SAN RAFAEL CITY COUNCIL AGENDA REPORT / Palle: 5 Five year delivery period, beginning on June 1, 2010 and ending on May 31, 2015 Fixed annual pricing throughout the term On November 5'"' the MEA Board approved and released a final draft contract for power purchase. This action initiated the 90 -day review period for the final contract. The draft contract was delivered to San Rafael on November 6`h. The contract package included an overview summarizing the Power Purchase Agreement (PPA) documents as well as the three components of the draft PPA for the Marin Energy Authority to secure power supply for the Marin Clean Energy program. The final draft PPA is the result of extensive negotiations and review by the MEA Board, its ad hoc contract committee, staff, technical, and legal consultants, the city manager peer review, and input from the public. There remains a final opportunity to weigh in on the various draft power purchase agreements currently still in negotiations with MEA and the primary company under consideration for this electricity supply contract. These agreements are included in this report as follows: L+ Attachment A - Contract Overview '+ Attachment B - Master Power Purchase and Sale Agreement L+ Attachment C - Master Power Purchase and Sale Agreement — Cover Sheet L4 Attachment D - Confirmation L4 Attachment E - MEA CEQA Notice for Public Review and Comment Period NOTE: Comment period closes at end of business day on January 15`h, 2010 L4 Attachment F — MEA Resolution approved November 5, 2009, required MEA Board not approve the draft PPA unless the price for customer electricity costs for the Light green energy product can be at or below PG&E's projected costs. San Rafael Involvement, Input and Decision: As was done with the Business Plan, the Marin Managers Association (those who serve MEA cities and the County) contracted with MRW and Associates to provide a review and comment on the proposed contracts. Their analysis of the draft PPA contracts, plus a review of financial risks to MEA, are included in their report and attached as Exhibit I. Along the way, I proposed additional questions related to the PPA contracts, as well as the process, which I felt needed to be addressed on behalf of the City, ratepayers and MCE members (see Exhibit Ilb). Dawn Weisz provided responses to my letter of October 27, 2009. Refer to Exhibit Ila for the MEA answers to my questions. In concert with this schedule, San Rafael was provided an overview of the process to date and contracts at an October 5, 2009 meeting. Dawn Weisz and the MEA staff provided the contracts and an overview of the negotiations up through the draft agreement period of October 1s` noted above. This report was used in other jurisdictions over the past few weeks, and is provided as Exhibit Ill. Over the last few weeks, additional information has become available. The MEA Board approved a draft Community Choice Aggregation Implementation Plan and Statement of Intent. This is a necessary step to comply with CPUC requirements, and provides updated information that was first outlined in the approved MEA Business Plan in 2008. The Implementation Plan is included as Exhibit IV. SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 6 The Marin County Civil Grand Jury released a report entitled "Marin Clean Energy: Pull the Plug". It is included as Exhibit V. A preliminary response to the Grand Jury Report was approved by the MEA on December 7m (see Exhibit VI). It is worth noting that all MEA member agencies, including the City of San Rafael, must provide a response to the grand jury. Our responses are due by the end of February (90 day due date). The City staff will be preparing a separate report for future City Council consideration and public input to comply with our obligations. Lastly, MEA also issued another Frequently Asked Questions, linked to some issues raised in the Grand Jury Report. This 4 page explanation to key issues is enclosed as Exhibit Vll. At the request of the Marin City Managers, two additional forums were held to provide information and seek public input on the MCE draft contracts. One was held on November 23rd in San Rafael, the second on December 1s` in Mill Valley. The purpose of these workshops was to allow members of the Marin County community to learn more about the proposed Marin Clean Energy program. These workshops were filmed by the Community Media Center for Marin and are now available for view at http://cmcm.tv/MEAPublicWorkshops. Section 7.1.1.1 of the Marin Energy Authority Joint Powers Agreement provides that prior to the Authority's execution of Program Agreement 1 (the draft PPA as attached to this report), 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. The projected date for MEA contract execution with an energy service provider is February 4, 2010. City staff expects the MEA Board to execute an agreement on this date. Given the structure of the JPA, and the 30 day noticing, Dawn has now confirmed that the final withdrawal date would be no later than January 13, 2010. One reason this item has been held until now for San Rafael consideration is the January 4, 2010 meeting is the first time all of the Council, post the November 2009 election, has been available to consider this PPA and MCE item for additional action. Summary and Recommendations: As has been stated all along in this CCA/MCE Program development, there are inherent risks and rewards which remain should the draft PPA's become binding on all member agencies via MEA action in February 2010. Below are some noteworthy outcomes and remaining issues as the City Council considers whether to continue support of the MCE program. 1. On the plus side, most people still like choices in their lives. It is true in our homes, our automobiles, and even our coffee drinks. Having a PPA that offers greener power, with varying price structures, allows residents and businesses to decide to stay with the current provider, PG&E, or make a switch to the MCE programs. Currently, about 25% of energy customers receive their power from municipal suppliers. Having government -provided electric power is not new in California. This is supported by the fact that public power agencies have been in business for a century in the Golden State. Customers only get an option to choose if San Rafael and other member agencies stay the course with the PPA and MCE program. 2. The PPA may serve as a bridge to longer term, local solutions. As noted in the business plan, our City, like all across the State, will be required to meet AB 32 GHG reduction goals. Our approved Climate Change Action Plan states our GHG reduction targets. The MCE effort presents a potential opportunity to collaborate with other Marin agencies in order to achieve carbon reductions. 3. Bear in mind that this Power Purchase Agreement will create GHG reductions for Marin, but not due to any new capacity (via the PPA contracts) initially being created across the State, nation, or beyond. This PPA does not produce renewable energy SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 7 locally. The future outlook is the continued increase demand for renewable energy products will provide market force effort to create additional capacity. Long term MEA renewable product solutions are intended to come from projects to be developed outside of the PPA five year contract proposal. 4. The MRW and Associates report raised specific contract issues, and recommendations to minimize risk and provide better resolution and protection for MEA and its customers. Some of these issues and recommendations have already been addressed in contract negotiations, which have been occurring weekly ever since the MRW report was issued. Financial risks regarding PG&E Exit fees, and MEA Departing Load Fees, are not resolved at this time. 5. Price competitiveness has been a selling point among MCE advocates. The bottom line is this — even though a MEA Resolution declares to not move forward on the PPA without making sure electricity pricing is at or below PG&E projected pricing, there are no guarantees. No pricing has been publicly stated at this point. It is impossible to measure outcomes of price savings or comparability over the term of this contract. Too many variables could impact future rates, including the CPUC annual rate setting for PG&E, natural gas prices, consumption and rate tiers, etc. Prices may be deemed competitive, but the only real rate comparison will be known when the CPUC sets PG&E rates for 2010, and MEA locks in 5 year fixed pricing. 6. MRW's report also made note of MEA needing to be abundantly clear about explanation of price competitiveness for light green power with PG&E. As stated in their report. MRW states ..."the meaning of "Projection" to meet or beat PG&E rates. MEA has stated that one of the benefits for customers is "Costs at or below PG&E" In discussions with MRW, MEA has clarified that this condition is based on comparing the projected overall costs of MEA assuming power supply by a third party over the term of the Agreements against MEA's costs assuming power supply was provided by PG&E at MEA's forecast of PG&E's tariffed generation rate. In other words, the following inequality must occur for MEA to sign the Agreements: MEA Power Supply Costs + Customer Exit Fees + MEA Overhead < PG&E Gen Rate Of course, all of the above factors are somewhat uncertain, although MEA Power Supply Costs are less uncertain than the other factors. Recommendation: MRW is concerned that customers might misinterpret MEA's statements regarding the rates for the Light Green product. To avoid that, MRW recommends that MEA make it very clear that such a commitment is based on reasonable commercial efforts. This would provide MEA with the flexibility it may need to meet its other policy goals (e.g., greenhouse gas reductions, greater levels of renewables, local control) even if, in one particular year or another, market pricing turns against MEA, resulting in costs to MEA customers being higher than if they were PG&E customers". 7. Regarding the MCE program, there is no financial risk to the City of San Rafael to stay this course. Much legal debate has been occurring between the legal experts of MEA and PG&E. The City Attorney has devoted substantial time to reviewing this matter and notes that both the MEA JPA Agreement and the PPA provide that the member entities shall not be liable for the obligations of the JPA. This "firewall" provision is authorized by state law. However, MEA must still obtain approval from the California Public Utilities Commission (PUC). It remains possible that the PUC could determine that MEA — in order to receive PUC approval — require the member SAN RAFAEL CITY COUNCIL AGENDA REPORT / Page: 8 cities (and County) to be liable for MEA's debts and obligations. The PUC's determination whether to impose such a requirement will rest on its analysis of the credit -worthiness of MEA. Should the PUC decide to impose such "joint and several" liability, each of the members of MEA would be faced with the decision whether to agree to assume such liability. In other words, the City could only assume such liability if the San Rafael City Council were to agree to it at a future date. As MEA has been founded on the principle that the general funds of the member entities will not be placed at risk, it is likely that none of the member entities, including the City, would agree to assume such liability. FISCAL IMPACT: Continuation in the MEA and MCE programs does not cause any immediate financial impact to the City's budget. If the PPA moves forward, the City over the next year will need to decide to what extent we will be customers (for City facilities), and under which options would we participate. Some MCE program options (e.g.' dark green) will increase the cost of the City's budget. We currently budget $876k for annual electricity costs across all funds. Using the MCE pricing model, we can assume about 'h of this sum ($438k) is for PG&E transmission and distribution; the other 50% being tied to consumption/usage. If so, a 10% dark green cost to the City could run $44k per year. I'll state the obvious — with our budget challenges, any decision to pay for electricity procurement above current costs is just another reduction in some other level of service. This decision is not for now, but if the PPA and MCE move forward, it will be before us for fiscal year 2010-2011. Having joined the MEA JPA creates possible future financial obligations to the City. The enabling MEA Ordinance, under Sections 6.3.3 (general costs) and 6.3.4 (other energy program costs) allows for cost sharing among member agencies, under allocations and formulas defined by the MEA Board. To date, I am not aware of any costs or formulas having been established, nor charges levied, to member agencies. As MEA members, the City is contractually obligated for our share of non -CCA expenses pursuant to the MEA Board of Directors action on such matters. With regard to the PPA, this is a cost intended to be solely borne by MCE customers. Not only is the purchase price of energy intended to be passed along, but so are other administrative, start up and related PPA oversight costs incurred by MEA. This roll up (all inclusive) approach was defined in the enabling Ordinance Section 6.3.2, which states: "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. If the City continues to be a member of the MEA JPA, it is my full understanding from conversing with MEA staff that the soup to nuts cost of running the MCE program will be 100% borne by Marin Clean Energy rate payers. No MCE program cost will be born by the member agencies' General Funds. SAN RAFAEL CITY COUNCIL. AGENDA REPORT / Page: 9 OPTIONS: The City Council may choose to: 1. Take no action. In doing so, the City of San Rafael will remain in the Marin Energy Authority and be bound to a future Power Purchase Agreement (Program Agreement #1) if so acted upon by the MEA Board. 2. Withdraw from MEA/MCE — by an affirmative voter calling for the withdrawal from MEA/MCE. In doing so, a formal letter would be prepared and sent to the MEA Board prior to it taking any future actions on the PPA. 3. Seek additional information and responses, and ask staff to return with the needed input; this would require continuing this Council agenda item until a meeting no later than January 12`h to coincide with the JPA provisions and MEA Board timing. ACTION REQUIRED: Hear the staff report and ask questions regarding the process or PPA documents, conduct the public meeting, and, if warranted, by motion, take action to withdraw from the MEA and MCE program Attachments: Attachment A - Contract Overview Attachment B - Master Power Purchase and Sale Agreement Attachment C - Master Power Purchase and Sale Agreement — Cover Sheet Attachment D - Confirmation Attachment E - MEA CEQA Notice Attachment F — MEA Cost Competiveness Resolution Exhibit I — MRW and Associates Report Exhibit II — Correspondence between City of San Rafael and MEA Exhibit III — MEA PowerPoint on MCE Process and Contract Overview Exhibit IV — MEA draft Community Choice Aggregation Implementation Plan and Statement of Intent Exhibit V - Marin County Civil Grand Jury Report - MCE Exhibit VI — MEA Preliminary Response to Grand Jury Report Exhibit VII — MEA FAQ Sheet Exhibit VIII — Public Correspondence W:\City Managers- WorkFile\Council Material\Staff Reports\10\mea mce participation and contract report.doc Attachment 'A' Marin Energy Authority Draft Power Purchase and Sale Agreement Attached you will find three components of the draft Power Purchase Agreement (PPA) for the Marin Energy Authority to secure power supply for the Marin Clean Energy program. The three components of the Agreement are described below. In addition, key terms of the contract are outlined below in the overview section. 1. EEI Master Power Purchase & Sale Agreement This Edison Electric Institute (EEI) Agreement is a standard industry document used by public and private utilities across the United States for power purchase and sale. 2. EEI Master Power Purchase & Sale Agreement Cover Sheet This document provides additional detail related to MEA's specific transaction, identifying exceptions, clarifications and areas of applicability which modify the standards terms and conditions of the Master EEI Agreement. 3. Confirmation This document is referenced in the EEI Agreement and defines the commercial terms of MEA's transaction. Key details include energy quantities, pricing and delivery term. The Confirmation also contains the terms and conditions pertinent to renewable energy content and environmental attributes. ----------------------------------Contract Overview ---------------------------------------- General Contract Terms • Contract is based on the industry -standard Edison Electric Institute (EEI), Master Power Purchase and Sale Agreement • Contract insulates municipal funds/budgets before, during and after the delivery period • Five year delivery period, beginning on June 1, 2010 and ending on May 31, 2015 Commercial Terms • Full requirements product to be provided by the supplier, including all: electric energy, renewable energy, capacity, ancillary services (as required by the California Independent System Operator) and scheduling coordination services • All MEA customers will receive at least 25% of energy deliveries from California Energy Commission eligible renewable resources • Supplier must maintain a minimum, "investment grade" credit rating • MEA's credit exposure is limited to customer receipts/revenues • MEA will be allowed to substitute renewable energy generated by newly developed and/or purchased resources for contracted energy volumes based on mutually agreeable terms among the parties Other Important Considerations • Energy pricing will be refreshed prior to contract signing • MEA will not execute PPA if costs will not support Light Green (25% renewable) generation at or below PG&E costs • MEA customers may voluntarily participate in a competitively priced energy supply option that will provide 100% of energy deliveries from clean, renewable fuel sources — energy supplier will procure renewable energy volumes sufficient to support MCE's "Deep Green" product Finding Contract Provisions in Draft Agreement • Contract energy price at or below PG&E's generation charges for Light Green energy: Confirmation #5 • No risk or contribution from city, town, or county budgets: EEI Cover Sheet, Other Changes, #26 • Five year, full requirements contract (all energy, scheduling, load following, risk management) at a fixed price: Confirmation #2 • Substituting MEA owned or acquired assets is allowed: Confirmation #11 • Deep green at 100% renewable energy: Confirmation #2.2 • Guaranteed supply of power 24 hrs/day: Confirmation #2 Attachment 'B' Master Power Purchase &Sale Agreement �9 EDISON ELECTRICgg�$ INSTITUTE MYMAAYfl Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association ALL RIGHTS RESERVED UNDER U.S. AND FOREIGN LAW, TREATIES AND CONVENTIONS AUTOMATIC LICENSE — PERMISSION OF THE COPYRIGHT OWNERS IS GRANTED FOR REPRODUCTION BY DOWNLOADING FROM A COMPUTER AND PRINTING ELECTRONIC COPIES OF THE WORK, NO AUTHORWED COPY MAY BE SOLD. THE INDUSTRY IS ENCOURAGED TO USE THIS MASTER POWER PURCHASE AND SALE AGREEMENT IN ITS TRANSACTIONS. ATTRIBUTION TO THE COPYRIGHT OWNERS IS REQUESTED. MASTER POWER PURCHASE AND SALES AGREEMENT TABLE OF CONTENTS COVERSHEET...............................................................................................................................1 GENERAL TERMS AND CONDITIONS.....................................................................................6 ARTICLE ONE: GENERAL DEFINITIONS.........................................................................6 ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS......................................11 2.1 Transactions...........................................................................................................11 2.2 Governing Terms...................................................................................................11 2.3 Confirmation..........................................................................................................11 2.4 Additional Confirmation Terms.............................................................................12 2.5 Recording...............................................................................................................12 ARTICLE THREE: OBLIGATIONS AND DELIVERIES.......................................................12 3.1 Seller's and Buyer's Obligations...........................................................................12 3.2 Transmission and Scheduling................................................................................12 3.3 Force Majeure........................................................................................................13 ARTICLE FOUR: REMEDIES FOR FAILURE TO DELIVER/RECEIVE ..........................13 4.1 Seller Failure..........................................................................................................13 4.2 Buyer Failure.........................................................................................................13 ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES.....................................................13 5.1 Events of Default...................................................................................................13 5.2 Declaration of an Early Termination Date and Calculation of Settlement Amounts.................................................................................................................15 5.3 Net Out of Settlement Amounts.............................................................................15 5.4 Notice of Payment of Termination Payment.........................................................15 5.5 Disputes With Respect to Termination Payment...................................................15 5.6 Closeout Setoffs.....................................................................................................16 5.7 Suspension of Performance....................................................................................16 ARTICLE SIX: PAYMENT AND NETTING....................................................................16 6.1 Billing Period.........................................................................................................16 6.2 Timeliness of Payment...........................................................................................17 6.3 Disputes and Adjustments of Invoices...................................................................17 6.4 Netting of Payments...............................................................................................17 6.5 Payment Obligation Absent Netting......................................................................17 6.6 Security..................................................................................................................18 6.7 Payment for Options..............................................................................................18 6.8 Transaction Netting................................................................................................18 I Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association ARTICLE SEVEN: LIMITATIONS..........................................................................................18 7.1 Limitation of Remedies, Liability and Damages...................................................18 ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS................................19 8.1 Party A Credit Protection.......................................................................................19 8.2 Party B Credit Protection.......................................................................................21 8.3 Grant of Security Interest/Remedies......................................................................22 ARTICLE NINE: GOVERNMENTAL CHARGES...............................................................23 9.1 Cooperation............................................................................................................23 9.2 Governmental Charges...........................................................................................23 ARTICLE TEN: MISCELLANEOUS.................................................................................23 10.1 Term of Master Agreement....................................................................................23 10.2 Representations and Warranties.............................................................................23 10.3 Title and Risk of Loss............................................................................................25 10.4 Indemnity...............................................................................................................25 10.5 Assignment............................................................................................................25 10.6 Governing Law......................................................................................................25 10.7 Notices...................................................................................................................26 10.8 General...................................................................................................................26 10.9 Audit......................................................................................................................26 10.10 Forward Contract...................................................................................................27 10.11 Confidentiality.......................................................................................................27 SCHEDULE M: GOVERNMENTAL ENTITY OR PUBLIC POWER SYSTEMS ..................28 SCHEDULE P: PRODUCTS AND RELATED DEFINITIONS.................................................32 EXHIBIT A: CONFIRMATION LETTER .................... ii Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric instiNte and National Energy Marketers Association ..39 MASTER POWER PURCHASE AND SALE AGREEMENT COVERSHEET This Master Power Purchase and Sale Agreement ("Master Agreement" ) is made as of the following date: ("Effective Date"). The Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Parry B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the "Agreement." The Parties to this Master Agreement are the following: Name (". All Notices: " or `Tarty A") Street: City: Zip: Attn: Contract Administration Phone: Facsimile: Duns: Federal Tax ID Number: Invoices: Atm: Phone: Facsimile: Scheduling: Attn: Phone: Facsimile: Payments: Attn: Phone: Facsimile: Wire Transfer: FINK: ABA: ACCT: Credit and Collections: Attn: Phone: Facsimile: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Phone: Facsimile: I Name ("Counterparty" or `Tarty B") All Notices: Street: City: Attn: Contract Administration Phone: Facsimile: Duns: Federal Tax ID Number: Invoices: Attn: Phone: _ Facsimile: Scheduling: Attn: Phone: _ Facsimile: Payments: Attn: Phone: Facsimile: Wire Transfer: BNK: ABA: ACCT: Credit and Collections: Attn: Phone: Facsimile: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Phone: Facsimile: Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff Tariff Dated Docket Number Parry B Tariff Tariff Dated Docket Number Article Two Transaction Terms and Conditions [] Optional provision in Section 2.4. If not checked, inapplicable. Article Four Remedies for Failure [] Accelerated Payment of Damages. If not checked, inapplicable. to Deliver or Receive Article Five Events of Default; Remedies Article 8 Credit and Collateral Requirements [] Cross Default for Party A: [] Party A: [] Other Entity: [] Cross Default for Party B: [] Party B: [] Other Entity: 5.6 Closeout Setoff Cross Default Amount $ Cross Default Amount $ Cross Default Amount $ Cross Default Amount $ [] Option A (Applicable if no other selection is made.) [] Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: [] Option C (No Setoff) 8.1 Party A Credit Protection: (a) Financial Information: [] Option A [] Option B Specify: [] Option C Specify: (b) Credit Assurances: [] Not Applicable [] Applicable (c) Collateral Threshold: L] Not Applicable [] Applicable 2 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association If applicable, complete the following: Party B Collateral Threshold: $ ; provided, however, that Party B's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party B has occurred and is continuing. Party B Independent Amount: $ Party B Rounding Amount: $ (d) Downgrade Event: [] Not Applicable [] Applicable If applicable, complete the following: [] It shall be a Downgrade Event for Party B if Party B's Credit Rating falls below from S&P or from Moody's or if Party B is not rated by either S&P or Moody's [] Other: (e) Guarantor for Party B Guarantee 8.2 Party B Credit Protection: (a) Financial Information: [] Option A [] Option B Specify: [] Option C Specify: (b) Credit Assurances: [] Not Applicable [] Applicable (c) Collateral Threshold: [] Not Applicable [] Applicable If applicable, complete the following: Party A Collateral Threshold: $ ; provided, however, that Party A's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party A has occurred and is continuing. Party A Independent Amount: $ Party A Rounding Amount: 3 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (d) Downgrade Event: [] Not Applicable [] Applicable If applicable, complete the following: [] It shall be a Downgrade Event for Party A if Party A's Credit Rating falls below from S&P or from Moody's or if Party A is not rated by either S&P or Moody's [] Other: Specify: (e) Guarantor for Party Guarantee Am, Article 10 Confidentiality [] Confidentiality Applicable If not checked, inapplicable. Schedule M [] Party A is a Governmental Entity or Public Power System [] Party B is a Governmental Entity or Public Power System [] Add Section 3.6. If not checked, inapplicable [] Add Section 8.6. If not checked, inapplicable Other Changes Specify, if any: Is Version 2.1 (modified 4/25/00) @COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association IN WITNESS WHEREOF, the Parties have caused this Master Agreement to be duly executed as of the date first above written. Party A Name By: Name: Title: Parry B Name M Name: Title: DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute ("EEPI) and National Energy Marketers Association ("NEM") member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting therefrom. By providing this Agreement EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected. 0 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association GENERAL TERMS AND CONDITIONS ARTICLE ONE: GENERAL DEFINITIONS 1.1 "Affiliate" means, with respect to any person, any other person (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such person. For this purpose, "control" means the direct or indirect ownership of fifty percent (50%) or more of the outstanding capital stock or other equity interests having ordinary voting power. 1.2 "Agreement" has the meaning set forth in the Cover Sheet. 1.3 "Bankrupt" means with respect to any entity, such entity (i) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it, (ii) makes an assignment or any general arrangement for the benefit of creditors, (iii) otherwise becomes bankrupt or insolvent (however evidenced), (iv) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (v) is generally unable to pay its debts as they fall due. 1.4 "Business Day" means any day except a Saturday, Sunday, or a Federal Reserve Bank holiday. A Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local time for the relevant Party's principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received. 1.5 "Buyer" means the Party to a Transaction that is obligated to purchase and receive, or cause to be received, the Product, as specified in the Transaction. 1.6 "Call Option" means an Option entitling, but not obligating, the Option Buyer to purchase and receive the Product from the Option Seller at a price equal to the Strike Price for the Delivery Period for which the Option may be exercised, all as specified in the Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to sell and deliver the Product for the Delivery Period for which the Option has been exercised. 1.7 "Claiming Party" has the meaning set forth in Section 3.3. 1.8 "Claims" means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys' fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed prior to or after the termination of this Agreement. 1.9 "Confirmation" has the meaning set forth in Section 2.3. version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric institute and National Energy Marketers Association 1.10 "Contract Price" means the price in $U.S. (unless otherwise provided for) to be paid by Buyer to Seller for the purchase of the Product, as specified in the Transaction. 1.11 "Costs" means, with respect to the Non -Defaulting Party, brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred by such Party either in terminating any arrangement pursuant to which it has hedged its obligations or entering into new arrangements which replace a Terminated Transaction; and all reasonable attorneys' fees and expenses incurred by the Non -Defaulting Party in connection with the termination of a Transaction. 1.12 "Credit Rating" means, with respect to any entity, the rating then assigned to such entity's unsecured, senior long-term debt obligations (not supported by third party credit enhancements) or if such entity does not have a rating for its senior unsecured long-term debt, then the rating then assigned to such entity as an issues rating by S&P, Moody's or any other rating agency agreed by the Parties as set forth in the Cover Sheet. 1.13 "Cross Default Amount" means the cross default amount, if any, set forth in the Cover Sheet for a Party. 1.14 "Defaulting Party" has the meaning set forth in Section 5.1. 1.15 "Delivery Period" means the period of delivery for a Transaction, as specified in the Transaction. 1.16 "Delivery Point" means the point at which the Product will be delivered and received, as specified in the Transaction. 1.17 "Downgrade Event" has the meaning set forth on the Cover Sheet. 1.18 "Early Termination Date" has the meaning set forth in Section 5.2. 1.19 "Effective Date" has the meaning set forth on the Cover Sheet. 1.20 "Equitable Defenses" means any bankruptcy, insolvency, reorganization and other laws affecting creditors' rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending. 1.21 "Event of Default" has the meaning set forth in Section 5.1. 1.22 "FERC" means the Federal Energy Regulatory Commission or any successor government agency. 1.23 "Force Majeure" means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer's markets; (ii) Buyer's inability economically 7 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association to use or resell the Product purchased hereunder; (iii) the loss or failure of Seller's supply; or (iv) Seller's ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the Transmission Provider's tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred. The applicability of Force Majeure to the Transaction is governed by the terms of the Products and Related Definitions contained in Schedule P. 1.24 "Gains" means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), resulting from the termination of a Terminated Transaction, determined in a commercially reasonable manner. 1.25 "Guarantor" means, with respect to a Party, the guarantor, if any, specified for such Party on the Cover Sheet. 1.26 "Interest Rate" means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under "Money Rates" on such day (or if not published on such day on the most recent preceding day on which published), plus two percent (2%) and (b) the maximum rate permitted by applicable law. 1.27 "Letter(s) of Credit" means one or more irrevocable, transferable standby letters of credit issued by a U.S. commercial bank or a foreign bank with a U.S. branch with such bank having a credit rating of at least A- from S&P or A3 from Moody's, in a form acceptable to the Party in whose favor the letter of credit is issued. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit. 1.28 "Losses" means, with respect to any Party, an amount equal to the present value of the economic loss to it, if any (exclusive of Costs), resulting from termination of a Terminated Transaction, determined in a commercially reasonable manner. 1.29 "Master Agreement" has the meaning set forth on the Cover Sheet. 1.30 "Moody's" means Moody's Investor Services, Inc. or its successor. 1.31 "NERC Business Day" means any day except a Saturday, Sunday or a holiday as defined by the North American Electric Reliability Council or any successor organization thereto. A NERC Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local time for the relevant Party's principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received. Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 1.32 "Non -Defaulting Party" has the meaning set forth in Section 5.2. 1.33 "Offsetting Transactions" mean any two or more outstanding Transactions, having the same or overlapping Delivery Period(s), Delivery Point and payment date, where under one or more of such Transactions, one Party is the Seller, and under the other such Transaction(s), the same Party is the Buyer. 1.34 "Option" means the right but not the obligation to purchase or sell a Product as specified in a Transaction. 1.35 "Option Buyer" means the Party specified in a Transaction as the purchaser of an option, as defined in Schedule P. 1.36 "Option Seller" means the Party specified in a Transaction as the seller of an option, as defined in Schedule P. 1.37 "Party A Collateral Threshold" means the collateral threshold, if any, set forth in the Cover Sheet for Party A. 1.38 "Party B Collateral Threshold" means the collateral threshold, if any, set forth in the Cover Sheet for Party B. 1.39 "Party A Independent Amount" means the amount, if any, set forth in the Cover Sheet for Party A. 1.40 "Party B Independent Amount" means the amount , if any, set forth in the Cover Sheet for Party B. 1.41 "Party A Rounding Amount" means the amount, if any, set forth in the Cover Sheet for Party A. 1.42 "Party B Rounding Amount" means the amount, if any, set forth in the Cover Sheet for Party B. 1.43 "Party A Tariff" means the tariff, if any, specified in the Cover Sheet for Party A. 1.44 "Party B Tariff" means the tariff, if any, specified in the Cover Sheet for Party B. 1.45 "Performance Assurance" means collateral in the form of either cash, Letter(s) of Credit, or other security acceptable to the Requesting Party. 1.46 "Potential Event of Default" means an event which, with notice or passage of time or both, would constitute an Event of Default. 1.47 "Product" means electric capacity, energy or other product(s) related thereto as specified in a Transaction by reference to a Product listed in Schedule P hereto or as otherwise specified by the Parties in the Transaction. W version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 1.48 "Put Option" means an Option entitling, but not obligating, the Option Buyer to sell and deliver the Product to the Option Seller at a price equal to the Strike Price for the Delivery Period for which the option may be exercised, all as specified in a Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to purchase and receive the Product. 1.49 "Quantity" means that quantity of the Product that Seller agrees to make available or sell and deliver, or cause to be delivered, to Buyer, and that Buyer agrees to purchase and receive, or cause to be received, from Seller as specified in the Transaction. 1.50 "Recording" has the meaning set forth in Section 2.4. 1.51 "Replacement Price" means the price at which Buyer, acting in a commercially reasonable manner, purchases at the Delivery Point a replacement for any Product specified in a Transaction but not delivered by Seller, plus (i) costs reasonably incurred by Buyer in purchasing such substitute Product and (ii) additional transmission charges, if any, reasonably incurred by Buyer to the Delivery Point, or at Buyer's option, the market price at the Delivery Point for such Product not delivered as determined by Buyer in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Buyer be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize Seller's liability. For the purposes of this definition, Buyer shall be considered to have purchased replacement Product to the extent Buyer shall have entered into one or more arrangements in a commercially reasonable manner whereby Buyer repurchases its obligation to sell and deliver the Product to another party at the Delivery Point. 1.52 "S&P" means the Standard & Poor's Rating Group (a division of McGraw-Hill, Inc.) or its successor. 1.53 "Sales Price" means the price at which Seller, acting in a commercially reasonable manner, resells at the Delivery Point any Product not received by Buyer, deducting from such proceeds any (i) costs reasonably incurred by Seller in reselling such Product and (ii) additional transmission charges, if any, reasonably incurred by Seller in delivering such Product to the third party purchasers, or at Seller's option, the market price at the Delivery Point for such Product not received as determined by Seller in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Seller be required to utilize or change its utilization of its owned or controlled assets, including contractual assets, or market positions to minimize Buyer's liability. For purposes of this definition, Seller shall be considered to have resold such Product to the extent Seller shall have entered into one or more arrangements in a commercially reasonable manner whereby Seller repurchases its obligation to purchase and receive the Product from another party at the Delivery Point. 1.54 "Schedule" or "Scheduling" means the actions of Seller, Buyer and/or their designated representatives, including each Party's Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity and type of Product to be delivered on any given day or days during the Delivery Period at a specified Delivery Point. 10 Version 2.1 (modified 4/25/00) @COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 1.55 "Seller" means the Party to a Transaction that is obligated to sell and deliver, or cause to be delivered, the Product, as specified in the Transaction. 1.56 "Settlement Amount" means, with respect to a Transaction and the Non - Defaulting Party, the Losses or Gains, and Costs, expressed in U.S. Dollars, which such party incurs as a result of the liquidation of a Terminated Transaction pursuant to Section 5.2. 1.57 "Strike Price" means the price to be paid for the purchase of the Product pursuant to an Option. 1.58 "Terminated Transaction" has the meaning set forth in Section 5.2. 1.59 "Termination Payment" has the meaning set forth in Section 5.3. 1.60 "Transaction" means a particular transaction agreed to by the Parties relating to the sale and purchase of a Product pursuant to this Master Agreement. 1.61 "Transmission Provider" means any entity or entities transmitting or transporting the Product on behalf of Seller or Buyer to or from the Delivery Point in a particular Transaction. ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS 2.1 Transactions. A Transaction shall be entered into upon agreement of the Parties orally or, if expressly required by either Party with respect to a particular Transaction, in writing, including an electronic means of communication. Each Party agrees not to contest, or assert any defense to, the validity or enforceability of the Transaction entered into in accordance with this Master Agreement (i) based on any law requiring agreements to be in writing or to be signed by the parties, or (ii) based on any lack of authority of the Party or any lack of authority of any employee of the Party to enter into a Transaction. 2.2 Governing Terms. Unless otherwise specifically agreed, each Transaction between the Parties shall be governed by this Master Agreement. This Master Agreement (including all exhibits, schedules and any written supplements hereto), , the Party A Tariff, if any, and the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmations accepted in accordance with Section 2.3) shall form a single integrated agreement between the Parties. Any inconsistency between any terms of this Master Agreement and any terms of the Transaction shall be resolved in favor of the terms of such Transaction. 2.3 Confirmation. Seller may confirm a Transaction by forwarding to Buyer by facsimile within three (3) Business Days after the Transaction is entered into a confirmation ("Confirmation") substantially in the form of Exhibit A. If Buyer objects to any term(s) of such Confirmation, Buyer shall notify Seller in writing of such objections within two (2) Business Days of Buyer's receipt thereof, failing which Buyer shall be deemed to have accepted the terms as sent. If Seller fails to send a Confirmation within three (3) Business Days after the Transaction is entered into, a Confirmation substantially in the form of Exhibit A, may be forwarded by Buyer to Seller. If Seller objects to any term(s) of such Confirmation, Seller shall notify Buyer of such objections within two (2) Business Days of Seller's receipt thereof, failing 11 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association which Seller shall be deemed to have accepted the terms as sent. If Seller and Buyer each send a Confirmation and neither Party objects to the other Party's Confirmation within two (2) Business Days of receipt, Seller's Confirmation shall be deemed to be accepted and shall be the controlling Confirmation, unless (i) Seller's Confirmation was sent more than three (3) Business Days after the Transaction was entered into and (ii) Buyer's Confirmation was sent prior to Seller's Confirmation, in which case Buyer's Confirmation shall be deemed to be accepted and shall be the controlling Confirmation. Failure by either Party to send or either Party to return an executed Confirmation or any objection by either Party shall not invalidate the Transaction agreed to by the Parties. 2.4 Additional Confirmation Terms. If the Parties have elected on the Cover Sheet to make this Section 2.4 applicable to this Master Agreement, when a Confirmation contains provisions, other than those provisions relating to the commercial terms of the Transaction (e.g., price or special transmission conditions), which modify or supplement the general terms and conditions of this Master Agreement (e.g., arbitration provisions or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 2.3 unless agreed to either orally or in writing by the Parties; provided that the foregoing shall not invalidate any Transaction agreed to by the Parties. 2.5 Recording. Unless a Party expressly objects to a Recording (defined below) at the beginning of a telephone conversation, each Party consents to the creation of a tape or electronic recording ("Recording") of all telephone conversations between the Parties to this Master Agreement, and that any such Recordings will be retained in confidence, secured from improper access, and may be submitted in evidence in any proceeding or action relating to this Agreement. Each Party waives any further notice of such monitoring or recording, and agrees to notify its officers and employees of such monitoring or recording and to obtain any necessary consent of such officers and employees. The Recording, and the terms and conditions described therein, if admissible, shall be the controlling evidence for the Parties' agreement with respect to a particular Transaction in the event a Confirmation is not fully executed (or deemed accepted) by both Parties. Upon full execution (or deemed acceptance) of a Confirmation, such Confirmation shall control in the event of any conflict with the terms of a Recording, or in the event of any conflict with the terms of this Master Agreement. ARTICLE THREE: OBLIGATIONS AND DELIVERIES 3.1 Seller's and Buyer's Obf atg ions. With respect to each Transaction, Seller shall sell and deliver, or cause to be delivered, and Buyer shall purchase and receive, or cause to be received, the Quantity of the Product at the Delivery Point, and Buyer shall pay Seller the Contract Price; provided, however, with respect to Options, the obligations set forth in the preceding sentence shall only arise if the Option Buyer exercises its Option in accordance with its terms. Seller shall be responsible for any costs or charges imposed on or associated with the Product or its delivery of the Product up to the Delivery Point. Buyer shall be responsible for any costs or charges imposed on or associated with the Product or its receipt at and from the Delivery Point. 3.2 Transmission and Scheduling. Seller shall arrange and be responsible for transmission service to the Delivery Point and shall Schedule or arrange for Scheduling services 12 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association with its Transmission Providers, as specified by the Parties in the Transaction, or in the absence thereof, in accordance with the practice of the Transmission Providers, to deliver the Product to the Delivery Point. Buyer shall arrange and be responsible for transmission service at and from the Delivery Point and shall Schedule or arrange for Scheduling services with its Transmission Providers to receive the Product at the Delivery Point. 3.3 Force Maieure. To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under the Transaction and such Party (the "Claiming Party") gives notice and details of the Force Majeure to the other Party as soon as practicable, then, unless the terms of the Product specify otherwise, the Claiming Party shall be excused from the performance of its obligations with respect to such Transaction (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non -Claiming Party shall not be required to perform or resume performance of its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure. ARTICLE FOUR: REMEDIES FOR FAILURE TO DELIVER/RECEIVE 4.1 Seller Failure. If Seller fails to schedule and/or deliver all or part of the Product pursuant to a Transaction, and such failure is not excused under the terms of the Product or by Buyer's failure to perform, then Seller shall pay Buyer, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if "Accelerated Payment of Damages" is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Contract Price from the Replacement Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount. 4.2 Buyer Failure. If Buyer fails to schedule and/or receive all or part of the Product pursuant to a Transaction and such failure is not excused under the terms of the Product or by Seller's failure to perform, then Buyer shall pay Seller, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if "Accelerated Payment of Damages" is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Sales Price from the Contract Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount. ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES 5.1 Events of Default. An "Event of Default" shall mean, with respect to a Party (a "Defaulting Party"), the occurrence of any of the following: (a) the failure to make, when due, any payment required pursuant to this Agreement if such failure is not remedied within three (3) Business Days after written notice; 13 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (b) any representation or warranty made by such Party herein is false or misleading in any material respect when made or when deemed made or repeated; (c) the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default, and except for such Party's obligations to deliver or receive the Product, the exclusive remedy for which is provided in Article Four) if such failure is not remedied within three (3) Business Days after written notice; (d) such Party becomes Bankrupt; (e) the failure of such Party to satisfy the creditworthiness/collateral requirements agreed to pursuant to Article Eight hereof, (f) such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party; (g) if the applicable cross default section in the Cover Sheet is indicated for such Party, the occurrence and continuation of (i) a default, event of default or other similar condition or event in respect of such Party or any other party specified in the Cover Sheet for such Party under one or more agreements or instruments, individually or collectively, relating to indebtedness for borrowed money in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet), which results in such indebtedness becoming, or becoming capable at such time of being declared, immediately due and payable or (ii) a default by such Party or any other party specified in the Cover Sheet for such Party in making on the due date therefor one or more payments, individually or collectively, in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet); (h) with respect to such Party's Guarantor, if any: (i) if any representation or warranty made by a Guarantor in connection with this Agreement is false or misleading in any material respect when made or when deemed made or repeated; (ii) the failure of a Guarantor to make any payment required or to perform any other material covenant or obligation in any guaranty made in connection with this Agreement and such failure shall not be remedied within three (3) Business Days after written notice; 14 Version 2.1 (modified 4/25/00) (COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (iii) a Guarantor becomes Bankrupt; (iv) the failure of a Guarantor's guaranty to be in full force and effect for purposes of this Agreement (other than in accordance with its terms) prior to the satisfaction of all obligations of such Party under each Transaction to which such guaranty shall relate without the written consent of the other Party; or (v) a Guarantor shall repudiate, disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of any guaranty. 5.2 Declaration of an Early Termination Date and Calculation of Settlement Amounts. If an Event of Default with respect to a Defaulting Party shall have occurred and be continuing, the other Party (the "Non -Defaulting Party") shall have the right (i) to designate a day, no earlier than the day such notice is effective and no later than 20 days after such notice is effective, as an early termination date ("Early Termination Date") to accelerate all amounts owing between the Parties and to liquidate and terminate all, but not less than all, Transactions (each referred to as a "Terminated Transaction") between the Parties, (ii) withhold any payments due to the Defaulting Party under this Agreement and (iii) suspend performance. The Non - Defaulting Party shall calculate, in a commercially reasonable manner, a Settlement Amount for each such Terminated Transaction as of the Early Termination Date (or, to the extent that in the reasonable opinion of the Non -Defaulting Party certain of such Terminated Transactions are commercially impracticable to liquidate and terminate or may not be liquidated and terminated under applicable law on the Early Termination Date, as soon thereafter as is reasonably practicable). 5.3 Net Out of Settlement Amounts. The Non -Defaulting Party shall aggregate all Settlement Amounts into a single amount by: netting out (a) all Settlement Amounts that are due to the Defaulting Party, plus, at the option of the Non -Defaulting Party, any cash or other form of security then available to the Non -Defaulting Party pursuant to Article Eight, plus any or all other amounts due to the Defaulting Party under this Agreement against (b) all Settlement Amounts that are due to the Non -Defaulting Party, plus any or all other amounts due to the Non - Defaulting Party under this Agreement, so that all such amounts shall be netted out to a single liquidated amount (the "Termination Payment") payable by one Party to the other. The Termination Payment shall be due to or due from the Non -Defaulting Party as appropriate. 5.4 Notice of Payment of Termination Payment. As soon as practicable after a liquidation, notice shall be given by the Non -Defaulting Party to the Defaulting Party of the amount of the Termination Payment and whether the Termination Payment is due to or due from the Non -Defaulting Party. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. The Termination Payment shall be made by the Party that owes it within two (2) Business Days after such notice is effective. 5.5 Disputes With Respect to Termination Payment If the Defaulting Party disputes the Non -Defaulting Party's calculation of the Termination Payment, in whole or in part, the Defaulting Party shall, within two (2) Business Days of receipt of Non -Defaulting Party's calculation of the Termination Payment, provide to the Non -Defaulting Party a detailed written 15 version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association explanation of the basis for such dispute; provided, however, that if the Termination Payment is due from the Defaulting Party, the Defaulting Party shall first transfer Performance Assurance to the Non -Defaulting Party in an amount equal to the Termination Payment. 5.6 Closeout Setoffs. Option A: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non -Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party to the Non -Defaulting Party under any other agreements, instruments or undertakings between the Defaulting Party and the Non -Defaulting Party and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise). Option B: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non -Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party or any of its Affiliates to the Non -Defaulting Party or any of its Affiliates under any other agreements, instruments or undertakings between the Defaulting Party or any of its Affiliates and the Non -Defaulting Party or any of its Affiliates and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise). Option C: Neither Option A nor B shall apply 5.7 Suspension of Performance. Notwithstanding any other provision of this Master Agreement, if (a) an Event of Default or (b) a Potential Event of Default shall have occurred and be continuing, the Non -Defaulting Party, upon written notice to the Defaulting Party, shall have the right (i) to suspend performance under any or all Transactions; provided, however, in no event shall any such suspension continue for longer than ten (10) NERC Business Days with respect to any single Transaction unless an early Termination Date shall have been declared and notice thereof pursuant to Section 5.2 given, and (ii) to the extent an Event of Default shall have occurred and be continuing to exercise any remedy available at law or in equity. ARTICLE SIX: PAYMENT AND NETTING 6.1 Billing Period. Unless otherwise specifically agreed upon by the Parties in a Transaction, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments and, if "Accelerated Payment of Damages" is specified by the Parties in the Cover Sheet, payments pursuant to Section 4.1 or 4.2 and Option premium payments pursuant to Section 6.7). As soon as practicable after the end of each month, 16 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association each Party will render to the other Party an invoice for the payment obligations, if any, incurred hereunder during the preceding month. 6.2 Timeliness of Payment. Unless otherwise agreed by the Parties in a Transaction, all invoices under this Master Agreement shall be due and payable in accordance with each Party's invoice instructions on or before the later of the twentieth (20th) day of each month, or tenth (10th) day after receipt of the invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Interest Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full. 6.3 Disputes and Adiustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Interest Rate from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 6.3 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance of a Transaction occurred, the right to payment for such performance is waived. 6.4 Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date pursuant to all Transactions through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Products during the monthly billing period under this Master Agreement, including any related damages calculated pursuant to Article Four (unless one of the Parties elects to accelerate payment of such amounts as permitted by Article Four), interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it. 6.5 Payment Obligation Absent Netting. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, including, but not limited to, any related damage amounts calculated pursuant to Article Four, interest, and payments or credits, that Party shall pay such sum in full when due. 17 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 6.6 Securi . Unless the Party benefiting from Performance Assurance or a guaranty notifies the other Party in writing, and except in connection with a liquidation and termination in accordance with Article Five, all amounts netted pursuant to this Article Six shall not take into account or include any Performance Assurance or guaranty which may be in effect to secure a Party's performance under this Agreement. 6.7 Payment for Options. The premium amount for the purchase of an Option shall be paid within two (2) Business Days of receipt of an invoice from the Option Seller. Upon exercise of an Option, payment for the Product underlying such Option shall be due in accordance with Section 6.1. 6.8 Transaction Netting. If the Parties enter into one or more Transactions, which in conjunction with one or more other outstanding Transactions, constitute Offsetting Transactions, then all such Offsetting Transactions may by agreement of the Parties, be netted into a single Transaction under which: (a) the Party obligated to deliver the greater amount of Energy will deliver the difference between the total amount it is obligated to deliver and the total amount to be delivered to it under the Offsetting Transactions, and (b) the Party owing the greater aggregate payment will pay the net difference owed between the Parties. Each single Transaction resulting under this Section shall be deemed part of the single, indivisible contractual arrangement between the parties, and once such resulting Transaction occurs, outstanding obligations under the Offsetting Transactions which are satisfied by such offset shall terminate. ARTICLE SEVEN: LIMITATIONS 7.1 Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR'S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, THE OBLIGOR'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR In Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS 8.1 Party A Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.1(a) is specified on the Cover Sheet, Section 8.1(a) Option C shall apply exclusively. If none of Sections 8.1(b), 8.1(c) or 8.1(d) are specified on the Cover Sheet, Section 8.1(b) shall apply exclusively. (a) Financial Information. Option A: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party B's annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of Party B's quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as Party B diligently pursues the preparation, certification and delivery of the statements. Option B: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements. Sheet. Option C: Party A may request from Party B the information specified in the Cover 19 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (b) Credit Assurances. If Party A has reasonable grounds to believe that Party B's creditworthiness or performance under this Agreement has become unsatisfactory, Party A will provide Party B with written notice requesting Performance Assurance in an amount determined by Party A in a commercially reasonable manner. Upon receipt of such notice Party B shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party A. In the event that Party B fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement. (c) Collateral Threshold. If at any time and from time to time during the term of this Agreement (and notwithstanding whether an Event of Default has occurred), the Termination Payment that would be owed to Party A plus Party B's Independent Amount, if any, exceeds the Party B Collateral Threshold, then Party A, on any Business Day, may request that Party B provide Performance Assurance in an amount equal to the amount by which the Termination Payment plus Party B's Independent Amount, if any, exceeds the Party B Collateral Threshold (rounding upwards for any fractional amount to the next Party B Rounding Amount) ("Party B Performance Assurance"), less any Party B Performance Assurance already posted with Party A. Such Party B Performance Assurance shall be delivered to Party A within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party B, at its sole cost, may request that such Party B Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party B's Independent Amount, if any, (rounding upwards for any fractional amount to the next Party B Rounding Amount). In the event that Party B fails to provide Party B Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement. For purposes of this Section 8.1(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party A as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party B to Party A, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions. (d) Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party B, then Party A may require Parry B to provide Performance Assurance in an amount determined by Party A in a commercially reasonable manner. In the event Party B shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement. (e) If specified on the Cover Sheet, Party B shall deliver to Party A, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party A. 20 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 8.2 Party B Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.2(a) is specified on the Cover Sheet, Section 8.2(a) Option C shall apply exclusively. If none of Sections 8.2(b), 8.2(c) or 8.2(d) are specified on the Cover Sheet, Section 8.2(b) shall apply exclusively. (a) Financial Information. Option A: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party A's annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of such Party's quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as such Party diligently pursues the preparation, certification and delivery of the statements. Option B: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements. Option C: Party B may request from Party A the information specified in the Cover Sheet. (b) Credit Assurances. If Party B has reasonable grounds to believe that Party A's creditworthiness or performance under this Agreement has become unsatisfactory, Party B will provide Party A with written notice requesting Performance Assurance in an amount determined by Party B in a commercially reasonable manner. Upon receipt of such notice Party A shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party B. In the event that Party A fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement. (c) Collateral Threshold. If at any time and from time to time during the term of this Agreement (and notwithstanding whether an Event of Default has occurred), the Termination Payment that would be owed to Party B plus Party A's Independent Amount, if any, exceeds the Party A Collateral Threshold, then Party B, on any Business Day, may request that Party A provide Performance Assurance in an amount equal to the amount by which the Termination Payment plus Party A's Independent Amount, if any, exceeds the Party A Collateral 21 Version 2.1 (modified 4125/00) 000PYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association Threshold (rounding upwards for any fractional amount to the next Party A Rounding Amount) ("Party A Performance Assurance"), less any Party A Performance Assurance already posted with Party B. Such Party A Performance Assurance shall be delivered to Party B within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party A, at its sole cost, may request that such Party A Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party A's Independent Amount, if any, (rounding upwards for any fractional amount to the next Party A Rounding Amount). In the event that Party A fails to provide Party A Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement. For purposes of this Section 8.2(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party B as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party A to Party B, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions. (d) Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party A, then Party B may require Party A to provide Performance Assurance in an amount determined by Party B in a commercially reasonable manner. In the event Party A shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement. (e) If specified on the Cover Sheet, Party A shall deliver to Party B, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party B. 8.3 Grant of Security Interest/Remedies. To secure its obligations under this Agreement and to the extent either or both Parties deliver Performance Assurance hereunder, each Party (a "Pledgor") hereby grants to the other Party (the "Secured Party") a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all cash collateral and cash equivalent collateral and any and all proceeds resulting therefrom or the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit of, such Secured Party, and each Party agrees to take such action as the other Party reasonably requires in order to perfect the Secured Party's first -priority security interest in, and lien on (and right of setoff against), such collateral and any and all proceeds resulting therefrom or from the liquidation thereof. Upon or any time after the occurrence or deemed occurrence and during the continuation of an Event of Default or an Early Termination Date, the Non -Defaulting Party may do any one or more of the following: (i) exercise any of the rights and remedies of a Secured Party with respect to all Performance Assurance, including any such rights and remedies under law then in effect; (ii) exercise its rights of setoff against any and all property of the Defaulting Party in the possession of the Non -Defaulting Party or its agent; (iii) draw on any outstanding 22 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association Letter of Credit issued for its benefit; and (iv) liquidate all Performance Assurance then held by or for the benefit of the Secured Party free from any claim or right of any nature whatsoever of the Defaulting Party, including any equity or right of purchase or redemption by the Defaulting Party. The Secured Party shall apply the proceeds of the collateral realized upon the exercise of any such rights or remedies to reduce the Pledgor's obligations under the Agreement (the Pledgor remaining liable for any amounts owing to the Secured Party after such application), subject to the Secured Party's obligation to return any surplus proceeds remaining after such obligations are satisfied in full. ARTICLE NINE: GOVERNMENTAL CHARGES 9.1 Cooperation. Each Party shall use reasonable efforts to implement the provisions of and to administer this Master Agreement in accordance with the intent of the parties to minimize all taxes , so long as neither Party is materially adversely affected by such efforts. 9.2 Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any government authority("Governmental Charges") on or with respect to the Product or a Transaction arising prior to the Delivery Point. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Product or a Transaction at and from the Delivery Point (other than ad valorem, franchise or income taxes which are related to the sale of the Product and are, therefore, the responsibility of the Seller). In the event Seller is required by law or regulation to remit or pay Governmental Charges which are Buyer's responsibility hereunder, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by law or regulation to remit or pay Governmental Charges which are Seller's responsibility hereunder, Buyer may deduct the amount of any such Governmental Charges from the sums due to Seller under Article 6 of this Agreement. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the law. ARTICLE TEN: MISCELLANEOUS 10.1 Term of Master Agreement. The term of this Master Agreement shall commence on the Effective Date and shall remain in effect until terminated by either Party upon (thirty) 30 days' prior written notice; provided, however, that such termination shall not affect or excuse the performance of either Party under any provision of this Master Agreement that by its terms survives any such termination and, provided further, that this Master Agreement and any other documents executed and delivered hereunder shall remain in effect with respect to the Transactions) entered into prior to the effective date of such termination until both Parties have fulfilled all of their obligations with respect to such Transaction(s), or such Transaction(s) that have been terminated under Section 5.2 of this Agreement. 10.2 Representations and Warranties. On the Effective Date and the date of entering into each Transaction, each Party represents and warrants to the other Party that: (i) it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation; 23 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (ii) it has all regulatory authorizations necessary for it to legally perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3); (iii) the execution, delivery and performance of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it; (iv) this Master Agreement, each Transaction (including any Confirmation accepted in accordance with Section 2.3), and each other document executed and delivered in accordance with this Master Agreement constitutes its legally valid and binding obligation enforceable against it in accordance with its terms; subject to any Equitable Defenses. (v) it is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming Bankrupt; (vi) there is not pending or, to its knowledge, threatened against it or any of its Affiliates any legal proceedings that could materially adversely affect its ability to perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3); (vii) no Event of Default or Potential Event of Default with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3); (viii) it is acting for its own account, has made its own independent decision to enter into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) and as to whether this Master Agreement and each such Transaction (including any Confirmation accepted in accordance with Section 2.3) is appropriate or proper for it based upon its own judgment, is not relying upon the advice or recommendations of the other Party in so doing, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions and risks of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3); (ix) it is a "forward contract merchant' within the meaning of the United States Bankruptcy Code; 24 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association (x) it has entered into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) in connection with the conduct of its business and it has the capacity or ability to make or take delivery of all Products referred to in the Transaction to which it is a Party; (xi) with respect to each Transaction (including any Confirmation accepted in accordance with Section 2.3) involving the purchase or sale of a Product or an Option, it is a producer, processor, commercial user or merchant handling the Product, and it is entering into such Transaction for purposes related to its business as such; and (xii) the material economic terms of each Transaction are subject to individual negotiation by the Parties. 10.3 Title and Risk of Loss. Title to and risk of loss related to the Product shall transfer from Seller to Buyer at the Delivery Point. Seller warrants that it will deliver to Buyer the Quantity of the Product free and clear of all liens, security interests, claims and encumbrances or any interest therein or thereto by any person arising prior to the Delivery Point. 10.4 Indemnity. Each Party shall indemnify, defend and hold harmless the other Party from and against any Claims arising from or out of any event, circumstance, act or incident first occurring or existing during the period when control and title to Product is vested in such Party as provided in Section 10.3. Each Party shall indemnify, defend and hold harmless the other Party against any Governmental Charges for which such Party is responsible under Article Nine. 10.5 Assienment. Neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, either Party may, without the consent of the other Party (and without relieving itself from liability hereunder), (i) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements, (ii) transfer or assign this Agreement to an affiliate of such Party which affiliate's creditworthiness is equal to or higher than that of such Party, or (iii) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of the assets whose creditworthiness is equal to or higher than that of such Party; provided, however, that in each such case, any such assignee shall agree in writing to be bound by the terms and conditions hereof and so long as the transferring Party delivers such tax and enforceability assurance as the non -transferring Party may reasonably request. 10.6 Governing Law. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT. 25 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 10.7 Notices. All notices, requests, statements or payments shall be made as specified in the Cover Sheet. Notices (other than scheduling requests) shall, unless otherwise specified herein, be in writing and may be delivered by hand delivery, United States mail, overnight courier service or facsimile. Notice by facsimile or hand delivery shall be effective at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise shall be effective at the close of business on the next Business Day. Notice by overnight United States mail or courier shall be effective on the next Business Day after it was sent. A Party may change its addresses by providing notice of same in accordance herewith. 10.8 General. This Master Agreement (including the exhibits, schedules and any written supplements hereto), the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmation accepted in accordance with Section 2.3) constitute the entire agreement between the Parties relating to the subject matter. Notwithstanding the foregoing, any collateral, credit support or margin agreement or similar arrangement between the Parties shall, upon designation by the Parties, be deemed part of this Agreement and shall be incorporated herein by reference. This Agreement shall be considered for all purposes as prepared through the joint efforts of the parties and shall not be construed against one party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof. Except to the extent herein provided for, no amendment or modification to this Master Agreement shall be enforceable unless reduced to writing and executed by both Parties. Each Party agrees if it seeks to amend any applicable wholesale power sales tariff during the term of this Agreement, such amendment will not in any way affect outstanding Transactions under this Agreement without the prior written consent of the other Party. Each Party further agrees that it will not assert, or defend itself, on the basis that any applicable tariff is inconsistent with this Agreement. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement). Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default. Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change (individually or collectively, such events referred to as "Regulatory Event") will not otherwise affect the remaining lawful obligations that arise under this Agreement; and provided, further, that if a Regulatory Event occurs, the Parties shall use their best efforts to reform this Agreement in order to give effect to the original intention of the Parties. The term "including" when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. All indemnity and audit rights shall survive the termination of this Agreement for twelve (12) months. This Agreement shall be binding on each Party's successors and permitted assigns. 10.9 Audit. Each Party has the right, at its sole expense and during normal working hours, to examine the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation made pursuant to this Master Agreement. If requested, a Party shall provide to the other Party statements evidencing the Quantity delivered at the Delivery Point. If any such examination reveals any inaccuracy in any statement, the necessary adjustments in such statement and the payments thereof will be made promptly and shall bear interest calculated at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or payment will be 26 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association made unless objection to the accuracy thereof was made prior to the lapse of twelve (12) months from the rendition thereof, and thereafter any objection shall be deemed waived. 10.10 Forward Contract. The Parties acknowledge and agree that all Transactions constitute "forward contracts" within the meaning of the United States Bankruptcy Code. 10.11 Confidentiality. If the Parties have elected on the Cover Sheet to make this Section 10.11 applicable to this Master Agreement, neither Party shall disclose the terms or conditions of a Transaction under this Master Agreement to a third party (other than the Party's employees, lenders, counsel, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential) except in order to comply with any applicable law, regulation, or any exchange, control area or independent system operator rule or in connection with any court or regulatory proceeding; provided, however, each Party shall, to the extent practicable, use reasonable efforts to prevent or limit the disclosure. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation. 27 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric institute and National Energy Marketers Association SCHEDULE M (THIS SCHEDULE IS INCLUDED IF THE APPROPRIATE BOX ON THE COVER SHEET IS MARKED INDICATING A PARTY IS A GOVERNMENTAL ENTITY OR PUBLIC POWER SYSTEM) A. The Parties agree to add the following definitions in Article One. "Act" means .1 "Governmental Entity or Public Power System" means a municipality, county, governmental board, public power authority, public utility district, joint action agency, or other similar political subdivision or public entity of the United States, one or more States or territories or any combination thereof. "Special Fund" means a fund or account of the Governmental Entity or Public Power System set aside and or pledged to satisfy the Public Power System's obligations hereunder out of which amounts shall be paid to satisfy all of the Public Power System's obligations under this Master Agreement for the entire Delivery Period. B. The following sentence shall be added to the end of the definition of "Force Majeure" in Article One. If the Claiming Party is a Governmental Entity or Public Power System, Force Majeure does not include any action taken by the Governmental Entity or Public Power System in its governmental capacity. C. The Parties agree to add the following representations and warranties to Section 10.2: Further and with respect to a Party that is a Governmental Entity or Public Power System, such Governmental Entity or Public Power System represents and warrants to the other Party continuing throughout the term of this Master Agreement, with respect to this Master Agreement and each Transaction, as follows: (i) all acts necessary to the valid execution, delivery and performance of this Master Agreement, including without limitation, competitive bidding, public notice, election, referendum, prior appropriation or other required procedures has or will be taken and performed as required under the Act and the Public Power System's ordinances, bylaws or other regulations, (ii) all persons making up the governing body of Governmental Entity or Public Power System are the duly elected or appointed incumbents in their positions and hold such I Cite the state enabling and other relevant statutes applicable to Governmental Entity or Public Power System. 28 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association positions in good standing in accordance with the Act and other applicable law, (iii) entry into and performance of this Master Agreement by Governmental Entity or Public Power System are for a proper public purpose within the meaning of the Act and all other relevant constitutional, organic or other governing documents and applicable law, (iv) the term of this Master Agreement does not extend beyond any applicable limitation imposed by the Act or other relevant constitutional, organic or other governing documents and applicable law, (v) the Public Power System's obligations to make payments hereunder are unsubordinated obligations and such payments are (a) operating and maintenance costs (or similar designation) which enjoy first priority of payment at all times under any and all bond ordinances or indentures to which it is a party, the Act and all other relevant constitutional, organic or other governing documents and applicable law or (b) otherwise not subject to any prior claim under any and all bond ordinances or indentures to which it is a party, the Act and all other relevant constitutional, organic or other governing documents and applicable law and are available without limitation or deduction to satisfy all Governmental Entity or Public Power System' obligations hereunder and under each Transaction or (c) are to be made solely from a Special Fund, (vi) entry into and performance of this Master Agreement and each Transaction by the Governmental Entity or Public Power System will not adversely affect the exclusion from gross income for federal income tax purposes of interest on any obligation of Governmental Entity or Public Power System otherwise entitled to such exclusion, and (vii) obligations to make payments hereunder do not constitute any kind of indebtedness of Governmental Entity or Public Power System or create any kind of lien on, or security interest in, any property or revenues of Governmental Entity or Public Power System which, in either case, is proscribed by any provision of the Act or any other relevant constitutional, organic or other governing documents and applicable law, any order or judgment of any court or other agency of government applicable to it or its assets, or any contractual restriction binding on or affecting it or any of its assets. D. The Parties agree to add the following sections to Article Three: Section 3.4 Public Power System's Deliveries. On the Effective Date and as a condition to the obligations of the other Party under this Agreement, Governmental Entity or Public Power System shall provide the other Party hereto (i) certified copies of all ordinances, resolutions, public notices and other documents evidencing the necessary authorizations with respect to the execution, delivery and performance by Governmental Entity or Public Power System of this Master Agreement and (ii) an opinion of counsel for Governmental Entity or Public Power System, in form and substance reasonably satisfactory to the Other Party, regarding the validity, binding effect and enforceability of this Master Agreement against Governmental Entity or Public Power System in 29 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association respect of the Act and all other relevant constitutional organic or other governing documents and applicable law. Section 3.5 No Immunity Claim. Governmental Entity or Public Power System warrants and covenants that with respect to its contractual obligations hereunder and performance thereof, it will not claim immunity on the grounds of sovereignty or similar grounds with respect to itself or its revenues or assets from (a) suit, (b) jurisdiction of court (including a court located outside the jurisdiction of its organization), (c) relief by way of injunction, order for specific performance or recovery of property, (d) attachment of assets, or (e) execution or enforcement of any judgment. E. If the appropriate box is checked on the Cover Sheet, as an alternative to selecting one of the options under Section 8.3, the Parties agree to add the following section to Article Three: Section 3.6 Governmental Entity or Public Power System Security. With respect to each Transaction, Governmental Entity or Public Power System shall either (i) have created and set aside a Special Fund or (ii) upon execution of this Master Agreement and prior to the commencement of each subsequent fiscal year of Governmental Entity or Public Power System during any Delivery Period, have obtained all necessary budgetary approvals and certifications for payment of all of its obligations under this Master Agreement for such fiscal year; any breach of this provision shall be deemed to have arisen during a fiscal period of Governmental Entity or Public Power System for which budgetary approval or certification of its obligations under this Master Agreement is in effect and, notwithstanding anything to the contrary in Article Four, an Early Termination Date shall automatically and without further notice occur hereunder as of such date wherein Governmental Entity or Public Power System shall be treated as the Defaulting Party. Governmental Entity or Public Power System shall have allocated to the Special Fund or its general funds a revenue base that is adequate to cover Public Power System's payment obligations hereunder throughout the entire Delivery Period. F. If the appropriate box is checked on the Cover Sheet, the Parties agree to add the following section to Article Eight: Section 8.4 Governmental Security. As security for payment and performance of Public Power System's obligations hereunder, Public Power System hereby pledges, sets over, assigns and grants to the other Party a security interest in all of Public Power System's right, title and interest in and to [specify collateral]. 30 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association G. The Parties agree to add the following sentence at the end of Section 10.6 - Governing Law: NOTWITHSTANDING THE FOREGOING, IN RESPECT OF THE APPLICABILITY OF THE ACT AS HEREIN PROVIDED, THE LAWS OF THE STATE OF 'SHALL APPLY. 2 Insert relevant state for Governmental Entity or Public Power System. 31 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association SCHEDULE P: PRODUCTS AND RELATED DEFINITIONS "Ancillary Services" means any of the services identified by a Transmission Provider in its transmission tariff as "ancillary services" including, but not limited to, regulation and frequency response, energy imbalance, operating reserve -spinning and operating reserve - supplemental, as may be specified in the Transaction. "Capacity" has the meaning specified in the Transaction. "Energy" means three-phase, 60 -cycle alternating current electric energy, expressed in megawatt hours. "Firm (LD)" means, with respect to a Transaction, that either Party shall be relieved of its obligations to sell and deliver or purchase and receive without liability only to the extent that, and for the period during which, such performance is prevented by Force Majeure. In the absence of Force Majeure, the Party to which performance is owed shall be entitled to receive from the Party which failed to deliver/receive an amount determined pursuant to Article Four. "Firm Transmission Contingent - Contract Path" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is interrupted or curtailed and (i) such Party has provided for firm transmission with the transmission provider(s) for the Product in the case of the Seller from the generation source to the Delivery Point or in the case of the Buyer from the Delivery Point to the ultimate sink, and (ii) such interruption or curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the applicable transmission provider's tariff. This contingency shall excuse performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of "Force Majeure" in Section 1.23 to the contrary. "Firm Transmission Contingent - Delivery Point" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission to the Delivery Point (in the case of Seller) or from the Delivery Point (in the case of Buyer) for such Transaction is interrupted or curtailed and (i) such Parry has provided for firm transmission with the transmission provider(s) for the Product, in the case of the Seller, to be delivered to the Delivery Point or, in the case of Buyer, to be received at the Delivery Point and (ii) such interruption or curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the applicable transmission provider's tariff. This transmission contingency excuses performance for the duration of the interruption or curtailment, notwithstanding the provisions of the definition of "Force Majeure" in Section 1.23 to the contrary. Interruptions or curtailments of transmission other than the transmission either immediately to or from the Delivery Point shall not excuse performance "Firm (No Force Majeure)" means, with respect to a Transaction, that if either Party fails to perform its obligation to sell and deliver or purchase and receive the Product, the Party to which performance is owed shall be entitled to receive from the Party which failed to perform an 32 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association amount determined pursuant to Article Four. Force Majeure shall not excuse performance of a Firm (No Force Majeure) Transaction. "Into (the "Receiving Transmission Provider"), Seller's Daily Choice" means that, in accordance with the provisions set forth below, (1) the Product shall be scheduled and delivered to an interconnection or interface ("Interface") either (a) on the Receiving Transmission Provider's transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which Interface, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area; and (2) Seller has the right on a daily prescheduled basis to designate the Interface where the Product shall be delivered. An "Into" Product shall be subject to the following provisions: 1. Prescheduling and Notification. Subject to the provisions of Section 6, not later than the prescheduling deadline of 11:00 a.m. CPT on the Business Day before the next delivery day or as otherwise agreed to by Buyer and Seller, Seller shall notify Buyer ("Seller's Notification") of Seller's immediate upstream counterparty and the Interface (the "Designated Interface") where Seller shall deliver the Product for the next delivery day, and Buyer shall notify Seller of Buyer's immediate downstream counterparty. 2. Availability of "Firm Transmission" to Buyer at Designated Interface; "Timely Request for Transmission," "ADI" and "Available Transmission." In determining availability to Buyer of next -day firm transmission ("Firm Transmission") from the Designated Interface, a "Timely Request for Transmission" shall mean a properly completed request for Firm Transmission made by Buyer in accordance with the controlling tariff procedures, which request shall be submitted to the Receiving Transmission Provider no later than 30 minutes after delivery of Seller's Notification, provided, however, if the Receiving Transmission Provider is not accepting requests for Firm Transmission at the time of Seller's Notification, then such request by Buyer shall be made within 30 minutes of the time when the Receiving Transmission Provider first opens thereafter for purposes of accepting requests for Firm Transmission. Pursuant to the terms hereof, delivery of the Product may under certain circumstances be redesignated to occur at an Interface other than the Designated Interface (any such alternate designated interface, an "ADI") either (a) on the Receiving Transmission Provider's transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which ADI, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area using either firm or non-firm transmission, as available on a day -ahead or hourly basis (individually or collectively referred to as "Available Transmission") within the Receiving Transmission Provider's transmission system. 3. Rights of Buyer and Seller Depending Upon Availability of/Timely Request for Firm Transmission. A. Timely Request for Firm Transmission made by Buyer, Accepted by the Receiving Transmission Provider and Purchased by Buy , If a Timely Request for Firm Transmission is made by Buyer and is accepted by the Receiving Transmission Provider 33 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association and Buyer purchases such Firm Transmission, then Seller shall deliver and Buyer shall receive the Product at the Designated Interface. i. If the Firm Transmission purchased by Buyer within the Receiving Transmission Provider's transmission system from the Designated Interface ceases to be available to Buyer for any reason, or if Seller is unable to deliver the Product at the Designated Interface for any reason except Buyer's non- performance, then at Seller's choice from among the following, Seller shall: (a) to the extent Firm Transmission is available to Buyer from an ADI on a day -ahead basis, require Buyer to purchase such Firm Transmission from such ADI, and schedule and deliver the affected portion of the Product to such ADI on the basis of Buyer's purchase of Firm Transmission, or (b) require Buyer to purchase non- firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer's purchase of non-firm transmission from the Designated Interface or an ADI designated by Seller, or (c) to the extent firm transmission is available on an hourly basis, require Buyer to purchase firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer's purchase of such hourly firm transmission from the Designated Interface or an ADI designated by Seller. ii. If the Available Transmission utilized by Buyer as required by Seller pursuant to Section 3A(i) ceases to be available to Buyer for any reason, then Seller shall again have those alternatives stated in Section 3A(i) in order to satisfy its obligations. iii. Seller's obligation to schedule and deliver the Product at an ADI is subject to Buyer's obligation referenced in Section 4B to cooperate reasonably therewith. If Buyer and Seller cannot complete the scheduling and/or delivery at an ADI, then Buyer shall be deemed to have satisfied its receipt obligations to Seller and Seller shall be deemed to have failed its delivery obligations to Buyer, and Seller shall be liable to Buyer for amounts determined pursuant to Article Four. iv. In each instance in which Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI pursuant to Sections 3A(i) or (ii), and Firm Transmission had been purchased by both Seller and Buyer into and within the Receiving Transmission Provider's transmission system as to the scheduled delivery which could not be completed as a result of the interruption or curtailment of such Firm Transmission, Buyer and Seller shall bear their respective transmission expenses and/or associated congestion charges incurred in connection with efforts to complete delivery by such alternative scheduling and delivery arrangements. In any instance except as set forth in the immediately preceding sentence, Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI under Sections 3A(i) or (ii), Seller shall be responsible for any additional transmission purchases and/or associated congestion charges incurred by Buyer in connection with such alternative scheduling arrangements. 34 version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association B. Timely Request for Firm Transmission Made by Buyer but Reiected by the Receiving Transmission Provider. If Buyer's Timely Request for Firm Transmission is rejected by the Receiving Transmission Provider because of unavailability of Firm Transmission from the Designated Interface, then Buyer shall notify Seller within 15 minutes after receipt of the Receiving Transmission Provider's notice of rejection ("Buyer's Rejection Notice"). If Buyer timely notifies Seller of such unavailability of Firm Transmission from the Designated Interface, then Seller shall be obligated either (1) to the extent Firm Transmission is available to Buyer from an ADI on a day -ahead basis, to require Buyer to purchase (at Buyer's own expense) such Firm Transmission from such ADI and schedule and deliver the Product to such ADI on the basis of Buyer's purchase of Firm Transmission, and thereafter the provisions in Section 3A shall apply, or (2) to require Buyer to purchase (at Buyer's own expense) non-firm transmission, and schedule and deliver the Product on the basis of Buyer's purchase of non-firm transmission from the Designated Interface or an ADI designated by the Seller, in which case Seller shall bear the risk of interruption or curtailment of the non-firm transmission; provided, however, that if the non-firm transmission is interrupted or curtailed or if Seller is unable to deliver the Product for any reason, Seller shall have the right to schedule and deliver the Product to another ADI in order to satisfy its delivery obligations, in which case Seller shall be responsible for any additional transmission purchases and/or associated congestion charges incurred by Buyer in connection with Seller's inability to deliver the Product as originally prescheduled. If Buyer fails to timely notify Seller of the unavailability of Firm Transmission, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface, and the provisions of Section 3D shall apply. C. Timely Request for Firm Transmission Made by Buyer, Accepted by the Receiving Transmission Provider and not Purchased by Buyer. If Buyer's Timely Request for Firm Transmission is accepted by the Receiving Transmission Provider but Buyer elects to purchase non-firm transmission rather than Firm Transmission to take delivery of the Product, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller's delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four. D. No Timely Request for Firm Transmission Made by Buyer, or Buyer Fails to Timely Send Buyer's Rejection Notice. If Buyer fails to make a Timely Request for Firm Transmission or Buyer fails to timely deliver Buyer's Rejection Notice, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller's delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four. 35 Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 4. Transmission A. Seller's Responsibilities. Seller shall be responsible for transmission required to deliver the Product to the Designated Interface or ADI, as the case may be. It is expressly agreed that Seller is not required to utilize Firm Transmission for its delivery obligations hereunder, and Seller shall bear the risk of utilizing non-firm transmission. If Seller's scheduled delivery to Buyer is interrupted as a result of Buyer's attempted transmission of the Product beyond the Receiving Transmission Provider's system border, then Seller will be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for damages pursuant to Article Four. B. Buyer's Responsibilities. Buyer shall be responsible for transmission required to receive and transmit the Product at and from the Designated Interface or ADI, as the case may be, and except as specifically provided in Section 3A and 3B, shall be responsible for any costs associated with transmission therefrom. If Seller is attempting to complete the designation of an ADI as a result of Seller's rights and obligations hereunder, Buyer shall co-operate reasonably with Seller in order to effect such alternate designation. 5. Force Majeure. An "Into" Product shall be subject to the "Force Majeure" provisions in Section 1.23. 6. Multiple Parties in Delivery Chain Involving a Designated Interface. Seller and Buyer recognize that there may be multiple parties involved in the delivery and receipt of the Product at the Designated Interface or ADI to the extent that (1) Seller may be purchasing the Product from a succession of other sellers ("Other Sellers"), the first of which Other Sellers shall be causing the Product to be generated from a source ("Source Seller") and/or (2) Buyer may be selling the Product to a succession of other buyers ("Other Buyers"), the last of which Other Buyers shall be using the Product to serve its energy needs ("Sink Buyer"). Seller and Buyer further recognize that in certain Transactions neither Seller nor Buyer may originate the decision as to either (a) the original identification of the Designated Interface or ADI (which designation may be made by the Source Seller) or (b) the Timely Request for Firm Transmission or the purchase of other Available Transmission (which request may be made by the Sink Buyer). Accordingly, Seller and Buyer agree as follows: A. If Seller is not the Source Seller, then Seller shall notify Buyer of the Designated Interface promptly after Seller is notified thereof by the Other Seller with whom Seller has a contractual relationship, but in no event may such designation of the Designated Interface be later than the prescheduling deadline pertaining to the Transaction between Buyer and Seller pursuant to Section 1. B. If Buyer is not the Sink Buyer, then Buyer shall notify the Other Buyer with whom Buyer has a contractual relationship of the Designated Interface promptly after Seller notifies Buyer thereof, with the intent being that the party bearing actual responsibility to secure transmission shall have up to 30 minutes after receipt of the Designated Interface to submit its Timely Request for Firm Transmission. 36 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association C. Seller and Buyer each agree that any other communications or actions required to be given or made in connection with this "Into Product" (including without limitation, information relating to an ADI) shall be made or taken promptly after receipt of the relevant information from the Other Sellers and Other Buyers, as the case may be. D. Seller and Buyer each agree that in certain Transactions time is of the essence and it may be desirable to provide necessary information to Other Sellers and Other Buyers in order to complete the scheduling and delivery of the Product. Accordingly, Seller and Buyer agree that each has the right, but not the obligation, to provide information at its own risk to Other Sellers and Other Buyers, as the case may be, in order to effect the prescheduling, scheduling and delivery of the Product "Native Load" means the demand imposed on an electric utility or an entity by the requirements of retail customers located within a franchised service territory that the electric utility or entity has statutory obligation to serve. "Non -Firm" means, with respect to a Transaction, that delivery or receipt of the Product may be interrupted for any reason or for no reason, without liability on the part of either Party. "System Firm" means that the Product will be supplied from the owned or controlled generation or pre-existing purchased power assets of the system specified in the Transaction (the "System") with non-firm transmission to and from the Delivery Point, unless a different Transmission Contingency is specified in a Transaction. Seller's failure to deliver shall be excused: (i) by an event or circumstance which prevents Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Seller; (ii) by Buyer's failure to perform; (iii) to the extent necessary to preserve the integrity of, or prevent or limit any instability on, the System; (iv) to the extent the System or the control area or reliability council within which the System operates declares an emergency condition, as determined in the system's, or the control area's, or reliability council's reasonable judgment; or (v) by the interruption or curtailment of transmission to the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Seller's performance. Buyer's failure to receive shall be excused (i) by Force Majeure; (ii) by Seller's failure to perform, or (iii) by the interruption or curtailment of transmission from the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Buyer's performance. In any of such events, neither party shall be liable to the other for any damages, including any amounts determined pursuant to Article Four. "Transmission Contingent" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is unavailable or interrupted or curtailed for any reason, at any time, anywhere from the Seller's proposed generating source to the Buyer's proposed ultimate sink, regardless of whether transmission, if any, that such Party is attempting to secure and/or has purchased for the Product is firm or non-firm. If the transmission (whether firm or non-firm) that Seller or Buyer is attempting to secure is from source to sink is unavailable, this contingency excuses performance for the entire Transaction. If the transmission (whether firm or non-firm) that Seller 37 Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association or Buyer has secured from source to sink is interrupted or curtailed for any reason, this contingency excuses performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of "Force Majeure" in Article 1.23 to the contrary. "Unit Firm' means, with respect to a Transaction, that the Product subject to the Transaction is intended to be supplied from a generation asset or assets specified in the Transaction. Seller's failure to deliver under a "Unit Firm" Transaction shall be excused: (i) if the specified generation asset(s) are unavailable as a result of a Forced Outage (as defined in the NERC Generating Unit Availability Data System (GADS) Forced Outage reporting guidelines) or (ii) by an event or circumstance that affects the specified generation asset(s) so as to prevent Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, and which is not within the reasonable control of, or the result of the negligence of, the Seller or (iii) by Buyer's failure to perform. In any of such events, Seller shall not be liable to Buyer for any damages, including any amounts determined pursuant to Article Four. W., Version 2.1 (modified 4/25/00) MOPYRIGnT 2000 by the Edison Electric Institute and National Energy Marketers Association EXHIBIT A MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER This confirmation letter shall confirm the Transaction agreed to on between ("Party A") and ("Party B") regarding the sale/purchase of the Product under the terms and conditions as follows: Seller: Buyer: _ Product: Into Firm (LD) Firm (No Force Majeure) System Firm (Specify System: Unit Firm (Specify Unit(s): Other Seller's Daily Choice [] Transmission Contingency (If not marked, no transmission contingency) [] FT -Contract Path Contingency [] Seller [] Buyer [] FT -Delivery Point Contingency [] Seller [] Buyer [] Transmission Contingent (] Seller [] Buyer [] Other transmission contingency (Specify: Contract Quantity: Delivery Point: Contract Price: Energy Price: Other Charges: 39 Version 2.1 (modified 4/25/00) @COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association Confirmation Letter Page 2 Delivery Period: Special Conditions: Scheduling: Option Buyer: _ Option Seller: Type of Option: Strike Price: Premium: Exercise Period: This confirmation letter is being provided pursuant to and in accordance with the Master Power Purchase and Sale Agreement dated (the "Master Agreement") between Party A and Party B, and constitutes part of and is subject to the terms and provisions of such Master Agreement. Terms used but not defined herein shall have the meanings ascribed to them in the Master Agreement. [Party Al Name: Title: Phone No: Fax: [Party B] Name: Title: Phone No: Fax: ,ll Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association Draft 11/5/09 MASTER POWER PURCHASE AND SALE AGREEMENT Attachment 'C' COVER SHEET This Master Power Purchase and Sale Agreement ("Master Agreement") is made as of the following date: 2010 ("Effective Date"). The Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the "Agreement." The Parties to this Master Agreement are the following: Name (" " or "Party A") All Notices: Street: City: Zip: Attn: Contract Administration Phone: Facsimile: Duns: Federal Tax ID Number: Invoices: Attn: Phone: Facsimile: Scheduling: Attn: Phone: Facsimile: Payments: Attn: Phone: Facsimile: Wire Transfer: BNK: ABA: ACCT: Name ("Marin Energy Authority" or "Party B") All Notices: Street: [3501 Civic Center Drive, Room 3081 City: [San Rafael, CA] Zip: [94903] Attn: Contract Administration Phone: Facsimile: Duns: Federal Tax ID Number: Invoices: Attn: Phone: Facsimile: Scheduling: Attn: Phone: _ Facsimile: Payments: Attn: Phone: _ Facsimile: Wire Transfer: BNK: ABA: ACCT: Version 2.1 (modified 4/25/00) ®COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 84832-0838-7332 Credit and Collections: Attn: Phone: Facsimile: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Phone: Facsimile: #4832-0838-7332 Draft 11/5/09 Credit and Collections: Attn: Phone: Facsimile: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Phone: Facsimile: Version 2.1 (modified 4/25/00) ©COPYRIGI IT 2000 by the Edison Electric Institute and National Energy Marketers Association Draft 11/5/09 The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff Tariff Dated Docket Number Party B Tariff Tariff Article Two Transaction Terms and Conditions Article Four Remedies for Failure to Deliver or Receive Article Five Events of Default; Remedies Article 8 Credit and Collateral Requirements Docket Number 0 Optional provision in Section 2.4. If not checked, inapplicable. El Accelerated Payment of Damages. If not checked, inapplicable. 0 Cross Default for Party A: El Party A ❑ Other Entity: ❑O Cross Default for Party B: ❑ Other Entity: 5.6 Closeout Setoff Cross Default Amount US$50,000,000 Cross Default Amount Cross Default Amount US$500,000 Cross Default Amount $ 0 Option A (Applicable if no other selection is made.) Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows:_ ❑ Option C (No Setoff) 8.1 Party A Credit Protection: (a) Financial Information: 0 Option A Version 2.1 (modified 4/25/00) ®COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 44832-0838-7332 Draft 11/5/09 ❑ Option B Specify: ❑ Option C Specify: (b) Credit Assurances: El Not Applicable ❑ Applicable (c) Collateral Threshold: O Not Applicable ❑ Applicable If applicable, complete the following: Parry B Collateral Threshold: $ ; provided, however, that Party B's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party B has occurred and is continuing. Party B Independent Amount: $ Party B Rounding Amount: $ (d) Downgrade Event: El Not Applicable ❑ Applicable If applicable, complete the following: ❑ It shall be a Downgrade Event for Party B if Party B's Credit Rating falls below from S&P or from Moody's or if Party B is not rated by either S&P or Moody's ❑ Other: (e) Guarantor for Party Guarantee 8.2 Party B Credit Protection: (a) Financial Information: !] Option A ❑ Option B Specify: Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 ❑ Option C Specify: (b) Credit Assurances: O Not Applicable ❑ Applicable (c) Collateral Threshold: El Not Applicable ❑ Applicable If applicable, complete the following: Party A Collateral Threshold: $ ; provided, however, that Party A's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party A has occurred and is continuing. Parry A Independent Amount: $ Party A Rounding Amount: $ Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 (d) Downgrade Event: ❑ Not Applicable 0 Applicable If applicable, complete the following: M It shall be a Downgrade Event for Party A if Party A's Credit Ratings from both S&P and Moody's fall below BBB and Baal, respectively, or if Party A is not rated by either S&P or Moody's. ❑ Other: Specify: (e) Guarantor for Party A: Guarantee Amount: Article 10 Confidentiality 0 Confidentiality If not checked, inapplicable. Applicable Schedule M ❑ Party A is a Governmental Entity or Public Power System 0 Party B is a Governmental Entity or Public Power System O Add Section 3.6. If not checked, inapplicable El Add Section 8. If not checked, inapplicable. Collateral description as follows: Parry B shall direct Pacific Gas & Electric ("PG&E") to deposit into a lockbox account, in favor of Party A, all of the proceeds of all of the customer account receipts (net of the amounts to be paid to PG&E) received by Party B from the sale of the Product to its customers. Party A shall receive, in accordance with an account control agreement, payments for its invoice for the previous calendar month and after Party A's invoice is paid, the amounts remaining in such lockbox shall be immediately released to Party B on the 25th of each calendar month. Party A acknowledges that revenues from customer account receipts may be subject to a lien securing secured loan facilities for Party B provided that Party A, Party B and the lender(s) of such secured loan facilities shall have agreed to an intercreditor agreement acceptable to Party A in Version 2.1 (modified 4/25/00) OCOPY RIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 its reasonable discretion to the extent that Party A's lien on the amounts in the lockbox is at least pari passu with the lien of Party B's lender(s). The Parties agree that the lockbox account shall be in the name of Party B, and any interest earned thereon shall accrue in favor of Party B. Other Changes 1) In Section 1.1, add the following sentence at the end of the definition of "Affiliate": " The Parties hereby agree and acknowledge that the members of Party B shall not constitute or otherwise be deemed an "Affiliate" for the purposes of this Master Agreement or any Confirmation executed in connection therewith." 2) In Section 1.27 delete the word "transferable" in the first line and insert the following after the last sentence: "The value of the Letter of Credit shall be its principal amount (the "Value"), provided that if the Letter of Credit expires within thirty days after the date its Value is being determined, its Value shall be zero. If a Party has delivered more than one form of Performance Assurance to the Secured Party, when a return of Performance Assurance is to be made, the Secured Party may elect which form to transfer." The issuer of any Letter of Credit shall be rated, at all times when such Letter of Credit is outstanding, no less than A by S&P and A by Moody's. 3) Section 1.50 (Recording) is hereby deleted in its entirety. 4) In Section 2. 1, delete "orally or, if expressly required by either Party with respect to a particular Transaction," in the 2nd line. 5) In Section 2.1, the last sentence is deleted in its entirety and replaced with the following: "Each Party agrees not to contest, or assert any defense to, the validity or enforceability of the Transaction entered into in accordance with this Master Agreement based on any lack of authority of the Party or any lack of authority of any employee of the Party to enter into a Transaction; provided, however, the Party A acknowledges that no employee may amend or otherwise materially modify this Master Agreement or Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 Confirmation without the approval of the board of Party B, and that the only employees with authority to act on behalf of Party B shall be limited based on the certified incumbency delivered to Party A pursuant to Section 10.15." 6) In Section 2.4, delete "either orally or" after "agreed to" in the 7th line. 7) Section 2.5 is hereby deleted in its entirety. 8) In Section 5.1 (a) change "three (3) Business Days" to "five (5) Business Days". 9) In Section 5.1(d) add the following after `Bankrupt': ",provided, however, if the presentation of an involuntary petition for the winding -up or liquidation of a party (an "Involuntary Proceeding") is commenced, such Involuntary Proceeding shall be not be a Default in respect of that party unless the Involuntary Proceeding has not been withdrawn, dismissed, discharged, stayed or restrained within 60 days of its commencement and in such event the other parry shall be entitled to exercise its rights and remedies under this Agreement in respect thereof;" 10) In Section 5.1(g) add the following at the end of Section 5.1(g): "provided, however, that no default or event of default shall be deemed to have occurred under this Section 5.1(g) to the extent that any applicable cure period or grace period is available;" 11) 5.4 Notice of Payment of Termination Payment. Add the following at the end: "The Termination Payment shall bear interest at the Interest Rate from the date upon which notice is effective until paid. Notwithstanding any provision to the contrary contained in this Agreement, the Non -Defaulting Party shall not be required to pay to the Defaulting Parry any amount under Article 5 until the Non -Defaulting Parry receives confirmation satisfactory to it in its reasonable discretion that all other obligations of any kind whatsoever of the Defaulting Parry to make any payments to the Non - Defaulting Party or any of its Affiliates under this Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 54832-0838-7332 Draft 11/5/09 Agreement or otherwise which are due and payable as of the Early Termination Date (including for these purposes amounts payable pursuant to Excluded Transactions) have been fully and finally performed and that the Defaulting Party has returned any Performance Assurance of the Non -Defaulting Party's that is held simultaneously or before the Non Defaulting Party makes any Termination Payment hereunder." 12) In Section 6:3, lines 3, 16 & 18, change twelve (12) months to twenty-four (24) months. 13) In Sections 8.1(b) and 8.2 (b) change "three (3) Business Days" to "five (5) Business Days". 14)In Sections 8.1(d) and 8.2(d) on line 5, change "three (3) Business Days" to "five (5) Business Days". 15) The following new section 8.2(f) shall be added to Section 8.2: "Upon the occurrence of an Event of Default by Party A under the Master Agreement, Party A shall reimburse Party B for (i) the costs associated with the posting and payment of the CCA Bond which is posted by Party B and (ii) any actual reentry fees assessed by PG&E in connection with such Event of Default by Party A regardless of the amount of the security posted. The term "CCA Bond" means the bond required to be posted, in form and substance satisfactory to Party B in its sole discretion, pursuant to the Settlement Agreement in Rulemaking R.03-10-003 (Phase 3 — Community Choice Aggregation Bond Proceeding). The CCA Bond [shall be/has been] posted [no later than [ , 20_] and Party B shall advise Parry A of the amount of such CCA Bond promptly after an Event of Default." 16) In Section 10.1, the phrase "by either Party upon thirty (30) days' prior written notice" shall be deleted and replaced by "upon mutual agreement of the Parties". 17) Section 10.2(ix) shall be deleted in its entirety and replaced with the following: "Each party acknowledges and agrees that (i) certain transaction(s) hereunder constitute a "forward contract" providing a "contractual right" within the meaning of such Version 2.1 (modified 4/25/00) ®COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 terms under Title 11 of the United States Code, as amended (the "Bankruptcy Code"); (ii) it is a "forward contract merchant" within the meaning of the Bankruptcy Code with respect to any transaction that constitutes a "forward contract," (iii) all payments made or to be made by one party to the other party pursuant to this contract constitute a "settlement payment" within the meaning of the Bankruptcy Code; (iv) all transfers of adequate assurance, prepayment or similar performance assurance by one party to the other party under this contract constitute a "margin payment" within the meaning of the Bankruptcy Codes; (v) each party shall have the "contractual right" to terminate, liquidate, accelerate, or offset the transaction as a "master netting agreement participant" within the meaning of the Bankruptcy Code; (vi) Electricity delivered hereunder constitutes a "good" under Section 503(b)(9) of the U.S. Bankruptcy Code; and (vii) the parties are entities entitled to the rights under, and protections afforded by, Sections 362, 546, 553, 556, 560, 561 and 562 of the Bankruptcy Code." 18) In Section 10.5 change "transfer, sell, pledge, encumber or assign" to "pledge, encumber or collaterally assign". 19) In Section 10.6 change "State of New York" to "State of California" and add the following after the last line: "EACH PARTY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE FEDERAL COURTS LOCATED IN SAN FRANCISCO, CALIFORNIA, FOR ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY TRANSACTION, AND EXPRESSLY WAIVES ANY OBJECTION IT MAY HAVE TO SUCH JURISDICTION OR THE CONVENIENCE OF SUCH FORUM." 20) Section 10.8 General. Add at the end of the second to last sentence: "and the rights of either Party pursuant to (i) Article 5, (ii) Section 7. 1, (iii) Section 10.11 (iv) Waiver of Jury Trial provisions, if applicable, (v) Arbitration provisions, if applicable, (vi) the obligation of either Party to make payments hereunder, (vii) Section 10.6 and (viii) Section 10.13 shall also survive the termination of the Agreement or any Transaction." Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 44832-0838-7332 Draft 11/5/09 21)In section 10.9 and insert the words "copies of after the word "examine". In line 9, change twelve (12) months to twenty-four (24) months. 22) Section 10.10 Bankruptev Issues. Delete Section 10.10 in its entirety and replace with the following: "The Parties intend that (i) all Transactions constitute a "forward contract" within the meaning of the United States Bankruptcy Code (the "Bankruptcy Code") or a "swap agreement" with in the meaning of the Bankruptcy Code; (ii) all payments made or to be made by one Party to the other Party pursuant to this Agreement constitute "settlement payments" within the meaning of the Bankruptcy Code; (iii) all transfers of Performance Assurance by one Party to the other Party under this Agreement constitute "margin payments" within the meaning of the Bankruptcy Code; and (iv) this Agreement constitutes a "master netting agreement" within the meaning of the Bankruptcy Code." 23) The following sentence shall be added at the end of Section 10.11: "Party A and Party B acknowledge and agree that the Master Agreement and any Confirmations executed in connection therewith are subject to the California Public Records Act (Government Code Section 6250 et seq.)." 24) The following Mobile -Sierra clause shall be added as Section 10.12: 10.12 Standard of Review/Modifications. (a) Absent the prior mutual written agreement of all parties to the contrary, the standard of review for any proposed changes to the rates, terms, and/or conditions of service of this Agreement or any Transaction entered into thereunder, whether proposed by a Party, a non-party or FERC acting sua sponte, shall be the "public interest" standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956). Version 2.1 (modified 4/25/00) OCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association 44832-0838-7332 Draft 11/5/09 (b) In addition, and notwithstanding the foregoing subsection (a), to the fullest extent permitted by applicable law, each Party, for itself and its successors and assigns, hereby expressly and irrevocably waives any rights it can or may have, now or in the future, whether under §§ 205 and/or 206 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any section of this Agreement specifying the rate, charge, classification, or other term or condition agreed to by the Parties, it being the express intent of the Parties that, to the fullest extent permitted by applicable law, neither Party shall unilaterally seek to obtain from FERC any relief changing the rate, charge, classification, or other term or condition of this Agreement, notwithstanding any subsequent changes in applicable law or market conditions that may occur. In the event it were to be determined that applicable law precludes the Parties from waiving their rights to seek changes from FERC to their market-based power sales contracts (including entering into covenants not to do so) then this subsection (b) shall not apply, provided that, consistent with the foregoing subsection (a), neither Party shall seek any such changes except solely under the "public interest" application of the "just and reasonable" standard of review and otherwise as set forth in the foregoing section (a). 25) The following new Section shall be added as Section 10.13: Party A hereby acknowledges and agrees that Party B is organized as a Joint Powers Authority in accordance with the Joint Powers Act of the State of California (Government Code Section 6500 et seq.) pursuant to a Joint Powers Agreement dated December 19, 2008 (the "Joint Power Agreement") and is a public entity separate from its members. Party B shall solely be responsible for all debts, obligations and liabilities accruing and arising out of this Agreement and Seller agrees that it shall have Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 no rights and shall not make any claim, take any actions or assert any remedies against any of Party B's members in connection with this Agreement or any of the Transactions. 26) The following new Section shall be added as Section 10.14: No Immunity Claim. Party B warrants and covenants that with respect to its contractual obligations hereunder and performance thereof, it will not claim immunity on the grounds of sovereignty or similar grounds with respect to itself or its revenues or assets from (a) suit, (b) jurisdiction of court (including a court located outside the jurisdiction of its organization), (c) relief by way of injunction, order for specific performance or recovery of property, (d) attachment of assets, or (e) execution or enforcement of any judgment. 27) The Parties agree to add the following representations and warranties to Section 10.2: Party B represents and warrants to Party A continuing throughout the term of this Master Agreement, with respect to this Master Agreement and each Transaction, as follows: (i) all acts necessary to the valid execution, delivery and performance of this Master Agreement, including without limitation, competitive bidding, public notice, election, referendum, prior appropriation or other required procedures has or will be taken and performed as required under the Joint Power Agreement and all applicable laws, ordinances, or other applicable regulations, (ii) all persons making up the governing body of Party B are the duly elected or appointed incumbents in their positions and hold such positions in good standing in accordance with the Joint Power Agreement and other applicable laws, (iii) the term of this Master Agreement does not extend beyond any applicable limitation imposed by the Joint Power Agreement or other relevant constitutional, organic or other governing documents and applicable law, (iv) Party B's obligations to make payments hereunder are, except as otherwise specifically set forth herein or in the account control agreement or any other agreement documenting the security of Party B to Party A, unsubordinated obligations which enjoy Version 2.1 (modified 4/25/00) CCOPYAIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 first priority of payment at all times under any and all bond ordinances or indentures to which it is a party, the Joint Power Agreement and all other relevant constitutional, organic or other governing documents and applicable law or (b) otherwise not subject to any prior claim under any and all bond ordinances or indentures to which it is a party, the Joint Power Agreement and all other relevant constitutional, organic or other governing documents and applicable law and are available without limitation or deduction to satisfy all of Party B's obligations hereunder and under each Transaction, and (v) obligations to make payments hereunder do not constitute any kind of indebtedness of Party B or create any kind of lien on, or security interest in, any property or revenues of Party B which, in either case, is proscribed by any provision of the Joint Power Agreement or any other relevant constitutional, organic or other governing documents and applicable law, any order or judgment of any court or other agency of government applicable to it or its assets, or any contractual restriction binding on or affecting it or any of its assets. 28) The Parties agree to add the following representations and warranties to Section 10.2: Parry A represents, warrants and covenants to Party B continuing throughout the term of this Master Agreement, with respect to this Master Agreement and each Transaction, as follows; (i) no new facilities are required to be constructed in order for Seller to meet its supply obligation under this Agreement, and (ii) Seller shall not construct any new facilities to meet its supply obligation hereunder unless such new facility has satisfied all Applicable Law, including the California Environmental Quality Act ("CEQA") and any other applicable California environmental statutes relating to the construction and operation of such facilities. The foregoing representation shall not limit Party A's ability to use newly built facilities to supply the Product hereunder provided such facilities have satisfied all Applicable Law, Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 including CEQA and any other applicable California environmental statutes relating to the construction and operation thereof. Party A further agrees to waive any claims against Party B for failure to perform Party B's obligations under this Master Agreement or under any Confirmation to the extent that such failure is a result of Party A's violation or breach of the foregoing representations, warranties and covenants or as a result of litigation against Party B as a result of Party A's violation or breach of the foregoing representations, warranties and covenants. 29) The following sentence shall be added at the end of Section 10.9: Party A agrees to cooperate with Party B's audits in connection with this Master Agreement and the Confirmation, which shall commence on the first Business Day of January and June of each year. To the extent that an audit reveals that Energy Party A sold to Party B was incorrectly classified by Party A as Eligible Renewable Energy or Renewable Energy, Party A (i) shall pay for all audit costs incurred by Party B and (ii) shall, at Party A's cost, deliver to Party B replacement Eligible Renewable Energy or Renewable Energy in a quantity equal to the incorrectly classified Energy. 30) The following shall be added as a new Section 10.15: Parry B's Deliveries. On the Effective Date and as a condition to the obligations of Party A under this Agreement, Party B shall provide to Party A (i) certified copies of the Joint Powers Agreement and such relevant ordinances, resolutions, public notices and other public documents issued by Party B evidencing the necessary authorizations with respect to the execution, delivery and performance by Party B of this Master Agreement, (ii) a certified incumbency setting forth the name and signatures of employees of Party B with authority to act on behalf of Party B, subject to the limitations set forth in Section 2.1 and (iii) opinions of legal counsel for Party B, in form and substance reasonably satisfactory to Party A, with appropriate qualifications, assumptions and limitations, regarding such the following matters: (A) Party B is a validly existing community choice aggregation ("CCA"), (B) Party B has the power and authority to execute, deliver and perform the Master Agreement and the Version 2.1 (modified 4/25/00) CCOPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 proposed Confirmation, (C) the execution, delivery and performance by Party B of the Master Agreement and the proposed Confirmation does not contravene: (x) applicable law, or (y) the Joint Powers Agreement of Party B, and (D) the Master Agreement has been executed and delivered and is enforceable against Party B in accordance with its terms. 31)The following shall be added as a new Section 10.16: Party A's Deliveries. On the Effective Date and as a condition to the obligations of Party B under this Agreement, Party A shall provide to Party B certified copies of its certificate of formation, good standing certificate, resolutions, incumbencies, its FERC authorization under Section [2051 of the Federal Power Act and such other documents reasonably requested by Party B evidencing the necessary authorizations with respect to the execution, delivery and performance by Party A of this Master Agreement and any Confirmations executed in connection therewith. 32) The following shall be added as a new Section 10.18: The New Two -Third Vote Requirement For Local Public Electricity Providers Initiative. The Parties acknowledge the pendency of the initiative entitled "The New Two - Thirds Vote Requirement For Public Electricity Providers" (the "NTVR Initiative"). The foregoing acknowledgement is for informational purposes only and shall not allocate any risk to either Party regarding the validity or enforceability of the Master Agreement or the proposed Confirmation. Each of the Parties hereby agree and acknowledge that the other Party makes no representations and warranties with respect to the potential impact of the NTVR Initiative on this Agreement. Each Party agrees to pay for its own costs and expenses associated with any actions or suits arising from the NTVR Initiative. Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 IN WITNESS WHEREOF, the Parties have caused this Master Agreement to be duly executed as of the date first above written. Party A By: Name: Title: Party B Marin Energy Authority Name: Title: DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute ("EEI") and National Energy Marketers Association ("NEM") member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting therefrom. By providing this Agreement EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected. Version 2.1 (modified 4/25/00) ©COPYRIGHT 2000 by the Edison Electric Institute and National Energy Marketers Association #4832-0838-7332 Draft 11/5/09 CONFIRMATION Reference: Master Power Purchase and Sale Agreement Between <Company Legal Name> ("Seller") And Marin Energy Authority ("Buyer") As of <Month, Day, Year> (the "Effective Date") Transaction Date: <Month, Day, Year> RECITALS: For Seller's Use Only_ Trade Date Seller's ID Attachment 'D' WHEREAS, pursuant to California Public Utilities Code Sections 366.1, et. seq., Buyer has been registered as a Community Choice Aggregator (the "CCA"); WHEREAS, Buyer is an independent public agency formed in accordance with the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) and established by that certain Joint Powers Agreement, effective as of December 19, 2008 ("Joint Powers Agreement") to protect the environment by furthering the environmental goals of AB 32, the Global Warming Solutions Act of 2006 (the "GWSA"), and reducing greenhouse gas emissions by studying, promoting, developing, conducting, operating and managing energy and energy-related climate change programs, including but not limited to the CCA program; WHEREAS, pursuant to California Public Utilities Code Section 366.2, the Buyer submitted Buyer's CCA Implementation Plan ("Implementation Plan') and Statement of Intent to the CPUC; WHEREAS, pursuant to the GWSA, the State of California has established a timetable to implement measures reduce greenhouse gas emissions; WHEREAS, pursuant to its regulatory authority and the purposes of the Joint Powers Agreement, Buyer required as part of its Request for Proposals that at least 25% of the Full Requirements Product Supply include Eligible Renewable Energy; WHEREAS, Buyer, pursuant to this Confirmation, will be taking a regulatory action that will purchase Renewable Energy to promote the regulatory goals established in the GWSA and thereby qualify for Class 8 categorical exemption under Section 15308 of Title 14 of the California Code of Regulations; WHEREAS, Buyer issued a Request for Proposals for Full Requirements Product Supply for Buyer serving as the CCA; WHEREAS, Buyer selected Seller to supply the Full Requirements Product for Buyer serving as the CCA; WHEREAS, Buyer will in turn supply the Full Requirements Product for use by the Members; and WHEREAS, Seller and Buyer desire to set forth the terms and conditions pursuant to which Seller shall supply the Full Requirements Product to Buyer, and Buyer shall take and pay for such supply of Full Requirement Product, including, subject to satisfaction of the conditions herein. NOW, THEREFORE, in consideration of the mutual covenants and agreements in this Agreement and for other good and valuable consideration, the sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties agree as follows: 1. DEFINITIONS. Defined terms shall have the meanings set forth in this Confirmation or as set forth below: "Ancillary Services" means those ancillary services, including but not limited to those described in FERC Order No. 888, that may from time to time be required by FERC to be supplied by CAISO. "Applicable Law' means any statute, law, treaty, rule, regulation, ordinance, code, permit, enactment, injunction, order, writ, decision, authorization, judgment, decree or other legal or regulatory determination or restriction by a court or Governmental Authority of competent jurisdiction; or any binding interpretation of the foregoing, as any of them is amended or supplemented from time to time. "CAISO" means the California Independent System Operator Corporation or the successor organization to the functions thereof. "CAISO Charges" mean those amounts [(other than for imbalance Energy)] billed by CAISO and associated with the procurement and delivery at the Delivery Point of any full requirements product through the CAISO market to CCA Customers as such charges may be adjusted from time to time pursuant to the Tariff. "Capacity" means the net generating capability of a generating resource or generating resources. Capacity is expressed in MW. "Capacity Requirement" means Capacity as required for Buyer to meet its RAR. "Commercially Reasonable Efforts" for the purposes of this Confirmation, "commercially reasonable efforts" or acting in a "commercially reasonable manner" shall not require a Party to undertake extraordinary or unreasonable measures. #4829.9021-7988A "Customers" means any account designated, from time to time, by Buyer as being served by Buyer, and identified to Seller pursuant to this Confirmation. "Energy" means real (not reactive) electric energy in the form of three-phase alternating current having a nominal frequency of approximately 60 cycles per second, a harmonic content consistent with the requirements of the Institute of Electrical and Electronic Engineers Standard No. 519, and a voltage content consistent with the guidelines applied by the Control Area in which the applicable generating resource resides. Energy is measured in MWh. "Eligible Renewable Energy Source" means any renewable energy source that qualifies for the RPS "Environmental Attributes" means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to any Renewable Energy Source or Renewable Energy. Environmental Attributes include but are not limited to renewable energy credits, as well as: (1) any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants; (2) any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth's climate by trapping heat in the atmosphere; (3) the reporting rights to these avoided emissions, such as Green Tag Reporting Rights. Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser's discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Environmental Attributes associated with one (1) MWh of energy. Environmental Attributes do not include (i) any energy, capacity, reliability or other power attributes from a Renewable Energy Source, (ii) production tax credits associated with the construction or operation of a Renewable Energy Source and other financial incentives in the form of credits, reductions, or allowances associated with the project that are applicable to a state or federal income taxation obligation, (iii) fuel -related subsidies or "tipping fees" that may be paid to a seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or (iv) emission reduction credits encumbered or used by a Renewable Energy Source for compliance with local, state, or federal operating and/or air quality permits. If the Renewable Energy Source is a biomass or biogas facility and Seller receives any tradable Environmental Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Environmental Attributes to ensure that there are zero net emissions associated with the production of electricity from such Renewable Energy Source. "Governmental Authority" means any federal, state, local or municipal government, governmental department, commission, board, bureau, agency, or instrumentality, or any judicial, regulatory or administrative body, having jurisdiction as to the matter in question. "Imbalance Charge" means any scheduling penalties, imbalance penalties, overpull or unauthorized overrun penalties, operational flow order penalties, cash out charges, banking charges or similar penalties, fees or charges, assessed by, or oversupply credits or payments due with respect to a failure to comply with balance and/or scheduling requirements of any applicable entity, specifically excluding any distribution charges imposed by PG&E on the delivery of the Energy hereunder. "Other Renewable Energy Source" means any renewable energy source that is not an Eligible Renewable Energy Source, including wind, hydro -electric, geothermal, biogas including landfill gas, digester gases and gas conversion or gasification technologies, direct combustion biomass, biodiesel power producing facilities, photovoltaic, solar thermal, fuel cells using eligible renewable fuels, qualifying municipal solid waste conversion, tidal current, ocean wave, and ocean thermal technology; provided, however, that in no event shall coal or nuclear resources be deemed to be "Other Renewable Energy Source". "Product" means any products provided by Seller to Buyer under this Confirmation. "Renewable Energy Certificates" or "RECs" means a certificate of proof representing renewable and/or environmental attributes associated with energy production, issued through the accounting system established by the California Energy Commission under Public Utilities Code Section 399.13, that one unit of electricity was generated and delivered by an Eligible Renewable Energy Resource and such REC satisfies the requirements of RPS. "Renewable Energy" means electricity generated from Renewable Energy Sources. "Renewable Energy Source" means any Eligible Renewable Energy Source or Other Renewable Energy Source. "Renewables Portfolio Standard" or "RPS" means that quantity of renewable energy resources that Buyer is required to procure pursuant to Applicable Law. "Resource Adequacy Requirement" or "RAR" means those resource adequacy requirements that Buyer is required to comply with pursuant to Applicable Law. "SC Agreement" means the Scheduling Coordinator Agreement by which Buyer appoints Seller as its scheduling coordinator with the CAISO. #4829-9021-7988-2- "System Power" refers to the Energy resource mix for electricity in the State of California net of electricity sold to consumers as specific purchases. "Tariff' shall mean the electric tariff filed by CAISO with the Federal Energy Regulatory Commission, as such document is amended and replaced by CAISO from time to time. "Weighted Average Price" shall mean a price determined on a monthly basis as a function of Buyer's actual energy consumption and the corresponding CAISO Real -Time PG&E LAP Price. [The Parties to agree to the specific formula for calculating the actual weighted average price]. 2. PRODUCT. 2.1 Seller Supply Obligation. Throughout the Delivery Period, Seller shall sell and deliver or make available, or cause to be sold and delivered or made available to Buyer, the "Full Requirements Product," which is comprised of: (a) a quantity of electrical Energy determined in accordance with this Confirmation; (b) a quantity of Renewable Energy as set forth in Section 2.2; (c) a quantity of Capacity equal to the Capacity Requirement; (d) Ancillary Services required to supply the foregoing electrical Energy identified in this Section 2.1 (the "Full Requirements Energy") to the Delivery Point; (e) distribution losses incurred in supplying Full Requirements Energy at the Delivery Point; and (f) CAISO scheduling coordination services as set forth in the SC Agreement. 2.2 Renewable Energy. During the Delivery Period, Seller shall provide to Buyer Renewable Energy in amounts sufficient to ensure that (i) Customers participating in Buyer's (a) "Light Green" service receive at least 25% (and 26.5% during the Delivery Period in 2015) of their Energy from Eligible Renewable Energy Sources, and (b) "Deep Green" service receive 25% (and 26.5% during the Delivery Period in 2015) of their Energy from Eligible Renewable Energy Sources and 100% of their Energy from Renewable Energy Sources and (ii) Buyer meets any RPS obligations. The Renewable Energy sold by Seller to Buyer shall also include any and all Environmental Attributes associated with such Renewable Energy. If due to any action by the CPUC or any state, federal or local governmental authority or agency, or any change in Applicable Law which occur after the execution date hereof (a "Change in Law"), the Parties shall work in good faith to try and revise this Confirmation so that the Parties can perform their obligations regarding the purchase and sale of Renewable Energy on economic terms equal to those in force on the execution date hereof. In the event the Parties cannot reach agreement on any amendments to this Confirmation within 60 days following the Change in Law, Seller shall perform its obligations hereunder with regard to Renewable Energy in accordance with the Applicable Law immediately prior to the Change in Law. 2.3 No New Construction. Seller covenants and agrees, during the Delivery Period, that (a) no new facilities are required to be constructed in order for Seller to meet its supply obligation, and (b) it shall not construct any new facilities to meet its supply obligation hereunder unless such new facility has satisfied all Applicable Law, including CEQA and any other applicable California environmental statutes relating to the construction and operation of such facility. 2.4 Non -Renewable Energy. The Energy provided under this Confirmation may be procured from unit -specific sources, provided such resources are not coal or nuclear, under terms and conditions to be agreed between the Parties. To the extent unit -specific resources have not been agreed to by the Parties, Seller will use System Power to provide the required Energy. 3. DELIVERY PERIOD. This Confirmation shall be in full force and effect as of the Transaction Date. The terms set forth herein shall apply from the Start Date through the End Date: Start Date: End Date: June 1, 2010 May 31, 2015 4. LOCATION AND DELIVERY POINT. I Market Area I SUDDIV Point I Delivery Point I Buver's Local Utilitv I 5. PRICING. #4829-9021-7988 -3- 5.1: Contract Price (Electricity): Buyer shall pay the following Contract Price for Energy, including related Ancillary Services (on a pass-through basis), and CAISO scheduling services (expressed in USD per MWh) for all monthly Electricity usage that is within the Balanced Monthly Usage as set forth in the tables, below. Year Contract Price (in US$/MWh) 2010 $ 2011 $ 2012 $ 2013 $ 2014 $ 2015 $ 5.2. Contract Price (Renewable Energy): Buyer shall pay the following Premium (Renewable Energy) (expressed in USD per MWh) for all monthly Renewable Energy which is in addition to the Contract Price (Electricity), including related Ancillary Services (on a pass-through basis), and CAISO scheduling services (expressed in USD per MWh) for all monthly Electricity usage as set forth in the tables, below Year Eligible Renewable Energy Premium in US$/MWh Other Renewable Energy Premium in US$/MWh 2010 $ $ 2011 $ $ 2012 $ $ 2013 $ $ 2014 $ $ 2015 $ $ 5.3. Contract Price (Resource Adequacy Capacity): Buyer shall pay the following Contract Price (Resource Adequacy Capacity) (expressed in USD per kilowatt) on a monthly basis for Capacity as set forth in the tables below: Year System Resource Adequacy Capacity (in US$/kW/month) Bay Area Resource Adequacy Capacity (in US$/kW/month Other PG&E Resource Adequacy Capacity in US$/kW/month 2010 $ $ 2011 $ $ 2012 $ $ 2013 $ $ 2014 $ $ 2015 $ $ 5.4. Balanced Monthly Usage: The term "Balanced Monthly Usage" shall mean the volume of Energy that is between the "Lower Limit" and the "Upper Limit" as defined and set forth below: [add exhibit with the Baseline hourly volumes] Balanced Monthl Usage Limits Lower Limit (the "Lower Limit") Percent below Buyer's Baseline Mon hly Usage) Upper Limit (the "Upper Limit') Percent above Buyer's Baseline Monthly Usage) aTableStart:TotalContractedQuantit »(dower limib>% I au er limib>((TableEnd:TotalContractedQuantit ))% 5.5. Pass -Through Charges: Seller shall be responsible for bidding and scheduling the loads of all Customers in accordance with Applicable Law, including the Tariff. Seller shall pass through to Buyer all CAISO Charges for providing Energy at the Delivery Point. Buyer's Customers will remain responsible for payment of delivery charges for transmission, distribution, public goods and other non -bypassable surcharges charged directly to Customers by PG&E. Buyer may request a review of the relevant records of Seller to confirm the accuracy of any costs passed -through to Buyer hereunder. Seller shall provide such records for Buyer's review during normal business hours and copies of such records at Buyer's cost and subject to any applicable confidentiality restrictions. #4829-9021-7988-4- 5.6. Distribution Losses: Buyer shall be responsible for the costs of additional Energy, Renewable Energy and Capacity provided by Seller necessary to cover Distribution Losses, which shall be determined as follows: for energy by using the distribution loss factors required for settlements with the CAISO during the billing period; for Renewable Energy by using the distribution loss factors required by the California Public Utilities Commission for Renewable Portfolio Standards compliance for the compliance year; and for capacity by using the distribution loss factors required by the California Energy Commission for Resource Adequacy compliance for the compliance year. 6. CONTRACT QUANTITY. Seller shall service 100% of Buyer's Energy requirements. Energy prices pursuant to this Confirmation will relate to the quantities set forth in the table below (the "Contract Quantities'): The Contract Price relates to the Contract Quantities at (choose one) ® the Supply Point ❑ the Delivery Point ❑ Bu er's Meter Commodity Renewable Energy Baseline Energy Resource Adequacy Month Monthly Usage Baseline Obligation (in kW/month) (MWh) AnnualUsage MWh «ContractedQuantity» «monthly_usage» aannual_usag «Calc_ Demand_ RAs«TabaEnd: «date» e» ContractedQuantit » Buyer shall be liable for all costs associated with delivering Energy from the Supply Point to the Delivery Point and Seller shall assist Buyer (at Buyer's cost) with obtaining all Congestion Revenue Rights ("CRRs") required relating to the congestion from the Supply Point to the Delivery Point. [For unit -specific Energy delivered hereunder pursuant to Section 2.4, Buyer shall be liable for all costs associated with delivering Energy from the generation point (the load aggregation point) to the Delivery Point and Seller shall assist Buyer (at Buyer's cost) with obtaining all Congestion Revenue Rights ("CRRs") required relating to the congestion from such generation point to the Delivery Point.] 7. MONTHLY BILLING SETTLEMENT. For monthly volumes within the Balanced Monthly Usage, Seller shall invoice Buyer at the Contract Price for the actual monthly usage. 7.1. Usage Above Upper Limit: During any month of delivery, if Buyer's metered usage for Energy (expressed in MWh) exceeds the Upper Limit ('Excess Quantity'), Seller shall invoice Buyer an amount equal to the Upper Limit multiplied by the Contract Price (Electricity). For the Excess Quantity, Buyer shall reimburse Seller at the monthly Weighted Average Price plus all related CAISO Charges at the Delivery Point. 7.2. Usage Below Lower Limit: During any month of delivery, if Buyer's metered usage for Energy (expressed in MWh) is less than the Lower Limit ("Underused Quantity"), Seller shall invoice Buyer for an amount equal to the Lower Limit multiplied by the Contract Price (Electricity) and shall credit Buyer's account by an amount equal to the Underused Quantity multiplied by the monthly Weighted Average Price. 7.3. Resource Adequacy Capacity Usage Above Limit. During any month of delivery, if Buyer's received Capacity with respect to its Resource Adequacy Requirement exceeds the Upper Limit ("Excess Resource Adequacy Capacity Quantity'), Seller shall invoice Buyer an amount equal to the Upper Limit multiplied by the Contract Price (Resource Adequacy Capacity). For the Excess Resource Adequacy Capacity Quantity, Buyer shall reimburse Seller for its actual cost of buying the Excess Resource Adequacy Capacity Quantity. Seller shall make commercially reasonable efforts to minimize the cost of Excess Resource Adequacy Capacity Quantity purchased on behalf of Buyer provided that Seller shall not enter into any such transactions for such purchases without Buyer's consent and acceptance of such transactions. 7.4. Resource Adequacy Capacity Usage Below Limit. During any month of delivery, if Buyer's received Capacity with respect to its Resource Adequacy Requirement is less than the Lower Limit ("Underused Resource Adequacy Capacity Quantity'), Seller shall invoice Buyer for an amount equal to the Lower Limit multiplied by the Contract Price (Resource Adequacy Capacity) and shall credit Buyer's account for the revenues obtained by Seller from remarketing the Underused Resource Adequacy Capacity Quantity. Seller shall make commercially reasonable efforts to maximize the value of Underused Resource Adequacy Capacity Quantity remarketed on behalf of Buyer provided that Seller shall not enter into any such transactions for remarketing without Buyer's consent and acceptance of such transactions. 8. SEMI-ANNUAL RENEWABLE ENERGY RECONCILIATION. No later than [January Vt and June 1st] of each calendar year during the term of this Confirmation, Buyer shall provide Seller with notice stating Buyer's then -current estimate of Buyer's compliance with the Renewable Portfolio Standards for such calendar year together with documentation setting forth amounts of Renewable Energy which were required to be the delivered for the preceding six-month period pursuant to Section 2.2. Following delivery of this notice, the Parties shall work together promptly to determine whether they anticipate Seller to be compliant or not with the requirements set forth in Section 2.2 for such calendar year and the Parties shall work together in good faith to determine appropriate actions to ensure that Seller will deliver sufficient amounts of Renewable Energy to be compliant with the requirements set forth in Section 2.2. #4829-9021-7988-5- 8.1 Excess Renewable Energy. In the event the Parties anticipate that Buyer will purchase more Renewable Energy than required by Section 2.2 for such calendar year, Buyer may, in its sole discretion, to the extent permitted under Applicable Law, bank and carryover such excess Renewable Energy for use in the succeeding calendar year. In the event banking is not permitted by Applicable Law, then Seller shall remarket such excess Renewable Energy for Buyer and shall credit Buyer's account by an amount equal to the amount received by Seller for such sales efforts. Seller shall make commercially reasonable efforts to maximize the value of such excess Renewable Energy remarketed on behalf of Buyer provided that Seller shall not enter into any such transactions for remarketing without Buyer's consent and acceptance of such transactions. 8.2 Deficient Renewable Energy. In the event the Parties anticipate that Buyer will purchase less Renewable Energy than required by Section 2.2 for such calendar year, Seller shall seek to procure such additional quantities of Renewable Energy required by Buyer in such calendar year. Seller shall make commercially reasonable efforts to minimize the cost of the purchases of additional Renewable Energy purchased on behalf of Buyer provided that Seller shall not enter into any such transactions for procuring additional Renewable Energy without Buyer's consent and acceptance of such transactions. Seller shall use commercially reasonable efforts to secure such Energy at a price no greater than the Contract Price (Renewable Energy); provided, however that Buyer shall pay Seller the actual costs of such additional Renewable Energy (whether such costs exceed the Contract Price or not). 9. CAPACITY REDUCTION. Buyer shall notify Seller as soon as possible if there is to be a permanent decrease in the Capacity Requirement ("Capacity Reduction'). In addition, Buyer shall be deemed to have a Capacity Reduction if reduced capacity is shown on the most recent long-term forecast. Any Capacity associated with a Capacity Reduction shall be remarketed by Seller using its commercially reasonable efforts to maximize such value and no such transactions shall be executed without consultation with, and approval by, Buyer. Buyer shall pay Seller all costs Seller incurs in effectuating the Capacity Reduction, including any costs associated with hedging and other fees, costs, expenses and losses relating to selling or otherwise disposing of the Capacity, reduced by any revenues or gains realized thereby (in the aggregate, the "Resale Costs"), and Seller shall credit Buyer with an amount equal to the actual sales price for such capacity less the Resale Costs). The Parties will cooperate to use commercially reasonable efforts to reduce the cost to Buyer of a Capacity Reduction. 10. LOAD SERVED. The services and the Product described under this Confirmation shall be provided to the Customer accounts specified by Buyer. During the initial commencement of this Confirmation, the Customers will be switched to CCA service over an approximately 30 -day period in accordance with the applicable meter read cycle for such Customer. At the end of each month, Buyer shall provide to Seller updated account information for Customers to be served during the upcoming month. Buyer shall also provide to Seller a daily report of Customer sales based on the meter data reported by the utility distribution company. Buyer shall prepare invoices to the Seller based on such daily reports. Buyer shall also deliver notice of any Customers which are no longer part of the Buyer's Marin Clean Energy program. it. RESOURCE SUBSTITUTION. Buyer may independently gain control or enter into contractual obligations with respect to specific electric supply or demand-side resources procured from other third parties or independently developed by Buyer (Buyer Facilities). The Parties agree that incorporation of the Energy, Capacity, and Renewable Energy from such Buyer Facilities into this Agreement shall be in the sole discretion of Buyer, subject solely to adjustment of the price for Energy, Capacity, and Renewable Energy set forth in this Agreement hereto payable by Buyer to Seller to reflect all reasonable and actual documented costs Seller incurs in connection therewith, including, reimbursement from Buyer for any costs associated with hedging and other fees, costs, and losses directly incurred by Seller in reducing the Energy, Capacity, and Renewable Energy otherwise provided to Buyer pursuant to this Agreement, such costs to be offset by any revenues or gains of Seller realized thereby. Seller agrees to use commercially reasonable efforts to minimize such costs to Buyer. The Buyer may pursue the development of Buyer Facilities during the term of this Agreement. Buyer shall have the right, on and after December 31, 2010, to provide Seller not less than one hundred and eighty (180) days written notice that Energy, Capacity, or Renewable Energy will be available to be incorporated into this Agreement. Unless otherwise agreed between the Parties, within ten (10) Business Days of receipt of such notice, the Seller shall notify the Buyer in writing of the costs to Seller determined in accordance with this Section 11 to be incurred in connection with incorporating such Energy. Capacity, or Renewable Energy into this Agreement. Immediately upon receipt of such written cost determination, the Buyer shall have the right (but not the obligation) to direct the Seller in writing to incorporate such Energy, Capacity, or Renewable Energy into this Agreement at the agreed upon price. In the event that Buyer Facilities are expected to become operational or effective during the term of this Confirmation, the Parties shall work in good faith to amend the underlying credit agreements in place between Seller and Buyer and its lenders so that amounts paid by Buyer's customers to PG&E and then into the lockbox arrangement discussed in Schedule M of the Master Agreement shall be apportioned as security between the Parties and/or Buyer's lenders based on the quantity of energy delivered by Buyer to its customers from the Buyer Facilities as compared with the energy delivered pursuant to this Confirmation. As supplemented by this Confirmation including its Appendices, if any, all other Terms and Conditions contained in the Agreement remain in full force and effect. This Confirmation is subject to the Schedules identified below and that are attached hereto: Appendix I - Schedule of Operational Services #4829-9021-7988 - 3 - SELLER Sign: _ Print: Title: MARIN ENERGYAUTHORITY Sion: Print: Title: #4829-9021-7988 - 3 - Draft 11/5/09 Appendix l Schedule of Operational Services Reference: Master Power Purchase and Sale Agreement Between <Company Legal Name> ("Seller") And Marin Energy Authority ("Buyer") As of <Month, Day, Year> (the "Effective Date") Transaction Date: <Month, Day, Year> For Seller's Use Only Trade Date Seller's ID 1. Description of Operational Services ("Services"). In conjunction with the attached Confirmation, Seller shall provide the Services listed below: (a) Forecasting: Seller shall be responsible for preparing and submitting short-term load forecasts of Energy and Capacity for less than one year as Buyer's "Scheduling Coordinator' (as such term is defined by CAISO) necessary to meet its energy supply obligations to Buyer. The Parties shall mutually agree from time to time on the assumptions and models to be included in the short-term and long-term forecasts prepared hereunder. Buyer shall provide settlement quality meter data, resource data and load data as reasonably requested by Seller necessary for the preparation of the forecasts. Seller shall not be liable for any costs or losses incurred by or charged to Buyer as a result of Seller's forecasting obligations so long as Seller has performed its obligations in accordance with prudent industry practices. In the event an administrative agency requests clarification of forecasts provided by Seller hereunder or otherwise requires Buyer to substantiate such forecasts, Seller shall in good faith assist Buyer in responding to the administrative agency's request and assist Buyer in defending the reasonableness of such forecasts (such assistance shall exclude payment of any costs or expenses incurred by Buyer in responding to such inquiries). (b) Scheduling Services: Seller shall be responsible for submitting schedules and bidding Product in accordance with the obligations of a Scheduling Coordinator as defined by the CAISO, including the scheduling and bidding for loads of all Customers served by Buyer. Seller shall perform the scheduling and bidding scheduling and bidding services in accordance with the Tariff, protocols and business practices. Seller shall established a separate "Scheduling Coordinator' identification to isolate CAISO charges related to providing energy supply services to Buyer. Seller shall adjust schedules as necessary to assist in coordinating the transition of Resource Adequacy obligations between PG&E and Buyer. Seller shall provide the services required pursuant to this sub -paragraph in accordance with the terms of a Schedule Coordinator Services Agreement to be executed between the Parties. (c) Load Balancing Services: Seller shall be responsible for and shall pay, and shall reimburse or credit Buyer if Buyer pays, all Imbalance Charges resulting from the supply of Product between the Energy Minimum and Energy Maximum, except to the extent such Imbalance Charges are a result of Buyer's failure to perform hereunder, including but not limited to the failure to receive Energy, or under the SC Agreement, or are a result of an event of Force Majeure. (d) Filing: Seller shall file with CAISO all schedules and meter data reports required to be filed by the scheduling coordinator for Buyer. (e) Regulatory Reporting. Seller will provide information to Buyer necessary for Buyer to timely comply with monthly, annual and periodic regulatory reporting requirements for RPS and Resource Adequacy requirements and as otherwise required by Applicable Law with respect to any Product. 2. Buyer's Obligation. (a) Forecasting: Buyer shall prepare appropriate long-term load forecasts for Energy and Capacity greater than one year and Seller will assist and coordinate with Buyer in its preparation of such long-term load forecasts and Buyer shall submit such long-term load forecasts as required by the CPUC, CEC the CAISO or any other applicable regulatory body, including those required of a CCA (including all updates and revisions, the "Long -Term Forecast") and promptly provide Seller with a copy thereof, provided that every ninety (90) days Buyer shall provide Seller with either a new Long -Term Forecast or a statement that no changes to the most recent Long -Term Forecast have occurred. Seller shall have the right to request clarification regarding any change made to the Long -Term Forecast. (b) Information: Buyer shall timely provide any information as reasonably required by Seller to perform the Services. #4829-9021-7988A SELLER MARIN ENERGY AUTHORITY Sign �m Print: Print: Title: Title: #4829-9021-7988 _ 3 _ Attachment 'E' NOTICE OF PUBLIC REVIEW AND COMMENT PERIOD ON INITIAL CEQA RECOMMENDATION FOR DRAFT POWER PURCHASE AGREEMENT The staff of the Marin Energy Authority ("MEA") has made an initial recommendation to the Board of Directors that the Board determine at its February 4, 2010 meeting when the draft Power Purchase Agreement is scheduled for final consideration that this Agreement is categorically exempt from the California Environmental Quality Act ("CEQA") pursuant to State CEQA Guidelines Sections 15308 and 15061(b)(3). The MEA has established a public review and comment process for interested persons and members of the public to comment on the initial staff recommendation and whether or to what extent CEQA applies to the draft Power Purchase Agreement. Persons may file written comments by no later than the close of business on January 15, 2010 with the Interim Executive Director, Dawn Weisz. Comments should be sent to the following address: Marin Energy Authority 3501 Civic Center Drive, Room No. 308 San Rafael, California 94903 Attn: Dawn Weisz, Interim Executive Director Comments also may be sent electronically to: dweisz@co.marin.ca.us After receiving any public comments, the Interim Executive Director, in her role as the Environmental Coordinator under the MEA's Environmental Review Guidelines, will forward her preliminary determination to the Board on whether the draft Power Purchase Agreement is exempt from CEQA at least 5 days before the February 4, 2010 meeting. The public will be given an opportunity to speak on this matter before the Board at this meeting. The Board will make the final determination as to whether the Power Purchase Agreement is a "project" as defined by CEQA and whether the preliminary determination by the Interim Executive Director should be approved or some other CEQA action should be taken. 12713-0002\1188315v1.doc IT'larin energy ClLltl-iol-ity November 5, 2009 Attachment 'F FAUV20 ! NOV ® 5 2009 MARIN TO: Marin Energy Authority Board FROM: Dawn Weisz, Interim Director RE: Resolution Affirming the Board's Policy that Program Agreement 1 Will Only be Approved if Customer Costs for the Light Green Energy Product Can Be At Or Below PG&E's Projected Cost. (Agenda Item #C-3, revised) ATTACHMENTS: Resolution Dear Board Members: At the October 1, 2009 meeting of your Board, staff was asked to prepare a resolution affirming the Board's policy decision to set customer costs for the Light Green energy product at or below PG&E's projected costs for customers. The attached resolution is in response to this request and provides that the Board will not approve the draft power purchase agreement (referred to as Program Agreement 1) currently scheduled for approval on February 4, 2010 unless the customer costs for the Light Green energy product can be at or below PG&E's projected costs. Recommendation: Approve resolution. RESOLUTION NO. 2009- A RESOLUTION OF THE BOARD OF DIRECTORS OF THE MARIN ENERGY AUTHORITY AFFIRMING THAT PROGRAM AGREEMENT 1 WILL ONLY BE APPROVED IF CUSTOMER COSTS FOR THE LIGHT GREEN ENERGY PRODUCT CAN BE AT OR BELOW PG&E'S PROJECTED COSTS. WHEREAS, the Marin Energy Authority ("MEA") is a joint powers authority established on December 19, 2008, and organized under the Joint Exercise of Powers Act (Government Code Section 6500 et seq.); and WHEREAS, MEA members include the following Marin communities: the County of Marin, the City of Belvedere, the Town of Fairfax, the City of Mill Valley, the Town of Ross, the Town of San Anselmo, the City of San Rafael, the City of Sausalito and the Town of Tiburon; and WHEREAS, the MEA Board has conducted an RFP process and a contract negotiation process for power purchase; and WHEREAS, the MEA Board has developed a draft Power Purchase Agreement also known as "Program Agreement 1" with potential energy suppliers; and WHEREAS, MEA technical advisors have determined that responses to the RFP included indicative costs that would allow the Marin Clean Energy program to offer the Light Green energy project at a customer cost that is at or below the projected PG&E customer cost; and WHEREAS, MEA's mission is to provide renewable energy, cost stability and other customer benefits. NOW, THEREFORE, BE IT RESOLVED, by the Board of Directors of the Marin Energy Authority that MEA will not approve and execute the Power Purchase Agreement known as "Program Agreement 1" with an energy supplier until confirmed pricing can be provided that will allow customer costs to be at or below PG&E project costs. PASSED AND ADOPTED at a regular meeting of the Marin Energy Authority Board of Directors on this 5th day of November 2009, by the following vote: City of Belvedere Town of Fairfax County of Marin City of Mill Valley Town of Ross Town of San Anselmo City of San Rafael City of Sausalito Town of Tiburon AYES NOES ABSTAIN ABSENT CHAIR, MARIN ENERGY AUTHORITY BOARD 1999 HARRISON STREET SUITE 1440 OAKLAND, CALIFORNIA 94612-3517 November 20, 2009 MRW &ASih S OCIATE8 Marin Manager's Association Attention: Matthew Hymel, Marin County Administrator Peggy Curran, Tiburon Town Manager Debbie Stutsman, San Ansehno Town Manager Re: Analysis of Service Agreements and Financial Risk to MEA Dear Mr. Hymel, Ms. Curran, and Ms. Stutsman: Exhibit I TEL 510.834.1999 FAX 510.834.0918 mrw@mmassoc.com As requested, MRW & Associates, LLC (MRW) reviewed copies of several documents being negotiated by the Marin Energy Authority (MEA) and Shell Energy North America (SENA), related to SENA providing power to MEA for the period from 2010-2015.2 The purpose of this examination was to identify risks faced by MEA, the member agencies that make up MEA, and the customers that would ultimately receive commodity electricity from MEA. Based on our review, MRW does not find any fatal flaws with the Agreements. Nonetheless, we find that there are certain issues that would place financial rislc3 on MEA or its customers. We point out these risks and propose some suggested changes to the Agreements for two reasons: (1) so that policymakers can make informed decisions regarding the potential benefits and risks of the CCA (given the current form of the Agreements), and (2) to suggest ways that policymakers might choose to modify the agreements to address these risks. It is important to understand MRW's scope of work for this assignment. Our review focused on identifying potential risks associated with the CCA program rather than enumerating the benefits of the CCA. MEA, in its Business Plan and other documents, has laid out these potential benefits. Some of these potential benefits include: Providing residents and businesses of Marin the opportunity to purchase 100% green power. ' MEA has not yet decided that SENA will be the supplier to MEA. However, SENA is in the "first position" and, as a result, MEA and SENA are negotiating the Agreements. In the memorandum, we use SENA and supplier interchangeably. 2 MEA is considering forming Marin Clean Energy, a Community Choice Aggregation (CCA) program. For. simplicity, this memo refers to MEA. 3 By financial risk we mean the risk that customers would pay more for power than they would have otherwise bad they remained with PG&E, or that MEA incur costs greater than its revenues. We note that there is, of course, upside risk—that MEA consistently provides power at a cost less than PG&E, which is MEA's intent. Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 2 • Assisting local governments meet state greenhouse gas reduction compliance requirements. • Over the long run, potentially providing power at costs comparable to, or less than, PG&E. • Insulating Marin power users from volatile natural gas and power commodity markets through the use of renewable energy. • Providing local control over power procurement and ratemaking decisions. We do not dispute these potential benefits, nor do we attempt to weigh these potential benefits against the potential risks we identify here. Such an analysis is unavoidably subjective and is more appropriately done by local policymakers, who better understand the values and concerns of their constituents. While we make some recommendations regarding possible changes to the Agreements (or potential MEA policies), creative thinkers may also come up with alternatives that address the issues in ways that better meet Marin's policy goals and risk preferences. Approach MRW received copies of various draft documents from MEA. The documents (jointly, the Agreements) were4: • Master Power Purchase & Sale Agreement, Edison Electric Institute • Cover Sheet, Master Power Purchase & Sale Agreement (Cover Sheet) • Confirmation, Master Power Purchase & Sale Agreement (Confirmation) The Edison Electric Institute Master Power Purchase & Sale Agreement is an industry standard agreement used in numerous wholesale power transactions (which is what MEA and SENA are negotiating). The proposed Cover Sheet specifies choices regarding options in the Master Power Purchase & Sales Agreement and also establishes other broad changes that define the overall goals and boundaries of the agreement. The Confirmation defines terms and conditions specific to the initial power purchase by MEA from the supplier.' MRW reviewed the draft Agreements in order to understand the services SENA would provide to MEA, the allocation of risks between the two entities, and the risks that the member agencies and MEA's customers would face.6 MRW also reviewed a presentation by MEA that outlined the key attributes of the Agreements and the goals of MEA .7 4 MRW is aware of five versions of the Agreements. The first version of the Agreement was provided to MRW by MEA. The second version is found on MEA's website: litti)://www.inariiieners2y5i�horit or //key efin. The third version of the Agreement was a confidential draft developed by SENA and provided to MEA on October 28, 2009. A fourth version was a confidential draft provided to MRW on November 2, 2009. A fifth, the draft final Agreement, was provided via email and is dated November 5, 2009. 'As discussed below, MEA will sign other Confirmations with the supplier when MEA makes additional purchases. ' MRW cannot provide a legal opinion of the Agreements. Instead, MRW's review was based on our professional judgment and experience. r http://www.marineneravauthority.org/PDF/MEA Presentation.ndf MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 3 After completing our initial review of version 1 of the Agreements, MRW held several extensive conversations with representatives of MEA to clarify questions MRW had regarding the Agreements and to understand MEA's perspective regarding specific provisions of the Agreements. Conversations were also held following MRW's review of the third and fifth version of the Agreements. MRW also requested that MEA perform several pro forma financial analyses using MEA's proprietary financial model so that MRW could understand the effect that different assumptions would have on the financial performance of MEA. MRW reviewed the results of these sensitivity analyses. During the engagement, MRW found MEA staff to be responsive to our requests for information and analysis. MRW also found MEA staff to be willing to address with SENA issues identified by MRW in the draft Agreements. MRW appreciates the difficulty MEA staff faces in trying to negotiate favorable terms and conditions with SENA and to finalize the Agreements while responding to questions and concerns raised by MRW.8 Risks and Issues with the Agreements MRW's initial review of the Agreements (version 1) identified a number of issues and concerns. Some of these concerns were eliminated by MEA explaining and clarifying the language of the Agreements. Others were explicitly addressed in subsequent drafts of the Agreements. We discuss below the remaining issues with the Agreements that were not clarified by MEA or addressed in subsequent drafts. 1. Basis Risk from Point of Supply to Point of Delivery. Under the Agreements, SENA prices its product at the Supply Point ("NP 15 EZ GEN HUB"), which is a supply point in the California power market. However, MEA receives the power at the Delivery Point ("PG&E LOAD AGGREGATION POINT"). This means that MEA is responsible for all costs to deliver power from the Supply Point to the Delivery Point. MEA indicates that this risk is mitigated because MEA will receive a pro rata amount of Congestion Revenue Rights (CRRs) from PG&E. However, these CRRs are not all applicable to deliveries from MEA's Supply Point to its Delivery Point. MEA also states that it will purchase other CRRs to mitigate the risk of congestion between the Supply Point and Delivery Point. MEA estimates that the congestion costs between the Supply and Delivery points to be $1-$2 per MWh. These costs represent only a few percent of MEA's overall costs. However given that the current wholesale market framework in California has existed only since April 1, 2009, there is relatively little data on the volatility of either CRRs or the price differentials between the proposed Supply and Delivery Points in the Agreement. 'In addition, MRW has had prior professional experience with MEA's technical advisors, Navigant Consulting, and its counsel addressing the power agreements, Milbank, Tweed, Hadley & McCloy, LLP, and has found their work to be excellent. MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 4 Recommendation: While the CRRs that will be allocated to MEA upon CCA formation may be valuable, MRW believes that MEA should focus on providing clean electricity at low, stable prices to its customers and not be distracted by attempting to extract the maximum value out of the CRRs allocated to it by PG&E. Also, unless otherwise specified, CRRs are only valid for one year. Thus, under the current approach, MEA will have to purchase additional CRRs in the future, regardless of the CRRs it receives from PG&E. Given the relatively limited amount of information regarding the volatility of CRRs prices between the Supply and Delivery points, there is some risk that future CRR costs may exceed MEA's estimated costs. Therefore, we recommend that MEA explore the cost of having its supplier price its power at the Delivery Point, rather than having MEA bear the risk of delivery charges between the Supply Point and the Delivery Point. One possible way to do this would be to request pricing from potential suppliers at both the Supply Point and the Delivery Point. With that information, MEA can make an informed choice as to whether the potential revenues gained by retaining and selling unused CRRs plus the future risk of price volatility of CRRs is superior to transferring the allocated CRRs to SENA and having SENA bear the congestion cost risk between the Supply and Delivery Points. 2. Uncertainty in customer loads. Under its current schedule, MEA plans to sign the Agreements in early February 2010 for service of its Phase I loads, which MEA characterizes as about 20% of its ultimate potential load. At that time, MEA must either specify the quantity of renewable and non-renewable energy and other services that it will receive from the supplier or establish some other mechanism whereby its Phase I loads are met. This is a concern because if MEA over -procures, then it will have 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 MEA under -procures, then it needs to purchase power in the future at unknown rates, which could be higher (or lower) than the fixed prices to be specified in the Agreement in February 2010. Recommendation: Phase I will consist of the government load of the member agencies plus some unspecified non-governmental load. Given that only around 10% of the Phase I load will be that of the MEA member agencies (which MEA assumes will not opt -out), the uncertainty in Phase I customer load is only slightly less than for Phase II. Nonetheless, MRW recommends that MEA consider ways to address the uncertainty associated with the level of opt outs. MRW suggests three approaches: MEA could require its supplier to provide MEA's entire Phase I load, regardless of the level of opt -outs, at a fixed price. Under this approach, the supplier bears all volume risk rather than MEA having to pre -specify load and facing the risk of under- or over - procuring, as is currently the case in the Agreements; MEA could request fixed pricing for two tranches of energy. The load for the first tranche would be much less than the expected Phase I load and would be specified prior to contract signing. The load for the second tranche would be specified after the end of the opt -out period (when MEA would have a much better idea of its total Phase I load requirements). The Supplier would, in essence, be selling MEA an option to adjust the MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 5 quantity of load in the second tranche; and MEA could request pricing quotes for different "deadbands" around its expected Phase I load. That is, the supplier would provide all needed power, as long as the actual load fell within the expected load plus or minus some percentage. In this case, only if the usage fell outside of that plus -or -minus band would MEA be responsible for buying or selling the excess power. With these three pricing options, MEA decision -makers can then weigh the additional cost of having the supplier bear all the risk of load uncertainty versus the cost of MEA bearing a certain amount of the risk of the actual loads deviating significantly from the expected load. In addition to the issues identified above, there are several outstanding issues in the Confirmation that are less important. These are addressed in Attachment 1. Risks and Issues Facing MEA That Are Independent of the Agreements In addition to reviewing the draft Agreements, MRW was also asked to assess, at a high level, any additional risks the MEA CCA might face. Below are MRW's findings. Uncertainty in PG&E Exit Fees. Depending upon its ratemaking policies, MEA or MEA's customers may face financial risks due to the level of exit fees they will pay to PG&E. Under base case assumptions, the overall level of exit fees during the five-year term of the Agreements is modest, averaging 0.3¢/kWh.9 However, if wholesale power prices are significantly (33%) lower than currently forecast (driven down by natural gas prices lower than assumed under MEA's base case), exit fees can increase by nearly an order of magnitude, up to 2.5¢/kWh. At the same time, lower gas/power prices would also reduce PG&E's rates relative to base case assumptions. Since MEA proposes to purchase power from SENA at fixed prices,10 its costs would not decrease with lower gas/power prices. 11 Thus, under a substantially lower gas/power price scenario, MEA customers could pay between 12%-15% more than the forecasted level of PG&E rates. 12," Alternatively, if MEA chose to bear the CRS price risk, it would have to have credit, reserves or hedging mechanisms in place to keep its light green customers' overall electricity rates at or below PG&E's.14 In assessing this risk, the key questions are: "How likely is it that gas and power prices will be below that forecasted by MEA, and for how long would such low prices would persist?" 9 All cost and rate values. presented here are based on pro forma analyses provided to MRW by MEA. 10 The Phase I agreements reviewed here present a fixed-price product. We assume, consistent with MEA's pro forma analysis, that Phase II would likewise be at a fixed price. " See discussion below regarding MEA costs that are not necessarily fixed. 12 Percentage based on all -in rate (i.e., includes all applicable PG&E transmission and distribution charges in addition to MEA power charges and PG&E exit fees). 13 Assumes that MEA does not mitigate CRS risk. 14 Value based on full, post -Phase II loads. AMW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 6 While a quantitative assessment of power and gas price volatility is beyond the scope of this assignment, power and gas prices assumed in the low price sensitivity case have occurred in the past ten years, and given the historical volatility of the natural gas market, have a finite chance of occurring again in the next five years. Nonetheless, extraordinarily low prices are not likely to persist for multiple years in a row, meaning that a prolonged period—more than a year—of adverse market conditions is remote. Recommendation: MEA, as a market participant, is better suited to mitigate the risk of low gas prices than are individual customers. MRW recommends that MEA explore establishing some form of hedge against high exit fees (i.e., a hedge against very low gas prices) so as to shield MEA customers from this market risk. Such action would also reduce the overall volatility of MEA customers' power prices, which is one of the stated benefits of participation in MEA. 2. Need to Establish an MEA Departing Load Fee. MEA's Business Plan assumes that MEA will construct renewable supply sources starting in 2011, with an expected online date of 2014. To undertake this construction program, MEA would issue debt (as is typically the case for other utilities). This effort would allow MEA to increase its level of renewable resources beyond the level assumed in the Agreements and would form the basis for MEA's renewable portfolio after the end of the Agreements. The Agreements allow MEA to undertake such a development program. MEA has indicated to MRW that it would only undertake such a construction program if it appeared to be cost-effective at the time the decision was being made. MRW believes that if MEA adds its own resources then that action has certain consequences: (1) SENA would likely have to liquidate some portion of the resources that it procured for MEA under the Agreements, with MEA customers being responsible for any losses (or benefiting from any gains) resulting from those sales and (2) MEA would have fixed debt service obligations to pay for its renewable resources. If MEA customers choose to leave MEA's service after the end of the opt -out period, then either the departing customers must pay a "Departing Load Fee" to MEA or the electric rates for remaining customers would increase. Note that customers choosing not to receive power from MEA during the opt -out period (two months prior to MEA providing power to two months after MEA starts providing power) would not be subject to any MEA Departing Load Fee. The is Departing Load 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 MEA. 15 Recommendation: MEA has indicated to MRW that it expects to establish a Departing Load Fee using an approach consistent with the method used by PG&E. MRW believes that MEA needs to adopt a clear policy stating (1) that it will charge a Departing Load Fee to customers that depart MEA service and (2) how MEA will determine that fee. This is critical in the case � a Also note that if an MEA 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 MEA. MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 7 where MEA owns its own resources. 16 MRW believes that MEA should include this policy in the Implementation Plan that it files with the California Public Utilities Commission (CPUC). CCA bonding obligation: CCAs must post a bond that would be sufficient to cover the costs to PG&E of having to unexpectedly serve the former CCA customers in the event of CCA failure. A settlement agreement at the CPUC set forth a complex formula for calculating the required bond level. This formula is recalculated biannually so as to account for prevailing wholesale power market conditions. If the wholesale power market is unusually high (above average retail rates), then the bond amount increases to cover the cost PG&E would incur to serve the returned customers. For MEA, this could be on the order of a few million dollars, which is ten times more than is shown in the MEA budget provided to MRW. However, the 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 MEA 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. Recommendation: Although MEA might face significantly higher bond requirements than shown in the budget provided to MRW, it would occur in circumstances when MEA should have the ability to cover it without undue financial stress. Additional Policy Considerations Meaning of "Projection" to meet or beat PG&E rate. MEA has stated that one of the benefits for customers is "Costs at or below PG&E.i17 In discussions with MRW, MEA has clarified that this condition is based on comparing the projected overall costs of MEA assuming power supply by a third party over the term of the Agreements against MEA's costs assuming power supply was provided by PG&E at MEA's forecast of PG&E's tariffed generation rate. In other words, the following inequality must occur for MEA to sign the Agreements: MEA Power Supply Costs + Customer Exit Fees + MEA Overhead < PG&E Gen Rate]$ Of course, all of the above factors are somewhat uncertain, although MEA Power Supply Costs are less uncertain than the other factors. Recommendation: MRW is concerned that customers might misinterpret MEA's statements regarding the rates for the Light Green product. To avoid that, MRW recommends that MEA make it very clear that such a commitment is based on reasonable commercial efforts. This 16 MRW believes that an exit fee policy is needed even if MEA does not develop its own renewable supply options. MEA presentation, October 2009, p. 12. is MEA Power Supply Costs, Customer Exit Fees, MEA Overheads, and PG&E Gen Rate are all forecasted values in early February 2010. MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 8 would provide MEA with the flexibility it may need to meet its other policy goals (e.g., greenhouse gas reductions, greater levels of renewables, local control) even if, in one particular year or another, market pricing turns against MEA, resulting in costs to MEA customers being higher than if they were PG&E customers. 2. Clarify MEA's rate design policies. MEA informs MRW that it plans to keep its rate design consistent with PG&E's rate design in MEA's first year of operation. This will simplify comparisons between MEA's rates and PG&E's generation rate. However, MEA has not yet clarified how it plans to design rates after the first year of operation. Recommendation: MRW believes that clarification regarding rate design policies is needed. This is not to say that it is necessary to restrict MEA's rate design at the present time. However, a policy statement regarding how MEA plans to design rates would provide customers with a better understanding of how their rates might look under MEA and allow for more informed decision-making. Points of Information MEA plans to procure power in two separate transactions: one for power to serve the Phase I load (beginning on or about June 1 2010) and one for power to serve the Phase 11 load (at a later date no sooner than January 1, 2011). This means that either prices will differ for Phase I and Phase II customers or Phase I customers will have their rates change at the onset of Phase II. The Agreements being considered in this analysis only pertain to the Phase I load. According to MEA, it intends to negotiate a separate Confirmation agreement 19 with its Phase I supplier when MEA is ready to start Phase 11. MEA envisions this negotiation to address primarily price but also "may consider slight revisions to the Confirm for Phase H to the extent our better information (about opt outs, operations streamlining, other lessons learned) requires revision."20 The pro forma financial analysis provided to MRW shows the Phase II load being served on January 1, 2012, however MEA has said that depending upon market conditions, it intends to remain flexible as to the start date of Phase H, moving it forward or backward by a year (or more) so as to take best advantage of Pricing in the power markets. This phase-in approach has both positive and negative aspects.2 Since power prices are volatile, it is likely that the prices MEA receives from its supplier for Phase II will differ from its pricing for Phase I. If power prices do differ, MEA will need to decide whether it establishes similar rates for all customers or sets rates for its Phase II customers '9 The Confirmation contains prices, quantities, and other important aspects of the agreement between MEA and its supplier. 2° Email communication, Elizabeth Rasmussen to Mark Fulmer November 5, 2009. 21 The positive aspects include simplifying the initial startup of MEA and negotiating a new agreement based on better understanding of opt -out risk. Negative aspects include possibly re -opening issues that were settled in Phase I, seeing wholesale power prices prior to Phase II that do not allow MEA to proceed (because its rates would not meet or beat PG&E's rates at that time) and having to negotiate with a supplier that has great deal of negotiating leverage. MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 9 different than for its Phase I customers 22 The phase-in approach has both benefits and risks but, on balance, it appears to be a reasonable strategy. MRW recommends that MEA limit the issues in the Confirmation that it revisits when establishing Phase II pricing and consider accepting pricing proposals from alternate suppliers. 2. The Agreements depend, in part, on the Scheduling Coordinator Agreement, which is not yet finalized. The Agreements refer in several places to the Scheduling Coordinator Agreement (SC Agreement). MEA and SENA are just beginning to negotiate the terms of the SC Agreement. MEA believes that it will finalize the SC Agreement in November 2009 and also believes that the SC Agreement will not significantly affect the relative risk allocation in the Agreements. Until MEA finalizes the SC Agreement, the degree to which costs and risks are ultimately allocated between MEA and SENA is unresolved. Although relatively small, some MEA costs are uncertain. MEA indicates that "Five year energy pricing will be known prior to contract signing.s23 SENA's pricing will include Resource Adequacy, non-renewable energy, RPS -compliant renewable energy, and other renewable energy. SENA's pricing will also cover power scheduling and forecasting services provided by SENA. However, SENA's pricing explicitly does not include ancillary services, net supply costs outside of the pre -determined Balanced Monthly Usage, distribution losses, and any net costs incurred by SENA to unwind positions if MEA decides to bring on its own resources. In other words, since SENA's price is not all-inclusive, customers should be advised that there are certain costs that are not "known prior to contract signing." However, MRW expects that these "uncertain" costs will be relatively small. Also, MEA has included estimates for costs not included in SENA's price in its financial models. " This is exacerbated by the fact that the exit fees charged to CCA customers by PG&E vary depending upon when the customer begins CCA service. If MEA decides to have similar rates for both Phase I and Phase II customers, then the rates for Phase I customers might increase or decrease relative to the rates those customers saw during Phase I. " MEA Presentation, October 2009, p. 36. MRW & Associates, LLC Marin Manager's Association Analysis of Service Agreements and Financial Risk to MEA November 20, 2009 Page 10 Conclusions Based on our review, MRW does not find any fatal flaws with the Agreements. However, as noted above, there are certain issues that would place financial risk on MEA or its customers that should be addressed by MEA .24 Please give us a call at (510) 834-1999 if you have questions about this material. Best regards, William A. Monsen and Mark E. Fulmer Principals attachment °" By financial risk we mean the risk that customers would pay more for power than they would have otherwise had they remained with PG&E. We note that there is, of course, upside risk—that MEA consistently provides power at a cost less than PG&E. MRW & Associates, LLC ATTACHMENT ADDITIONAL ISSUES IN CONFIRMATION 1. Open issues in the Confirmation. In the final draft of the Confirmation dated November 5, 2009, there are three issues that remain open (i.e., they are denoted with [square brackets]). These are (1) definition of CAISO Charges, (2) Definition of "Weighted Average Price", and the final sentence in Section 6 (regarding the party that is responsible for paying transportation charges for unit -specific purchases). The open issues all represent potential costs that will be borne by MEA customers rather than the supplier. The magnitudes of the potential costs are unknown but are likely not so great that they would endanger MEA's viability. Recommendation: MEA should finalize these three open issues in the following manner: Definition of CAISO Charges: The open issue is whether "Imbalance charges" are included in the definition of CAISO Charges. MRW believes that the supplier should bear these imbalance charges (as is indicated in Appendix 1, section 1(c).) MEA has indicated that the final draft of the Confirmation will not include Imbalance Charges within the definition of CAISO Charges (i.e., the supplier will bear them, not MEA). Definition of Weighted Average Price: The Weighted Average Price is used to determine the price that MEA would pay/receive if it uses more/less energy than allowed under the Agreement. MRW recommends that MEA clearly define how this important factor is calculated. MEA agrees, and has held this issue open awaiting the MEA load profile data necessary to better understand the weighted average price. Responsibility for delivery of energy from unit -specific resources: Section 2.4 states "[For unit -specific Energy delivered hereunder pursuant to Section 2.4, Buyer shall be liable for all costs associated with delivering Energy from the generation point (the load aggregation point) to the Delivery Point and Seller shall assist Buyer (at Buyer's cost) with obtaining all Congestion Revenue Rights ("CRRs") required relating to the congestion from such generation point to the Delivery Point.]" (emphasis added). MEA indicates that it intends to bear the costs associated with transmitting power from any unit -specific generator approved by MEA to the Delivery Point. Per the discussion in Issue 1, above, MRW believes MEA should request pricing whereby (1) the supplier bear the costs of delivery from the unit - specific resource(s) to the Delivery Point, and (2) the supplier bears the cost of delivery from the unit -specific resource(s) to NP 15 EZ Gen Hub, just as it does for all system power being supplied under the Agreements. 2. Requirement to Supply "Baseline hourly volumes" (Section 5.2): The Confirmation now includes a new exhibit: Baseline hourly volumes. To date, all volumes have been either monthly or annual volumes. MRW does not understand the need for providing these data, since MRW understands that all purchase obligations are on a monthly or annual basis. MEA indicates that this will be deleted. Recommendation: MRW concurs with MEA that since no other sections of the Agreements reference baseline hourly volumes, this should be deleted. 3. Commercially Reasonable Efforts (Sections 7.1 and 7.2): The Confirmation now does not include a provision that the supplier will use "Commercially Reasonable Efforts" to minimize/maximize the costs/revenue associated with under -/over -use of non-renewable energy. The Confirmation states that the supplier will use Commercially Reasonable Efforts if it has to buy/sell additional renewable energy and other services (see Sections 7.3, 7.4, 8. 1, and 8.2). Recommendation: MEA should insist that the supplier use Commercially Reasonable Efforts in the case where it must buy or sell non-renewable energy to meet MEA's loads. MEA concurs and intends to include such language in the final version. MRW & Associates, LLC Exhibit Ila MEA Response to San Rafael Questions Page 1 Response to Question from San Rafael dated October 27, 2009 A key provision occurs under Section 7.1.1. According to the MCE calendar published on its website, the MEA Board will consider approval of the draft Program Services Agreement #1 (the Energy Service Provider (ESP) contract), at its November 5th Board meeting. To keep the jargon clear, I believe these documents are also referred to as the Power Purchase Agreement (PPA). For purposes of clarification, can you confirm the PPA includes ratifying the "EEI Master Power Purchase & Sale Agreement", "EEI Master Power Purchase & Sale Agreement Cover Sheet", and the "Confirmation"? Please list any additional documents that will be considered as part of the Board action on November 5th. ,'t,u have, -O redly listed all of the documents that were consirle.ffed for 2. Should the MEA Board ratify the ESP draft contract, then the 90 day period begins, running through the February 4th, 2010 MEA Board meeting, at which a final contract (documents noted in #1 above) will be approved. During this November 5th to February 4th review period, Section 7.1.1.1 of the JPA Agreement sets forth a minimum 30 day notice of withdrawal required for any agency that desires not to move forward with Program Agreement #1. If a member agency seeks to withdraw under this Section, what form of notice will suffice for MEA? Written notice is required but the form of the written notice Is riot spedfied. A Futter stating that action has been taken by the Council to �iC� =ria �uou''d be adequate under this provision, Will MEA require a resolution or some other form of official withdrawal action by member agencies? If February 4th is a hard and fast date for MEA Board action to ratify the final ESP contract, please provide specifics of how and when the 30 day noticing needs to occur. kj :iohi, the 0 day noticing otould occur on or before January 4 2010. lovever, the MEA BoaI'd rnav be € filling to aCCePt a withdrawal up to 0 days c...e.' :i -;.3i Cia`;s= it requested. 3. The County has now committed $500,000 under Section 6.3.2 as part of the initial funding to complete the CCAlMCE bidding process and award of contract. Section 6.3.3 allows for general costs to be `...be shared among the Parties on such basis as the Board shall determine pursuant to an Authority Document.' Should the MEA move forward on February 4, 2010, by approving the ESP contract, additional tasks to begin implementation are necessary. These will include the hiring of administrative services providers, successful development and acceptance of an implementation plan, and other start up activities. Please provide your current estimate of these costs. I'llerase see attached budget. Exhibit Ila MEA Response to San Rafael Questions Page 2 b. The approved business plan determined a line of credit or other lending mechanism would be needed for these start up costs. The risk/exposure for these enterprise start-up expenses appears to begin after February 4'", and up until the ESP begins to produce revenues for MEA. Can you also identify how the financing of start-up costs will work, and to what extent, if any, member agencies of MEA will be responsible for underwriting these costs? If for some reason the ESP contract fails to produce revenues, who would absorb what portion of the line of credit, and by what formula? €`bon-'rnember Hands aro being identified to c v ef. the initial al S` up on ca grant or loan basis. Thera would be no recourse tc agencies under the agreements being pl°sra.'.Lg,>OL 4. The enabling ordinance for MEA, Section 2.3, defines each member agency as not liable for the debts, liabilities and obligations of the Authority, unless otherwise noted. To what extent in the ESP contracts is this liability limitation further defined so as to avoid local member agency risks? I hO ESP Contract defines this. Slee the Gover heel pod. )n of the ,s,S,>" ,O ruder "Cather Changes" #S25 for the specific provision lief=ich iis as fr E "Party A hereby acknowledges and agrees that Panty S is or aniz d rs a Aothor'ty in accordance with the Joint Powers Act of the Stafe, r$ alh`orLia � ri .ode Section 51500 et seq.) pursuant too a Joint Povvei's 2008 (the ".Joint PovverAgreement'; and is a Public c-nc,r, sepa,roar its Party S shall safely be responsible for ali riebts tab ga#tunS and I ab,iRR?Sai r+a + :MO ansirg oat of this Agreement and Seller agreas that it shah have nnnghts, afjo make anv claim, take any actions or assert any rernediec aga,nisf any r_T' Ro! liv,, roembecs, in connection with this Agreement or any of the Transactions, 5. As part of the review and approval of the JPA ordinance and enabling agreement approved last fall, MRW and Associates completed a review of the Business Plan analysis. In my December 2008 staff report to the City Council, it was noted that subsequent to adoption the business plan, during the beginning months of the MEA, it should complete a quantitative risk analysis and plan in order to identify and mitigate risks. Has this work been completed? If so, where can the information be found? For purpose of reference, I have included the potential risks and issues I noted from last December below: rr"`- quantitative risk analysis was conducted as -Pie of tY k inidal rcvieiv1 rJ bids in July, 2009 and this analysis info rnied uM €EA' the selection of bidders. In addition, the peer _e ewv pros s,; c nd_ i -ed i;,, the € ity Managers in October 2009 included a sensitivity analyis 'v ii ", flaavigant Consulting which addresses the arca, blow This ari 1,t r r r infer-aed the development of the povoer purchase, , gree�ar nt tap , {a "ov it r= fVIEA Board on November 5, 2009, I -his, irn'orraatiun necds to fin corsildentlal but could be v9Et'w€d by specified vepr sent;ativ confidential basis. Exhibit Ila MEA Response to San Rafael Questions Page 3 a. Expected rates for MCE customers relative to PG&E b. Volatility of MCE rates relative to PG&E, and c. Cash flow risks for MCE. Responses should be clear in the areas of: d. Natural gas and wholesale power costs, and ability to meet the pricing goals for the "light green" and "dark green" options, e. Nature of "fixed" price bids from a third party power provider, f. Cost and performance of the renewable power project developed by the MCE in its fifth year of operation, g. Customer opt -out assumptions, and h. Customer migration between the 100% Green and the Light Green options. 6. As I understand your work, contract negotiation details continue to be refined through continuing negotiations between MEA and Shell. It seems almost weekly that new refinements are made the ESP Program #1 documents. As you and the MEA staff have been making the rounds to elected officials, city mangers and city attorneys, have you compiled a summary listing of key questions and responses relative to the RFP process, contract terms, etc.? If so, has this been distributed to all parties? h'rc,e v ro 4mula.iple improvements and revisions made tri'he draft con€ram' .:ler+ ugherO the monAh of October, As of November 5, 2009 the final draft i ¢ f'81 t vti,as approved and is no longer in flux. p'''lease see-` the FAO, ts,sc ,ad `..,±t i,Q e=n iy asked questions, and see the PowerPoint {at ached) °vhi �r,3 ryf nc.v/ erovmrons in the contract. Shell Energy North America is selected as first -position bidder for the ESP contracts. There remain two other 'second position' bidders who could also serve in this capacity. Am I correct in understanding that the draft contracts prepared for MEA Board consideration on November 5'h would not refer to any provider, but that a final ESP vendor will be listed in the February 4'h contract approval requests? "Yes. Additionally, I remain unclear as to how MEA will keep the other two bidders in the game while it continues to negotiate contract language and pricing with Shell, given MEA's apparent Spring 2010 deadline for concluding the negotiations. Please explain. i - 1, iop v , find draft Contract has been sent to all the full requirement's ita�i ,r ii{f , 3Ali %3ti�*rl i.,`,?` them to ut7$771t pricing under the I„'tYY C31 tht`.^. o � ,� pct in 1at� Janua,rv. Final contract approval is currently scheduled for SFeN Iiaiv 4, 2010. 8. AB32 - Page 4 of the PowerPoint presentation (in the November 5'h MEA Board packet) identifies AB32 costs to local jurisdictions if not pursuing MCE. This data supports a approach which is very compelling, but I can't figure out where these cost estimates for "compliance costs," whatever that term means, come from. Can you clarify the sources of these calculations, and how the results differ with or without MCE? Exhibit Ila MEA Response to San Rafael Questions Page 4 The source is from the California Air Oesources Board wnbsite and ._ by Varshney & Associates, September 2009. it is o alculei r:'s cn a, P( -,-r l`9$}E9.sF'hold basis and this was applied to 6?"ie iurriber or housei lel stt t drisdictions in Marin using census data. e a§9 E' the hilalin Ci n Program would result in an overall greenhouse gas rea. icl . n rf f r rd wnty of Morin, the prograrn would achieve 11of the LB .... a, ,. i9 would reduce the per household cost by two-thirds. 9. According to your October presentation, final PPA energy pricing will be done prior to contract signing. You noted that MEA will not execute the PPA if pricing does not support light green (25% renewable) generation cost at or below PG&E projected cost (based upon PG&E CPUC submittal of September 2009). a. City councils and the Board of Supervisors will be on the 90 day opt out track for Program Agreement #1, presumably beginning November 6`" What contractual assurances do MEA members and future customers have regarding the pricing goals noted above? A (esolution vvas by the MEA Board ora Novernber o, 2009 to assure pang c ,t achieved. How will this objective be captured, measured, and reported out by MEA? This objective will be captured, rntirasured and reperz `d ,Alt xi t .alb r, part of the audit process described in the contract. b. Are the price comparisons limited to the vendor costs of providing power, or is the PG&E comparison goal the fully loaded rates for electricity procurement (meaning the cost of the electricity procurement vendor, plus the dollars required to run MEA operations, etc)? The price comparisons include the fully loaded c. Has the ramping up of customer service to various categories (e.g. business, governments, residents) under the PPA remained the same as outlined in the business plan? If not, how has this changed, and what, if any, impact has this had on pricing and comparisons to PG&E rate competitiveness? The Municipal load will be included in phase 'l ;atuh; z rra= h.uw 0� -. residential and/or commercial brad included The final d cisiun v pha , will be determined alter final pricing come in, Ph_a,.e i will a. couira fo 2-u% of the load. The remaining 80% will be included in Phipse ll d. What is the minimum percentage of customers who must remain "in" (i.e., not 'opt out") in order for MEA to fulfill its pricing promises? 15 Megawats is the minimum percentage of customers v,jh , must in. The current load of the MEA jurisdictions is 1 70 W 1Ci:,r "vla`9ager- VtJrrkReToards & Committees\,1PA's\; /IEAVIVI^E\Bidding ,1 , October 27. 2009 Dawn Weisz, Interim Executive Director Marin Energy Authority C/O Marin County Community Development Department 3501 Civic Center Drive, Room #308 San Rafael, CA 94903 Dear Dawn: Exhibit IIb Mayor Albert J. Bore Council Members Greg Brockbank Damon Connolly Barbara Heller Cyr N. Miller Thanks to you and your Marin Energy Authority team for allowing member agencies to comment on the Marin Clean Energy (MCE) RFP process and the contracts that have been developed (in draft) relating to the procurement of energy for MEA member agencies and customers. Much activity has been occurred over these past few months concerning the MCE process. Over the last few weeks, you and the staff have met with our City Council to provide a summary of the contract terms. Additionally, meetings have been held with MEA agency managers and attorneys to discuss the proposed agreements and seek input regarding contract terms, risks, etc. I am now taking the time to frame some key questions to help assist our review process. Answers to these questions are necessary to help inform this important public policy decision here in San Rafael. The answers may also assist others in the coming months, when local City Councils will be asked to move forward with critical opt -out decisions related to the MCE contract. It is our hope that by raising questions and issues, thorough answers can assist all agencies -- as well as members of our communities -- in understanding the impacts, risks, and benefits of moving forward with a Marin Clean Energy contract. As a beginning point, I wish to refer to some issues raised at the time that the City of San Rafael chose to become a member of the Marin Energy Authority on December 1, 2008. A key provision occurs under Section 7.1.1. According to the MCE calendar published on its website, the MEA Board will consider approval of the draft Program Services Agreement #1 (the Energy Service Provider (ESP) contract), at its November 5`n Board meeting. To keep the jargon clear, I believe these documents are also referred to as the Power Purchase Agreement (PPA). For purposes of clarification, can you confirm the PPA includes ratifying the "EEI Master Power Purchase & Sale Agreement', "EEI Master Power Purchase & Sale Agreement Cover Sheet', and the "Confirmation"? Please list any additional documents that will be considered as part of the Board action on November 5`n 1400 Fifth Ave., P.O. Box 151560, San Rafael, CA 94915-1560 Phone: (415) 485-3070 Fax: (415) 459-2242 TDD: (415) 485-3198 MEA — MCE Bids and Contract Review 2 2. Should the MEA Board ratify the ESP draft contract, then the 90 day period begins, running through the February 4th, 2010 MEA Board meeting, at which a final contract (documents noted in #1 above) will be approved. During this November 5th to February 4th review period, Section 7.1.1.1 of the JPA Agreement sets forth a minimum 30 day notice of withdrawal required for any agency that desires not to move forward with Program Agreement #1. If a member agency seeks to withdraw under this Section, what form of notice will suffice for MEA? Will MEA require a resolution or some other form of official withdrawal action by member agencies? If February 4th is a hard and fast date for MEA Board action to ratify the final ESP contract, please provide specifics of how and when the 30 day noticing needs to occur. 3. The County has now committed $500,000 under Section 6.3.2 as part of the initial funding to complete the CCA/MCE bidding process and award of contract. Section 6.3.3 allows for general costs to be '... be shared among the Parties on such basis as the Board shall determine pursuant to an Authority Document.' a. Should the MEA move forward on February 4, 2010, by approving the ESP contract, additional tasks to begin implementation are necessary. These will include the hiring of administrative services providers, successful development and acceptance of an implementation plan, and other start up activities. Please provide your current estimate of these costs. b. The approved business plan determined a line of credit or other lending mechanism would be needed for these start up costs. The risk/exposure for these enterprise start-up expenses appears to begin after February 4th, and up until the ESP begins to produce revenues for MEA. Can you also identify how the financing of start-up costs will work, and to what extent, if any, member agencies of MEA will be responsible for underwriting these costs? If for some reason the ESP contract fails to produce revenues, who would absorb what portion of the line of credit, and by what formula? 4. The enabling ordinance for MEA, Section 2.3, defines each member agency as not liable for the debts, liabilities and obligations of the Authority, unless otherwise noted. To what extent in the ESP contracts is this liability limitation further defined so as to avoid local member agency risks? 5. As part of the review and approval of the JPA ordinance and enabling agreement approved last fall, MRW and Associates completed a review of the Business Plan analysis. In my December 2008 staff report to the City Council, it was noted that subsequent to adoption the business plan, during the beginning months of the MEA, it should complete a quantitative risk analysis and plan in order to identify and mitigate risks. Has this work been completed? If so, where can the information be found? For purpose of reference, I have included the potential risks and issues I noted from last December below: a. Expected rates for MCE customers relative to PG&E b. Volatility of MCE rates relative to PG&E, and c. Cash flow risks for MCE. Responses should be clear in the areas of.. d. Natural gas and wholesale power costs, and ability to meet the pricing goals for the "light green" and "dark green" options, MEA — MCE Bids and Contract Review 3 e. Nature of "fixed" price bids from a third party power provider, f. Cost and performance of the renewable power project developed by the MCE in its fifth year of operation, g. Customer opt -out assumptions, and h. Customer migration between the 100% Green and the Light Green options. Based upon your presentations to our City Council, along with contract reviews by me and my staff, some additional questions specifically related to the RFP process, bids and contract documents are listed below. 6. As I understand your work, contract negotiation details continue to be refined through continuing negotiations between MEA and Shell. It seems almost weekly that new refinements are made the ESP Program #1 documents. As you and the MEA staff have been making the rounds to elected officials, city mangers and city attorneys, have you compiled a summary listing of key questions and responses relative to the RFP process, contract terms, etc.? If so, has this been distributed to all parties? 7. Shell Energy North America is selected as first -position bidder for the ESP contracts. There remain two other 'second position' bidders who could also serve in this capacity. Am I correct in understanding that the draft contracts prepared for MEA Board consideration on November 5th would not refer to any provider, but that a final ESP vendor will be listed in the February 4th contract approval requests? Additionally, I remain unclear as to how MEA will keep the other two bidders in the game while it continues to negotiate contract language and pricing with Shell, given MEA's apparent Spring 2010 deadline for concluding the negotiations. Please explain. 8. AB32 - Page 4 of the PowerPoint presentation (in the November 5th MEA Board packet) identifies AB32 costs to local jurisdictions if not pursuing MCE. This data supports a approach which is very compelling, but I can't figure out where these cost estimates for "compliance costs," whatever that term means, come from. Can you clarify the sources of these calculations, and how the results differ with or without MCE? 9. According to your October presentation, final PPA energy pricing will be done prior to contract signing. You noted that MEA will not execute the PPA if pricing does not support light green (25% renewable) generation cost at or below PG&E projected cost (based upon PG&E CPUC submittal of September 2009). a. City councils and the Board of Supervisors will be on the 90 day opt out track for Program Agreement #1, presumably beginning November 6th. What contractual assurances do MEA members and future customers have regarding the pricing goals noted above? How will this objective be captured, measured, and reported out by MEA? b. Are the price comparisons limited to the vendor costs of providing power, or is the PG&E comparison goal the fully loaded rates for electricity procurement (meaning the cost of the electricity procurement vendor, plus the dollars required to run MEA operations, etc)? c. Has the ramping up of customer service to various categories (e.g. business, governments, residents) under the PPA remained the same as outlined in the business plan? If not, how has this changed, and what, if any, impact has this had on pricing and comparisons to PG&E rate competitiveness? MEA — MCE Bids and Contract Review 4 d. What is the minimum percentage of customers who must remain "in" (i.e., not "opt out") in order for MEA to fulfill its pricing promises? Dawn, once again I thank you for all of the meetings, information sharing, and effort you and your staff have poured into MEA, MCE, and the bidding process and contract review. Over the coming weeks, the City of San Rafael will be expecting answers to the above questions. We recognize some response details may not be known as of today. If that is so, knowing when specifics can be shared will all parties would be helpful. I would be glad to elaborate or clarify anything raised in this letter. Please call me at 485-3055 or contact me via e-mail at ken. nordhoffecitvofsanrafael.orq Sincerely, Ken Nordhoff City Manager cc: Mayor and City Council of San Rafael Rob Epstein, City Attorney Linda Jackson, Principal Planner W:\City Managers- WorkFile\Correspondence\Nordhoff\Letters\2009\MEA -MCE RFP & Bids.doc Exhibit III Marin Clean Energy "Renewable by Choice" A program of the Marin Energy Authority October 2009 mann energy autharity 1 Projected GHG emissions using PG&E methodology for 2010 Note: This slide does not include the GHG impacts of nuclear and large hydroelectric power 2010 Marin Energy Authority Greenhouse Gas Emissions ■ CO2 60% 40 ® Non -0O2 2010 PG&E Greenhouse Gas Emissions 51%0 1 49% E CO2 ® Non -CO2 2 1 Exhibit III Projected GHG emissions using PG&E methodology for 1 Note: This slide does not include the GHG impacts of nuclear and large hydroelectric power 2015 Marin Energy Authority Greenhouse 2015 PG&E Greenhouse Gas Ernissions Gas Emissions $89,293,097 a �y $78,935,073 $26,311,691 ,t o FM CO2 $21,355,818 E Non -0O2 IN Non -0O2 $19,325,720 $6,441,907 Larkspur $18,746,807 $6,248,936 Estimated AB 32 Compliance Cost by Community Community Compliance Costs without MCE Compliance Costs with MCE Marin County $108,099,199 $36,033,066 San Rafael $89,293,097 $29,764,361 Novato $78,935,073 $26,311,691 Mill Valley $21,355,818 $7,118,606 San Anselmo $19,325,720 $6,441,907 Larkspur $18,746,807 $6,248,936 Corte Madera $14,633,557 $4,877,852 Tiburon $13,687,946 $4,562,648 Sausalito $11,506,488 $3,835,496 Fairfax $11,405,062 $3,801,688 Ross $3,665,411 $1,221,804 Belvedere $3,326,801 $1,108,933 4 G Exhibit III Civic Rights and Responsibilities ■ As a member of MEA your agency, residents and businesses will be able to receive power under this contract. No further action is needed. ■ Your agency may withdraw from MEA if 30 - days notice is given before contract with energy supplier is executed ■ Contract is scheduled for execution on February 4, 2010 m9rin energy authority 6 3 GHG Reduction Sample Measures for Marin GHG Reduction Goal: 797,130 tons CO2e 800,000 Marin GHG Reduction 700,000 -__ __ _. _... Target 0 i. 600.000 o° h• m - - ... 500,000 _. ____ _- ____------- __-------- 0 r 400,000 ®2020 v' 300.000 _... 0 $ 200.000 V 100,000 Green Marin Energy Install Solar AB811 Marin Clean Building Watch Panels on Energy Standards Partnership Municipal Facilities 5 Civic Rights and Responsibilities ■ As a member of MEA your agency, residents and businesses will be able to receive power under this contract. No further action is needed. ■ Your agency may withdraw from MEA if 30 - days notice is given before contract with energy supplier is executed ■ Contract is scheduled for execution on February 4, 2010 m9rin energy authority 6 3 FoT.rew Power Purchase Agreement Development Process ■ May 2009: Request for Procurement (RFP) released ■ July 2009: 12 proposals received ■ August 2009: 3 finalists selected ■ September 2009: Negotiations with finalists ■ October 2009: Draft contract approved and released by MEA Board, presented to member agencies, peer review conducted ■ November 5, 2009: Final draft contract approved and released by MEA Board marin energy authority Draft Contract Under Extensive Review ■ Ad Hoc Contract Committee (McGlashan, Connolly, Thornton, Collins) ■ City Managers sub group and City Managers group ■ City and Town Attorneys ■ Ad Hoc Technical Committee ■ Third party peer review by MRW & Associates marin energy authority e rd Exhibit III Draft Contract Under Extensive Review Nine presentations have been made to member agencies in public Council/Board meetings as follows: ■ 10/5/2009 5:00 pm City of San Rafael ■ 10/6/2006 7:00 pm City of Sausalito ■ 10/7/2009 7:30 pm Town of Fairfax ■ 10/8/2009 6:30 pm Town of Ross ■ 10/12/2009 7:30 pm Town of Belvedere ■ 10/13/2009 10:00 am County of Marin ■ 10/19/2009 7:00 pm City of Mill Valley ■ 10/21/2009 7:30 pm Town of Tiburon ■ 10/27/2009 7:00 pm Town of San Anselmo mann energy authority 9 Professional Services Support ■ Navigant Consulting, Inc. ■ Technical Consulting/Implementation Support ■ Milbank, Tweed, Hadley & McCloy LLP ■ Power Supply Agreement Legal Counsel ■ Richards, Watson and Gershon LLP ■ General Counsel ■ Nixon Peabody LLP ■ Special Counsel 3 k marin energy authority 10 5 Exhibit III Draft Power Purchase Agreement (PPA) General Overview ■ Contract is based on the industry -standard Edison Electric Institute (EEI), Master Power Purchase and Sale Agreement ■ Five year delivery period, beginning on June 1, 2010 and ending on May 31, 2015 ■ Contract prices set at the beginning of the term rnarin energy authority u PPA Commercial Terms ■ Supplier will deliver all energy MEA needs, including: — Electric energy, including renewable energy content — Capacity, as required by the California Independent System Operator (CAISO) — Ancillary services, as required by CAISO and Scheduling coordination services ■ Guaranteed energy supply — No interruption of power due to provider failure — In case of provider failure, customers returned to PG&E at no cost to them (CPUC requires set aside bond to cover these costs) ■ MEA has responsibility for administrative and technical matters including: — Interfacing with the California Public Utilities Commission — Customer service related to MCE — Energy efficiency and solar program implementation — Rate setting and resource planning iz 0 Exhibit III PPA Key Requirement: No Recourse to Members ■ Contract insulates municipal funds/budgets before, during and after the delivery period — "Firewall' ensured by Section 25 of EEI Agreement, State law and the JPA Agreement ■ MEA credit support is limited to customer receipts/revenues marin energy authority 13 PPA Key Requirement: Competitive Pricing ■ Energy pricing will be refreshed prior to contract signing ■ MEA has approved a resolution to assure PPA will only be executed if pricing supports Light Green (minimum 25% renewable) generation cost at or below PG&E protected cost ■ MEA owned assets improve economics over time 1 marin energy authority 14 VA Exhibit III PPA Key Requirement: High Renewable Content ■ All MEA customers will receive at least 25% of energy deliveries from California Energy Commission eligible renewable resources (wind, solar, geothermal & others) ■ MEA customers will have a choice of energy products: — Light Green: At least 25% renewable content — Deep Green: 100% renewable content — Customers may choose to remain with PG&E: 15% renewable content ■ Coal and nuclear generated power will not be selected for either product marin energy authority is Contract Changes/Improvements ■ Phase 1 and phase 2 handled under separate confirmation agreements ■ Resource substitution defined to substitute renewable energy generated by MEA for contracted energy; MEA will work with counterparty to unwind contracted power ■ CCA Bond obligation shared marin energy authority 16 0 Exhibit III Contract Changes/Improvements ■ Ability to use pari passu structure for other resource needs including future bonds ■ Option to re -set volume on Aug. 31 post opt -out ■ Completion of extraneous documents before execution ■ Semi -Annual Audit/Reconciliation related to risk mitigation and assurance of RPS compliance. marin energy authority 17 Long Term Objective: Owned Renewable Assets ■ MEA will negotiate future contracts prior to initial contract expiration and substitute in new assets, ensuring seamless energy delivery ■ 150-200 MW CA certified renewables projected to be on line by 2014. ■ MEA will invest in local and regional renewable projects targeting 100% renewable content by 2016 18 Exhibit III Contract Pricing $230.00 / $180.00 -- / r / y,,,.-` Light Green $130.00 $80.00 Year Year Year Year Year Year Year. 10 15 20 25 30 Note: This assumes a 3.4% rate increase for PG&E, their average rate increase over the last 10 years. It assumes a 3% rate increase for MEA through Year 6 and a 2% increase for MEA after Year 6 19 10 Exhibit III Projected Schedule October 2009 - June 2010 8 marin energy n authority rafg.niraot"aPl�-��'ea Gy ME;ta'�wL.. .. releaaea L mem�erkgsnctes awd3he gubfl� 4o1Q'berl Loop -out to each city/town council and BOS to October 2 — 30 solicit feedback : onareftcontrect `Mt=�cBbardap�mved%rratdrak�unt���-.,µ_ i3avem"becr- 90-day review period of MEA approved final draft contract; Final loop -out to each city/town council November 5 —February 4 final nal'off-rampfor cities and towns MEA,i3oard exe�0tga flnai eonfl'a_df Febeuar�4, �Ot6 Service to Phase 1customers begins June 1, 2010 Questions? All documents are available at these websites: www.marinenergyauthority.org www. marincleanenergy. info rnann energy autharity zz 11 Exhibit III A Brief History Phase 1 (2003-2005) completed tasks: ✓ Feasibility Study ✓ Peer Review of Feasibility Study ✓ Bond Counsel/Legal Review ✓ Risk Analysis Phase II (2005-2008) completed tasks: ✓ Formation of Local Government Task Force ✓ Local Renewables Analysis ✓ Business Plan ✓ Peer Reviews of Business Plan by Task Force and City Managers mann energy authority F r MCE Objectives ■ High Renewable Content — Light Green Option: 25-50% renewable content — Deep Green Option: 100% renewable content ■ Local Renewable Development: Ensures local focus in development of renewable energy projects ■ Local Programs: SEED Program, other energy efficiency and rooftop solar programs ■ Customer Choice — Light Green, Deep Green or PG&E Ftr Marin energy authority 24 12 Exhibit III Committees of the Board ■ Executive Committee (McGlashan, Connolly, Tremaine, Marshall) • Agenda review • Policy advice • Legislative and regulatory analysis ■ Technical Committee (Connolly, Thornton, Tremaine, Martin) • Request for Procurement and Power Supply Contract • PG&E proposal review • Review of other AB32 related programs ■ Ad Hoc Contract Committee (McGlashan, Connolly, Thornton, Collins) • Power Supply Contract • Contract negotiations mann energy authority zs Ad Hoc Technical Advisory Group Expertise ■ Ruth McDougall, Renewable Energy Procurement Manager, Sacramento Municipal Utility District (SMUD), retired • Municipal Utility Energy Procurement & Operations ■ Bill Kissinger, Partner, Bingham McCutchen, LLP • Legal, Finance, Power Purchase Agreements ■ Peter Luchetti, Founding Partner, Table Rock Capital, LLC • Finance, Renewable Energy Issues, Infrastructure ■ Tom Delaney, Account Manager Customer Services & Industry Affairs, California Independent System Operator (CAISO) • Transmission, Capacity, Distribution ■ Wally McOuat, Founder, HMH Energy Resources, Inc. • Finance, Project Development ■ Tom Sweet, Senior Engineer, URS Corporation • Power/Energy Industry Engineering, Design, Technology 26 13 Exhibit III Average Marin PG&E Bill ACCOUNT SUMMARY 061092009-07108!2009 Efeoule Charges $85.58 Service Service Dates Amount Gas 06/0912009 To 07108/2009 $11.32 Net Charges $85.58 Electric 06/09/2009 To 0710812009 $85.58 Please see definigons on Page 2 athe bill Energy Commission Tax 0.11 Gas PPP Surcharge 0.79 Disulbugon 28.97 TOTAL CURRENT CHARGES Public Purpose Programs 3.06 $97.80 Nuclear Decommissioning 0.15 Previous Balance 57.58 06119 Payment -Thank You 57.58- 7.58-TOTAL Energy Cost Recovery Amounty 1.80 Taxes and Other TOTALAMOUNT DUE DUE DATE - 07/29/2009 $97,80 27 What Is the Impact to MEA Customers? MEA customers continue to pay PG&E Bill. Generation charge will be remitted to MEA. cha ges 061092009-07108!2009 Efeoule Charges $85.58 Baseline Ouaneky 272.00000 Kwh Susan. Usage 520.00000 Kwh@$0.1 U57 Net Charges $85.58 The mn charges shown above include the following compommus). Please see definigons on Page 2 athe bill Generagon 880.08 Transmission 5.22 Disulbugon 28.97 Public Purpose Programs 3.06 Nuclear Decommissioning 0.15 DM Bond OmM. 238 Ongoing CTC 8.33 Energy Cost Recovery Amounty 1.80 Taxes and Other Energy commission Tax $0.11 TOTAL CHARGES $85.69 28 14 Exhibit IV MARIN ENERGY AUTHORITY COMMUNITY CHOICE AGGREGATION IMPLEMENTATION PLAN AND STATEMENT OF INTENT _ w= Marin energy authority December 2009 For copies of this document contact the Marin Energy Authority in San Rafael, California or visit www.marinenergyauthority.org CHAPTER 3 — Organizational Structure.................................................................................................................7 OrganizationalOverview.................................................................................................................................... 7 Governance............................................................................................................................................................ 8 Officers................................................................................................................................................................... 8 Committees............................................................................................................................................................ 8 Addition/Termination of Participation.............................................................................................................. 8 AgreementsOverview......................................................................................................................................... 9 JointPowers Agreement...................................................................................................................................... 9 ProgramAgreement No. 1................................................................................................................................... 9 AgencyOperations...............................................................................................................................................9 ResourcePlanning..............................................................................................................................................10 PortfolioOperations...........................................................................................................................................10 20 Operations & Local Energy Programs.............................................................................................................11 RateSetting..........................................................................................................................................................11 Financial Management/Accounting.................................................................................................................11 22 CustomerServices..............................................................................................................................................12 23 Legal and Regulatory Representation..............................................................................................................13 Rolesand Functions...........................................................................................................................................13 Staffing.................................................................................................................................................................14 CHAPTER 4 — Startup Plan and Funding.............................................................................................................16 StaffingRequirements........................................................................................................................................17 CapitalRequirements.........................................................................................................................................17 StartupActivities and Costs..............................................................................................................................18 StartupCost Summary............................................................................................................................18 EstimatedStaffing Costs..........................................................................................................................19 Estimated Administrative & General Expenses...................................................................................19 Utility Implementation and Transaction Charges...............................................................................19 Estimates of Third -Party Contractor Costs...........................................................................................19 FinancingPlan .....................................................................................................................................................19 WorkingCapital.......................................................................................................................................20 ProForma.................................................................................................................................................. 20 CHAPTER5 — Program Phase-In...........................................................................................................................21 CHAPTER 6 - Load Forecast and Resource Plan .................................................................................................22 Introduction......................................................................................................................................................... 22 ResourcePlan Overview.................................................................................................................................... 23 I December 2009 SupplyRequirements.........................................................................................................................................24 CustomerParticipation Rates............................................................................................................................24 46 CustomerForecast..............................................................................................................................................25 46 SalesForecast.......................................................................................................................................................26 CapacityRequirements......................................................................................................................................26 43 Renewable Portfolio Standards Energy Requirements................................................................................. 28 BasicRPS Requirements..........................................................................................................................28 44 RPSCompliance Rules............................................................................................................................. 28 Marin Energy Authority's Renewable Portfolio Standards Requirement........................................29 48 Resources............................................................................................................................................................. 30 PurchasedPower................................................................................................................................................ 30 RenewableResources.........................................................................................................................................30 Near -Term Renewable Potential............................................................................................................ 31 Medium and Long -Term Renewable Potential.................................................................................... 33 Planned Renewable Generation Resources...........................................................................................35 EnergyEfficiency................................................................................................................................................35 Baseline Energy Efficiency Potential Estimates....................................................................................36 CCA Program Energy Efficiency Goals.................................................................................................37 DemandResponse....................................................................................................................................38 DistributedGeneration...................................................................................................................................... 39 CHAPTER7 — Financial Plan..................................................................................................................................42 Description of Cash Flow Analysis..................................................................................................................42 46 Costof CCA Program Operations....................................................................................................................42 46 Revenues from CCA Program Operations......................................................................................................43 CashFlow Analysis Results.............................................................................................................................. 43 CCA Program Implementation Feasibility Analysis..................................................................................... 43 Marin Clean Energy Financings....................................................................................................................... 44 CCA Program Start-up and Working Capital (Phase 1)................................................................................44 CCA Program Working Capital (Phase 2).......................................................................................................45 48 Renewable Resource Project Financing........................................................................................................... 45 CHAPTER 8 - Ratesetting and Program Terms and Conditions........................................................................46 Introduction......................................................................................................................................................... 46 RatePolicies......................................................................................................................................................... 46 RateCompetitiveness.........................................................................................................................................46 RateStability........................................................................................................................................................47 Equity among Customer Classes......................................................................................................................47 Customer Understanding..................................................................................................................................47 RevenueSufficiency...........................................................................................................................................47 RateDesign.......................................................................................................................................................... 48 NetEnergy Metering.......................................................................................................................................... 48 Disclosure and Due Process in Setting Rates and Allocating Costs among Participants ......................... 48 CHAPTER 9 — Customer Rights and Responsibilities ................... Customer Notices........................................................................... Termination Fee.............................................................................. Customer Confidentiality.............................................................. Responsibility for Payment........................................................... CustomerDeposits......................................................................... CHAPTER 10 - Procurement Proc Introduction ................................. Procurement Methods ................ .................................................................... 50 .................................................................... 51 .................................................................... 52 .................................................................... 52 .................................................................... 53 ii December 2009 KeyContracts..................................................................................... Electric Supply Contract......................................................... Data Management Contract ................................................... Electric Supply Procurement Process ................................... Shell Energy North America .................................................. Constellation Energy Commodities Group ......................... Macquarie Cook Power Inc .................................................... Chapter 11— Contingency Plan for Program Termination .............. Introduction........................................................................................ Termination by Marin Clean Energy .............................................. Termination by Members................................................................. CHAPTER 12 — Appendices................................................................. ................. 54 ................. 54 ................. 55 ................. 56 ................. 56 ................. 57 ................. 57 ...................59 ................. 59 ................. 59 ................. 60 iii December 2009 The Marin Energy Authority ("MEA" or "Authority") is a public agency comprised of nine municipalities', located within the geographic boundaries of Marin County, formed for the purposes of implementing a community choice aggregation ("CCA") program and other energy-related programs targeting significant greenhouse gas emissions ("GHG") reductions. Member Agencies of the Authority include the cities of Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San Rafael, Sausalito and Tiburon and the County of Marin ("Members" or "Member Agencies"). This Implementation Plan describes the Authority's plans to implement a voluntary CCA Program for electric customers within the jurisdictional boundaries of its Member Agencies that currently take bundled electric service from Pacific Gas and Electric Company ("PG&E"). The CCA Program, which has been named Marin Clean Energy ("MCE" or "Program"), will give electricity customers the opportunity to join together to procure electricity from competitive suppliers, with such electricity being delivered over PG&E's transmission and distribution system. The planned start date for the Program is June 1, 2010 (subject to the final review and approval of the Authority's Board). All current PG&E customers within the Authority's service area will receive information describing the Program and will have multiple opportunities to express their desire to remain full requirement customers of PG&E, in which case they will not be enrolled in the Program. Thus, participation in the CCA Program is completely voluntary; however, customers, as provided by law, will be automatically enrolled unless they affirmatively elect to opt -out of the CCA Program. Implementation of MCE will enable customers within MEA's service area to take advantage of the opportunities granted by Assembly Bill 117 ("AB 117"), the Community Choice Aggregation Law. MEA's primary objective in implementing this Program is to increase utilization of renewable energy supplies and promote significant GHG emissions reductions by offering customers at least two new energy supply options: 1) 25 percent renewable content, which will be the default service option for participating customers; or 2) 100 percent renewable content. The prospective benefits to consumers include a substantial increase in renewable energy supply, stable and competitive electric rates, public participation in determining which technologies are utilized to meet local electricity needs, and local/regional economic benefits. Because providing retail electric service can be a complex undertaking and the Authority has no operational experience in procuring electricity for retail customers, the Authority will receive assistance from experienced energy suppliers and contractors in providing energy services to Program customers during the early years of program operations. Following a competitive solicitation process and subsequent contract negotiations, three qualified firms were selected for consideration as the Authority's initial energy services provider and scheduling coordinator. Information regarding the three shortlisted companies is contained in Chapter 10. The final supplier selection is scheduled to be made by the MEA Board in February 2010. 1 MEA's member municipalities include Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San Rafael, Sausalito, Tiburon and Marin County. 1 December 2009 MEA's Implementation Plan reflects a collaborative effort among the Authority, its Members, and the private sector to bring the benefits of competition and choice to Member residents and businesses. By exercising its legal right to form a CCA Program, the Authority will enable its Members' constituents to access the competitive market for energy services and obtain access to increased renewable energy supplies and resultant reductions in GHG emissions. Absent action by the Authority or its individual Members, most customers would have no ability to choose an electric supplier and would remain captive customers of their incumbent utility. The California Public Utilities Code provides the relevant legal authority for the Authority to become a Community Choice Aggregator and invests the California Public Utilities Commission ("CPUC" or "Commission') with the responsibility for establishing the cost recovery mechanism that must be in place before customers can begin receiving electrical service through the Authority's CCA Program. The CPUC also has responsibility for registering the Authority as a Community Choice Aggregator and ensuring compliance with basic consumer protection rules. The Public Utilities Code requires that an Implementation Plan be adopted at a duly noticed public hearing and that it be filed with the Commission in order for the Commission to determine the cost recovery mechanism to be paid by customers of the Program in order to prevent shifting of costs. Each of these milestones has been accomplished, and the Authority now submits this Implementation Plan to the CPUC. On December 3, 2009, the Authority, at a duly noticed public hearing, considered and adopted this Implementation Plan, through MEA Resolution No. 2009-10 (a copy of which is included as part of Appendix A). The Commission has established the methodology that will be used to determine the cost recovery mechanism, and PG&E now has approved tariffs for imposition of the cost recovery mechanism. Finally, each of the Authority s Members has adopted an ordinance to implement a CCA program through its participation in the Authority (copies of individual ordinances are included as Appendix A). Following the CPUC's certification of its receipt of this Implementation Plan and resolution of any outstanding issues, the Authority will take the final steps needed to register as a CCA prior to initiating the customer notification and enrollment process. Organization of this Implementation Plan The content of this Implementation Plan complies with the statutory requirements of AB 117. As required by PU Code Section 366.2(c)(3), this Implementation Plan details the process and consequences of aggregation and provides the Authority's statement of intent for implementing a CCA program that includes all of the following: ➢ Universal access; ➢ Reliability; ➢ Equitable treatment of all customer classes; and ➢ Any requirements established by state law or by the CPUC concerning aggregated service. 2 December 2009 The remainder of this Implementation Plan is organized as follows: Chapter 2: Aggregation Process Chapter 3: Organizational Structure Chapter 4: Startup Plan and Funding Chapter 5: Program Phase -In Chapter 6: Load Forecast and Resource Plan Chapter 7: Financial Plan Chapter 8: Ratesetting Chapter 9: Customer Rights and Responsibilities Chapter 10: Procurement Process Chapter 11: Contingency Plan for Program Termination Appendix A: Authority Resolution 2009-10 and Authority Member Ordinances Appendix B: Joint Powers Agreement The requirements of AB 117 are cross-referenced to Chapters of this Implementation Plan in the following table. AB 117 Cross References AB 117 REQUIREMENT IMPLEMENTATION PLAN CHAPTER Process and consequences of aggregation_ Cha ter 2: Aggregation Process Organizational structure of the program, Chapter 3: Organizational Structure its operations and funding Chapter 4: Startup Plan and Funding Cha ter 7: Financial Plan Ratesetting and other costs to participants Chapter 8: Ratesetting Chapter 9: Customer Rights and Res onsibilities Disclosure and due process in setting rates Chapter 8: Ratesetting and allocating costs among participants Methods for entering and terminating Chapter 10: Procurement Process agreements with other entities Participant rights and responsibilities Chapter 9: Customer Rights and Responsibilities Termination of the program Chapter 11: Contingency Plan for Program Termination Description of third parties that will be Chapter 10: Procurement Process supplying electricity under the program, including information about financial, technical and operational capabilities Statement of Intent Chapter 1: Introduction 3 December 2009 Introduction This chapter describes the background leading to the development of this Implementation Plan and describes the process and consequences of aggregation, consistent with the requirements of AB 117. Beginning in 2004, the County of Marin ("County"), each of the municipalities within its geographic boundaries' and the two water districts within the County began investigating formation of a CCA Program, pursuant to California state law, with the following primary objectives: 1) promoting use of renewable energy resources; 2) reducing GHG emissions in the region; 3) promoting energy efficiency; and 4) creating local economic benefits. A feasibility study for a CCA Program serving the region was completed in March 2005, and an independent review of the feasibility study and a supplemental risk analysis were completed in August 2005 and May 2006, respectively. After nearly a year of collaborative work by representatives of the participating municipalities, independent consultants, local experts and stakeholders, the participating municipalities released a business plan in April 2008, which described the planned organization, governance and operation of the CCA Program. Consistent with the business plans described organizational structure, the MEA was formed in December 2008 to implement the CCA Program and other energy-related programs targeting significant GHG reductions. As previously noted, Member Agencies of the Authority include the cities of Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San Rafael, Sausalito and Tiburon and the County of Marin. The proposed CCA Program, Marin Clean Energy, represents a culmination of planning efforts that are responsive to the expressed needs and priorities of the citizenry and business community within Marin. Through MCE, the Marin Energy Authority plans to expand the energy choices available to eligible customers, including the creation of a 100% renewable energy product. In effect, NICE would provide Marin residents and businesses with three electric service options, which include: 1) 100% renewable energy service; 2) 25% (minimum) renewable energy service; or 3) bundled energy service from the incumbent utility. It is MEA's long-term goal to supply its customers entirely with clean, renewable energy, subject to economic and operational constraints. Each of the Member Agencies has adopted an ordinance to implement a CCA program through its participation in the Authority. The final Implementation Plan was adopted at a duly noticed public hearing of the Authority on December 3, 2009. Process of Aggregation Before customers are enrolled in the Program, customers will receive two written notices in the mail, from the Authority, that will provide information needed to understand the Programs 2 The municipalities participating in CCA investigation and analysis included Belvedere, Corte Madera, Fairfax, Larkspur, Mill Valley, Novato, San Anselmo, San Rafael, Sausalito, Tiburon and Ross. 4 December 2009 terms and conditions of service and explain how customers can opt -out of the Program, if desired. All customers that do not follow the opt -out process specified in the customer notices will be automatically enrolled, and service will begin at their next regularly scheduled meter read date at least thirty following the date of automatic enrollment, subject to the service phase- in plan described in Chapter 5. The initial opt -out notices will be provided to the first phase of customers in March 2010. Initial opt -out notices will be provided to subsequent customer phases consistent with statutory requirements and based on schedule(s) determined by the Authority's Board of Directors — notices will be sent to customers in subsequent phases beginning 90 to 105 days prior to commencement of service or twice within 60 days of automatic enrollment. Follow-up opt -out notices will be provided within the first two months of service for each customer phase. Customers enrolled in the Program will continue to have their electric meters read and be billed for electric service by the distribution utility (PG&E). The electric bill for Program customers will show separate charges for generation procured by the Program and all other charges related to delivery of the electricity and other utility charges that will continue to be assessed by PG&E. After service cutover, customers will be given two additional opportunities to opt -out of the Program and return to the distribution utility (PG&E) following receipt of their first and second bills. Customers that opt -out between the initial cutover date and the close of the post enrollment opt -out period will be responsible for program charges for the time they were served by the Authority but will not otherwise be subject to any penalty for leaving the program. Customers that have not opted -out within thirty days of the fourth opt -out notice will be deemed to have elected to become a participant in the Program and to have agreed to the Program's terms and conditions, including those pertaining to requests for termination of service, as further described in Chapter 8. Consequences of Aggregation Rate Impacts Program customers will see no immediate changes in electric service other than the price and composition of their electric bills. Customers will pay the generation charges set by the Authority and no longer pay the costs of PG&E generation. Customers enrolled in the Program will be subject to the Program's terms and conditions, including responsibility for payment of all Program charges as described in Chapter 9. The Authority's rate setting policies described in Chapter 7 establish a goal of providing rates that are initially competitive (at or below) with the projected generation rates offered by the incumbent distribution utility (PG&E). The Authority will establish rates sufficient to recover all costs related to operation of the Program, and actual rates will be adopted by the Authority's governing board. Initial Program rates will be established following approval of the Authority�s inaugural program budget, reflecting final costs from the Program's energy supplier(s). The Authority's rate policies and procedures are detailed in Chapter 7. Information regarding final Program 5 December 2009 rates will be disclosed along with other terms and conditions of service in the pre -enrollment opt -out notices sent to potential customers. Once the Program gives definitive notice to PG&E that it will commence service, Program customers are not expected to be responsible in any way for costs associated with the utilities' future electricity procurement contracts or power plant investments. Certain pre-existing generation costs will continue to be charged by PG&E to CCA customers through a separate rate component, called the Cost Responsibility Surcharge or CRS. This charge is shown in PG&E's tariff, which can be accessed from the utility's website, and the costs are already included in rates currently paid. Renewable Energy Impacts A second consequence of the Program will be an increase in the proportion of energy generated and supplied by renewable resources. The resource plan includes procurement of renewable energy sufficient to meet a minimum of 25 percent of the Program's electricity needs. Customers of the Authority may voluntarily participate in a 100 percent renewable supply option. To the extent that customers choose to participate in this voluntary program, the renewable content of MEA's power supply would increase. Initially, this renewable energy will be met contractually, but may be complemented, at an indeterminate point in the future, by the development of new renewable generation resources by or for the Authority subject to then - current considerations (such as development costs, regulatory requirements and other concerns). Energy Efficiency Impacts A third consequence of the Program will be an increase in energy efficiency program investments and activities. The existing energy efficiency programs administered by the distribution utility are not expected to change as a result of the Authority forming the Program. CCA customers will continue to pay the Public Goods Charge ("PGC") to the distribution utility which fund energy efficiency programs for all customers, regardless of generation supplier. The energy efficiency investments ultimately planned for the Program, as described in Chapter 5, will be in addition to the level of investment that would continue in the absence of the Program. Thus, the Program has the potential for increased energy savings and a further reduction in emissions due to expanded energy efficiency programs. As planned, MEA will apply for administration of requisite PGC program funding from the CPUC to independently administer energy efficiency programs within its jurisdiction. 6 December 2009 This section provides an overview of the organizational structure of the Authority and its proposed implementation of the CCA program. Specifically, the key agreements, governance, management, and organizational functions of the Authority are outlined and discussed below. Organizational Overview The CCA program would be governed by MEA's Board of Directors ("Board"), appointed by the Members. MEA is a joint powers agency created in December 2008 and formed under California law. The County of Marin and eight municipalities within the geographic boundaries of the County that have elected to offer the Program to their constituents have become Members of MEA. The Marin Energy Authority is the CCA entity that will register with the CPUC, and it is responsible for implementing and managing the program pursuant to the Authority's Joint Powers Agreement ("JPA Agreement" or "Agreement"). The Program will be operated under the direction of a General Manager appointed by the Board. The General Manager will report to the Board comprised of one representative from each participating Member of MEA. Those who are eligible to serve as representatives on the Board will be elected officials from the then -current County Board of Supervisors (one Board representative will be selected from the County Board of Supervisors) and the City and Town Councils (one representative will be selected from each of the eight City and Town Councils) of the Members. The Board's primary duties will be to establish program policies, set rates and provide policy direction to the General Manager, who will have general responsibility for program operations, consistent with the policies established by the Board. The Board will also determine necessary staffing levels, individual titles and related compensation for the organization. The Board may also adjust staffing levels and compensation over time in response to varying workloads, specific programs and/or general responsibilities of MCE. The General Manager could be an employee of MEA, an individual under contract with MEA, a corporation, or any other person so designated by the Board. The Board will be responsible for evaluating the General Manager's performance and is ultimately responsible for hiring and terminating the General Manager. The Board has established a Chairman and other officers from among its membership and has established an Executive Committee and Technical Committee and may establish other committees and sub -committees as needed to address issues that require greater expertise in particular areas (e.g., finance or contracts). MCE may also establish an "Energy Commission" formed of Board -selected designees. The Energy Commission would have responsibility for evaluating various issues that may affect MCE and its customers, including rate setting, and would provide analytical support and recommendations to the Board in these regards. 7 December 2009 The General Manager will have responsibilities over the functional areas of Finance, Regulatory Affairs, and Operations. In performing his or her obligations to the Authority, the General Manager will utilize a combination of internal staff and contractors. Certain specialized functions needed for program operations, namely the electric supply and customer account management functions described below, will be performed initially by experienced third -party contractors. Governance MEA has a Board of Directors consisting of one representative from each of the Members. The Board meets at regular intervals to provide the overall management and guidance for MCE. All Board meetings will be public and held in accordance with the Ralph M. Brown Act. Decisions by MEA are under voting procedures defined in the JPA Agreement, attached hereto as Appendix B. All votes on a particular matter are subject to the two-tiered approval process described in the JPA Agreement. Officers MEA has a Chair and Vice -Chair elected to one-year terms by the Board of Directors. Both the Chair and Vice -Chair must be members of the Board. In addition, MEA will have a Board Clerk and Auditor; neither of which will be members of the Board of Directors. The JPA Agreement provides further detail with respect to each of these positions. Committees MEA may form an appointed Energy Commission, which would be comprised of Board designees from the Member communities. Appointments would be made based on various skill sets and expertise that will be useful in evaluating matters affecting MEA and its customers, specifically issues related to rate setting and other technical matters. The Energy Commission would provide the Board with recommendations and related analysis to support policy -level decisions of the Board. MEA may elect to have additional committees or working groups to address various topics. Any additional committees and their functions will be determined by the Board of Directors at the time each committee is created. AdditionlTermination of Participation The JPA Agreement provides for the addition of new participants subject to the affirmative vote of MEA's Board of Directors pursuant to the voting structure described in the Agreement. The Board will determine the specific terms and conditions under which a new Member can be admitted. A JPA Member can withdraw itself from the JPA subject to the specific terms and conditions contained in the JPA Agreement. December 2009 Agreements Overview There are two principal agreements that govern MEA and the initial operation of its CCA Program: the JPA Agreement and Program Agreement No. 1 (PA -1). Each of these agreements and its functions are discussed below. Joint Powers Agreement The JPA Agreement created MEA and delineates a broad set of powers related to the study, promotion, development, and conduct of electricity -related projects and programs. The JPA Agreement describes the Authority as having broad powers, but a very limited role without implementing agreements ("program agreements') to carry out specific programs. This structure is intended to provide flexibility for MEA to undertake other programs in the future that may be unrelated to CCA on behalf of all or a subset of MEA's Members. The Board will have limited decision making authority regarding land use within the Member communities. Any issues involving land use within Member communities will be raised with the potentially affected Member. The land use and building regulations of each Member shall apply to any JPA facilities located within the jurisdiction of that Member. Any amendments to the JPA Agreement will be subject to prior approval by the Board. The first program agreement or PA -1, discussed in greater detail below, would provide for electric generation service to customers of the CCA Program. At MEA's Members' discretion, future program agreements could provide for other energy related programs. Program Agreement No. l PA -1 consists of three components: 1) the Edison Electric Institute ("EEI") Master Power Purchase & Sale Agreement ("Master EEI Agreement"), which is a standard industry contract used by public and private utilities across the United States; 2) the EEI Master Power Purchase & Sale Agreement Cover Sheet, which provides additional detail related to MEA's specific transaction, identifying exceptions, clarifications and areas of applicability that modify the standard terms and conditions of the Master EEI Agreement; and 3) the Confirmation, which is referenced in the Master EEI Agreement and defines the commercial terms of MEA's transaction. PA -1 is the agreement under which MEA will procure all necessary electric supply services for MCE customers. As drafted, PA -1 specifies a five year delivery period, commencing on June 1, 2010 and ending on May 31, 2015. PA -1 specifies a full requirements energy product, including all electric energy, renewable energy, capacity, ancillary services and scheduling coordination services. Based on contract negotiations, PA -1 will specify fixed annual prices for each year of the delivery period and will insulate municipal funds/budgets of the Member Agencies before, during and after the delivery period. It is anticipated that PA -1 will be executed by MEA and its energy supplier(s) on or around February 4, 2010. Agency Operations The Authority will conduct program operations through its own internal staff and through contracting for services with third parties. MEA will have its own General Counsel to manage 9 December 2009 its legal affairs. MEA's General Manager will have responsibility for day-to-day operations of the Program. To assist the General Manager, MEA will hire a full-time Administrative Assistant who will also serve as Board Clerk. Other staff positions that may be added as necessary include positions in finance, customer services, energy efficiency and other local energy programs, and operations. Major MCE functions that will be performed and managed by the General Manager are summarized below. Resource Planning MEA is charged with developing both short (one and two-year) and long-term resource plans for the program. The General Manager will manage staff and contractors to develop the resource plan under the guidance provided by the Board and in compliance with California Law, and other requirements of California regulatory bodies (CPUC and CEC). Long-term resource planning includes load forecasting and supply planning on a ten- to twenty-year time horizon. MEA's CCA planners will develop integrated resource plans that meet program supply objectives and balance cost, risk and environmental considerations. Integrated resource planning considers demand side energy efficiency and demand response programs as well as traditional supply options. The CCA Program will require an independent planning function even if the day-to-day supply operations are contracted to a third party energy supplier. Plans will be updated and adopted by the Board on an annual basis. Portfolio Operations Portfolio operations encompass the activities necessary for wholesale procurement of electricity to serve end use customers. These highly specialized activities include the following: ➢ Electricity Procurement — assemble a portfolio of electricity resources to supply the electric needs of program customers. ➢ Risk Management — standard industry techniques will be employed to reduce exposure to the volatility of energy markets and insulate customer rates from sudden changes in wholesale market prices. ➢ Load Forecasting — develop accurate load forecasts, both long-term for resource planning and short-term for the electricity purchases and sales needed to maintain a balance between hourly resources and loads. ➢ Scheduling Coordination — scheduling and settling electric supply transactions with the CAISO. MEA will initially contract with an experienced and financially sound third party to perform most of the portfolio operation requirements for the CCA Program. These requirements include the procurement of energy and ancillary services, scheduling coordinator services, and day - ahead and real-time trading. PA -1 is the contractual instrument that has been developed for this purpose; additional detail related to PA -1 is provided in the preceding discussion. 10 December 2009 MEA will approve and adopt a set of Program Controls that will serve as the risk management tools for the General Manager and any third party involved in the program's portfolio operations. Program Controls will define risk management policies and procedures and a process for ensuring compliance throughout the organization. During the initial startup period, the chosen full requirements electric supplier will bear the majority of program operational risks, pursuant to the terms and conditions of PA -1. Operations & Local Energy Programs A key focus of the CCA Program will be the development and implementation of local energy programs for its Members, including energy efficiency programs, distributed generation programs and other energy programs responsive to Member interests. The General Manager will be responsible for further development of these Programs. To assist the General Manager in this regard, MEA will initially hire a full-time Director of Operations & Local Energy Programs. Over time, MEA may hire up to three full-time Project Coordinators to administer these programs, develop energy efficiency marketing strategies, perform customer outreach and conduct related analyses to support chosen courses of action. As experience is gained from the retail energy side of the CCA Program, MEA will continue enhancing its local energy programs to achieve MEA's desired goals and objectives. MEA will administer energy efficiency, demand response and distributed (solar) generation programs that can be used as cost-effective alternatives to procurement of supply-side resources. MEA will attempt to consolidate existing demand side programs into this organization and leverage the structure to expand energy efficiency offerings to customers throughout its service territory, including the CPUC application process for third party administration of energy efficiency programs and use of funds collected through the existing public goods surcharges paid by NICE customers. Rate Setting The Board of Directors has the ultimate responsibility for setting the electric generation rates for the Programs customers. The General Manager in cooperation with the Assistant General Manager of Finance and appropriate advisors, consultants and committees of the Board will be responsible for developing proposed rates and options for the Board to consider before finalization. The final approved rates must, at a minimum, meet the annual revenue requirement developed by the General Manager, including any reserves or coverage requirements set forth in bond covenants. The Board will have the flexibility to consider rate adjustments within certain ranges, provided that the overall revenue requirement is achieved; this provides an opportunity for economic development rates or other rate incentives. Financial Management/Accounting The General Manager in cooperation with the Assistant General Manager of Finance will be responsible for managing the financial affairs of NICE, including the development of an annual budget and revenue requirement; managing and maintaining cash flow requirements; potential 11 December 2009 bridge loans and other financial tools; and a large volume of billing settlements. The General Manager will use contractors and/or staff in support of these activities, as appropriate. The Finance function arranges financing for capital projects, prepares financial reports, and ensures sufficient cash flow for the Program. This function also plays an important role in risk management by monitoring the credit of suppliers so that credit risk is properly understood and mitigated by the Program. In the event that changes in a supplier's financial condition and/or credit rating are identified, the Program will be able to take appropriate action, as would be provided for in the electric supply agreement. The Finance function establishes credit policies that the program must follow. The retail settlements (customer billing) would be contracted out to an organization with the necessary infrastructure and capability to handle approximately 71,000 accounts during full Program phase-in, which is scheduled to occur by January 2012. This function is described under Customer Services, below. Customer Services In addition to general program communications and marketing, a significant focus on customer service, particularly representation for key accounts, will be necessary. This will include both a call center designed to field customer inquiries and routine interaction with customer accounts. The General Manager in cooperation with the Director of Customer Relations & Marketing will be responsible for the Customer Services function and will use staff and/or contractors in support of these activities as appropriate. The Customer Account Services function performs retail settlements -related duties and manages customer account data. It processes customer service requests and administers customer enrollments and departures from the Program, maintaining a current database of customers enrolled in the Program. This function coordinates the issuance of monthly bills through the distribution utility's billing process and tracks customer payments. Activities include the electronic exchange of usage, billing, and payments data with the distribution utility and MCE, tracking of customer payments and accounts receivable, issuance of late payment and/or service termination notices, and administration of customer deposits in accordance with MCE credit policies. The Customer Account Services function also manages billing related communications with customers, customer call centers, and routine customer notices. MEA will initially contract with a third party, who has demonstrated the necessary experience and administers appropriate computer systems (customer information system), to perform the customer account and billing services functions. MEA will conduct Program marketing and key customer account management functions. These responsibilities include the assignment of account representatives to key accounts, which will ensure high levels of customer service to these businesses, and implementation of a 12 December 2009 marketing strategy to promote customer satisfaction with the CCA Program. Ongoing communications, marketing messages, and information regarding the CCA Program to all customers will be critical for the overall success of the CCA Program. Legal and Regulatory Representation The CCA Program will require ongoing regulatory representation to file resource plans, resource adequacy, compliance with California RPS, and overall representation on issues that will impact MEA, its Members and MCE customers. MEA will maintain an active role at the CPUC, CEC, and, as necessary, FERC and the California legislature. Day-to-day analysis and reporting of pertinent legal and regulatory issues will be completed by the Program's Director of Regulatory Affairs and/or qualified contractors. MEA will retain legal services, as necessary, to administer MEA, review contracts, and provide overall legal support to the activities of MEA. Roles and Functions The Board will perform the functions inherent in its policy-making, management and planning roles. MEA is the public face of the Program and will have a direct role in marketing, communications and customer service. Other highly specialized functions, such as energy supply and account management, will be contracted out to third parties with sufficient experience, technical and financial capabilities. The functions that will initially be performed by MEA's Board of Directors, the General Manager and third parties are specified below: 13 December 2009 Organization Roles/Functions/Activities MEA Board of Directors ExecutivelPolicylLegal General Manager Finance Legal and Regulatory - Legal support - Participation in regulatory proceedings - Regulatory reporting Marketing/Communications Rates & Support - Rate policy - Rate design - Cost-of-service planning Resource Planning - Load research - Load forecasting - Su 1-sidelDemand side portfolio planning Contract Management — RFPIRFQ Customer Service - Account representatives - Energy a iciencn lDG program management Energy Supplier Supply Operations - Procurement - Scheduling coordination - Settlements (ISOAVholesale) - Short-term loadjorecasting Customer Account Services ProviderlData Account Management (Customer Information System) Manager - Customer switching - New customer processing - Data exchange (EDI) - Payment processing (ARIAP) - Billing and retail settlements - Call center Staffing Staffing requirements for the above MCE functions are approximately twenty and one-half full time equivalent positions, once the customer phase-in is complete and the program is fully operational. These staffing requirements are in addition to the services provided by the third party energy suppliers and the data manager. The General Manager will have discretion whether to internally staff these required functions or to contract for these services. 14 December 2009 The following table shows the staffing plan for Marin Clean Energy at initial full-scale operational levels, following full phase-in. Customer service for the mass market residential and small commercial customers will be provided by the Programs third party customer account services provider. Staffing Plan for Marin Clean Energy Community Choice Aggregation Program Position Staff (Full Time Equivalents) Management General Manager 1.0 Policy Analyst 1.0 Administrative Assistant 1.0 Finance and Rates Assistant General Manager of 1.0 Finance Rates Analyst 1.0 Accounting/BillingAccounting/Billing Analyst 1.0 Sales and Marketing Director of Customer Relations 1.0 & Marketing Account Representative 4.0 Communications Specialist 1.0 Administrative Assistant - 1.0 Operations & Local Energy Programs Director of Operations & Local Energy Programs 1.0 Project Coordinators 3.0 Regulatory Director of Regulatory Affairs 1.0 Regulatory Analyst 1.0 Information Technology ITSpecialist 1.0 Human Resources HRSpecialist 0.5 Total Staffing 20.5 Longer-term staffing needs will include additional energy efficiency and distributed generation activities and potentially the creation of an internal organization to perform the portfolio operations and account services functions that will originally be contracted out. 15 December2009 This Chapter presents the Authority's plans for the start-up period, including the necessary staffing and capital outlays, which will commence once the CPUC certifies its receipt of this Implementation Plan. As described in the previous Chapter, the Authority will utilize a mix of staff and contractors in its CCA Program implementation. The following table illustrates the expectations for start-up, near-term (two to five years), and long-term anticipated staffing roles. Expectations for Staffing Roles 16 December 2009 Near -Term Function Start -Up (2 to 5 Years) Long -Term Program Governance MEA Board MEA Board MEA Board Program Management MEA GM MEA GM MEA GM Outreach MEA GM MEA GM MEA GM Customer Service MEA GM MEA GM MEA GM Key Account MEA GM MEA GM MEA GM Management Regulatory Third Party MEA GM MEA GM (MEA GM (Regulatory (Regulatory support) Analyst so ort) Analyst support) Legal MEA GM MEA GM MEA GM Finance MEA GM MEA GM MEA GM Rates: Approve MEA Board MEA Board MEA Board Develop MEA GM (third MEA GM (third MEA GM Party support) Party support) Resource Planning Third Party MEA GM (third MEA GM (MEA GM party support) support) Energy Efficiency MEA GM MEA GM MEA GM (third Party (Program Energy (Program Energy Support) Efficiency Staff) Efficiency Staff) Resource Development MEA GM (third MEA GM (third MEA GM party support) party support) Portfolio Operations Third Party Third Party MEA GM (MEA GM support) Scheduling Coordinator Third Party Third Party Third Party (potentially MEA GM) Data Management Third Party Third PartyThird Party (potentially MEA GM) 16 December 2009 Staffing Requirements Staff will be added incrementally to match workloads involved in forming the new organization, managing contracts, and initiating customer outreach/marketing during the pre - operations period. During the startup period, minimal staffing requirements would include a General Manager, an Assistant to the General Manager, an Assistant General Manager of Finance, a Director of Customer Relations & Marketing, a Director of Operations & Local Energy Programs and a Project Coordinator (6 full time equivalent positions). MEA will hire the General Manager, Assistant to the General Manager, Assistant General Manager of Finance, a Director of Customer Relations & Marketing, a Director of Operations & Local Energy Programs and Project Coordinator as its direct staff but may choose to fill all other necessary positions with staff and/or contractors at the discretion of the General Manager and MEA's Board. Following these initial staffing efforts, additional staff and/or contractors will be added during the Phase 1 customer enrollment period and following commencement of service to Phase 1 customers. The organization should be nearly fully staffed by the time the Phase 2 (and any subsequent phases, as necessary) customers are enrolled. Actual staff will be dependent upon several factors, including the ability to recruit and hire qualified staff and personnel policies ultimately established by the General Manager and the Board of Directors. Capital Requirements The Start-up of the CCA Program will require capital for three major functions: (1) staffing and contractor costs; (2) program initiation; and (3) working capital. Each of these and the anticipated requirement is discussed below. The Finance Plan in Chapter 7 provides a detailed overview of the capital requirements. Staffing costs for calendar year 2010 are estimated to be approximately $940,000. Actual costs may vary depending on the ability of MEA to recruit qualified staff to fill the roles described above. Contractor costs for the same time period are estimated to be approximately $1.6 million. These costs include: public relations, marketing/advertising, consulting, legal, and data management services. Program initiation costs include administrative and general expenses of MEA as well as the distribution utility fees for initiating the CCA Program. Administrative and general expenses are estimated to be approximately $165,000 and the distribution utility fees, which include CCA Bond requirements and a service deposit, are estimated to be approximately $265,000. Therefore, the total staffing, contractor and program initiation costs are expected to be approximately $2.9 million in 2010. These are costs that ultimately will be collected through CCA Program rates; however, some of these costs will be incurred prior to the Authority selling its first kWh of electricity. In addition, as discussed in Chapter 7 (Financial Plan), it is anticipated that additional working capital will be required to purchase electricity for Program customers prior to revenue being collected from those customers. The amount of financing required to support the CCA Program through the start-up and initial phase-in period, including working capital and net of revenues received from energy sales 17 December 2009 during Phase 1, is estimated to be $2.0 million. The actual amount of financing required will be primarily dependent upon power purchase requirements. Short-term financing instruments, such as a letter of credit or commercial paper will be used to cover these start-up costs and working capital requirements not otherwise covered by other capital infusions. Startup Activities and Costs The initial startup funding estimate of $2.0 million is budgeted to fund the following activities and costs: ➢ Define and execute communications plan • Media campaign • Informational materials and customer notices • Customer call center ➢ Hire staff ➢ Negotiate supplier/vendor contracts • Electric supplier • Data management provider ➢ Pay utility service initiation, notification and switching fees ➢ Perform customer notification, opt -out and transfers ➢ Conduct load forecasting ➢ Finalize rates ➢ Legal and regulatory support ➢ Financial reporting ➢ General consulting costs Other costs related to starting up the program will be the responsibility of the Program's contractors. These include capital requirements needed for collateral/credit support for electric supply expenses, customer information system costs, electronic data exchange system costs, call center costs, and billing administration/settlements systems costs. Startup Cost Summary Monthly costs associated with program startup and phasing of customer enrollments are shown below for program staff, associated administrative and general expenses, contractor costs and fees payable to the distribution utilities for CCA implementation and transactions costs. The estimated startup costs include capital expenditures and one-time expenses as well as ongoing expenses during calendar year 2010. is December 2009 Estimated Start-up Costs Shat -up coals Start -0p Phase 3 Operations Stalling Jan -10 Feb -10 Mar -10 Ap,40 Ma,10 Jun -ID Jul -lo AogdO Sep49 Orldo Nov -10 Der40 FM 2 4 7 7 6 6 6 6 6 6 6 Cast $ 40,583 $ 60,833 $ 104,583 $ 104,583 $ 90,000 $ 90,000 $ 90,000 $ 90,000 $ 90,000 $ 90,000 $ 90,000 Administrative & General Cwt $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,00(1 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 Cmrtrartor Costa MarketingUmmwientians $ 40,000 $ 40,000 $ 40,000 $ 40,000 $ 40,00D $ 40,000 $ 40,000 $ 15,000 $ 15,000 $ 15,090 $ 15,000 Consulting $ - $ 145,000 $ 50,000 $ 60,000 $ 60,000 $ 60,000 $ 60,000 $ 60,00D $ 60,000 $ 60,00 $ 60,000 Legal $ 40,000 $ 40,000 $ 40,000 $ 40,000 $ 40,000 $ 40,000 $ 40,000 $ 40,D00 $ 40,000 $ 40,000 $ 40,000 Wta Management $ $ 10,900 $ 10,000 $ 19,999 $ 10,900 $ 10,090 $ 10,909 $ 10,990 $ 10,099 $ 10,000 $ 10,900 Subrotal Contractor Cwt. $ 80,000 $ 235,000 $ 140,000 $ 150,000 $ 150,000 $ 150,000 $ 150,000 $ 125,000 $ 125,000 $ 125,000 $ 125,000 100 Fres (lacludingBiliin6) Cost $ $ 185,090 $ 5,000 $ 5,000 $ 10,009 $ 10,000 $ 10,000 $ 10,000 $ 10,000 $ 10,000 $ 10,000 Grand Total $ 135583 $ 495,033 $ 264,583 $ 274$83 $ 265,000 $ 265,000 $ 265,000 $ 240,000 $ 290,000 $ 290,000 $ 240,000 Estimated Staffing Costs Staffing budgets include direct salaries and benefits loading. MEA anticipates funding six full- time positions during initial phase-in, including a General Manager, an Assistant to the General Manager, an Assistant General Manager of Finance, a Director of Customer Relations & Marketing, a Director of Operations & Local Energy Programs and a Project Coordinator. Estimated Administrative & General Expenses Administrative and general expenses needed to support the organization include computers and peripheral equipment, office furnishings, office space and utilities. Office space and utilities are ongoing monthly expenses that will begin to accrue before revenues from Program operations commence and are therefore assumed to be financed along with other startup costs. Utility Implementation and Transaction Charges The estimated costs payable to the distribution utilities for services related to the CCA Program start-up period include costs associated with initiating service with the Authority, providing data, processing of customer opt -out notices, customer enrollment, post enrollment opt out processing, and billing fees. Most of the distribution utility fees are explicitly stated in the relevant CCA tariffs. Estimates of Third -Party Contractor Costs Contractor costs include outside assistance for marketing/public relations/customer communications, legal services, resource planning, implementation support customer enrollment, customer service, and payment processing/accounts receivable and verification. The latter three will be provided by the Program's customer account services provider, and these preliminary estimates will be refined as the services and costs provided by the selected contractor are negotiated. Financing Plan The initial start-up funding will be provided by MEA via a short-term financing, likely a credit line that can be drawn upon as needed to cover expenditures. MEA will recover the principal and interest costs associated with the start-up funding via retail rates. It is anticipated that the start-up costs will be fully recovered within the first few years of the Program operations through retail rates. 19 December 2009 Working Capital Operating revenues from sales of electricity will be remitted to the Authority beginning on approximately day 47 of program operations, based the distribution utility's standard meter reading cycle of 30 days and its payment/collections cycle of 17 days. MEA will be responsible for providing the working capital needed to support electricity procurement as well as the working capital requirements related to program management, which will be included in the financing program associated with start-up funding. Pro Forma Ongoing operating expenses will be recovered from revenues accruing from sales of electricity to Program customers and, where applicable, sales of excess power to other entities. Pro forma projections for the initial six years of program operations are shown in Chapter 7 below. 20 December 2009 The Authority will phase-in the customers of its CCA Program over the course of two or more phases: Phase 1. MEA Member (municipal) accounts & a subset of residential, commercial and/or industrial accounts, comprising approximately 20 percent of total customer load. Phase 2. Remaining accounts, subject to economic and operational considerations. Phase 3. All remaining accounts, if necessary. This approach provides the Authority with the ability to start slow, address any problems or unforeseen challenges on a small manageable program before gradually building to full program integration for an expected customer base of approximately 71,000 accounts. This approach also allows the Authority and its energy supplier(s) to address all system requirements (billing, collections, payments) under a phase-in approach to minimize potential exposure to uncertainty and financial risk by "walking' prior to ultimately "running". MEA will offer service to all customers on a phased basis expected to be completed within twenty four months of initial service to Phase 1 customers. Phase 1 of the Program is targeted to begin on June 1, 2010. During Phase 1, MEA anticipates serving approximately 7,500 accounts totaling nearly 160 GWh. MEA is currently analyzing the potential composition of Phase 1 accounts in consideration of opportunities for maximizing energy efficiency and renewable energy impacts, synergies with local ordinances and other customer programs such as a planned municipally financed solar program, cost of service and customer load characteristics, and other operational considerations. Specific accounts to be included in Phase 1 will approximate 20 percent of MEA's total customer load and will be specifically defined after further analysis and consideration of the Board. The Board may, at its discretion, determine to expand Phase 1. Phase 2 of the Program will commence following successful operation of the Program over a minimum 12 -month term. Following this initial operating period, expected to continue for no more than 24 months, the Board will commence the process of completing the full roll out of the Program to all remaining customers in Phase 2. The Board may evaluate other phase-in options based on then -current market conditions, statutory requirements and regulatory considerations as well as other factors potentially affecting the integration of additional customer accounts. 21 December 2009 Introduction This Chapter describes MCE's proposed ten -yeas integrated resource plan, which would create a highly renewable, diversified portfolio of electricity supplies capable of meeting the electric demands of MCE's retail customers, plus sufficient reliability reserves. This integrated resource plan reflects a long-term, programmatic goal of 100 percent renewable energy supply. Within five years of program commencement (2015), this significant commitment to renewable resources is projected to result in MCE meeting over 60 percent of its total electric needs through renewable resources. As the Program moves forward, incremental renewable supply additions will be made based on resource availability as well as economic goals of the Program. MCE's aggressive commitment to renewable generation adoption may involve both direct investment in new renewable generating resources through partnerships with experienced public power developers/operators, significant purchases of renewable energy from third party suppliers and, potentially, the purchase of Renewable Energy Certificates ("RECs") from the market. The resource plan also sets forth ambitious targets for improving customer side energy efficiency as well as for potential deployment of approximately 12 MW of new distributed solar capacity within the jurisdictional boundaries of MCE by 2019 (year ten of Program operations). The plan described in this section would accomplish the following by 2019: ➢ Procure energy needed to offer two generation rate tariffs: 100 percent Green and 25 percent Light Green through a full -requirements contract with an experienced, financially stable energy supplier. Through this contract, the remaining energy requirements for the Light Green Tariff may be supplied from unit -specific resources such as efficient, low emission conventional generating resources and, potentially, hydroelectric resources, or by system power purchases. ➢ Increase the aggregate renewable energy supply of the Program to over 60 percent by 2015, based on projected levels of participation in MCE's two available generation tariffs. ➢ Continue increasing renewable energy supplies beyond 2015 based on resource availability and economic goals of the program. ➢ Develop partnership(s) with experienced public power developer(s) to responsibly evaluate development opportunities for Program-owned/controlled renewable generating capacity. ➢ Achieve incremental reductions in greenhouse gas emissions totaling as much as 17 percent of the Marin Communities' total GHG emissions (from all sectors, including transportation). MEA will be responsible to comply with regulatory rules applicable to California load serving entities. MEA will arrange for the scheduling of sufficient electric supplies to meet the hour -by - hour demands of its customers. MEA will adhere to capacity reserve requirements established by the CPUC and the CAISO designed to address uncertainty in load forecasts and potential 22 December 2009 supply disruptions caused by generator outages and/or transmission contingencies. These rules also ensure that physical generation capacity is in place to serve the Program's customers, even if there were to be a need for the Program to cease operations and return customers to PG&E. In addition, MEA will be responsible for ensuring that its resource mix contains sufficient production from renewable energy resources needed to comply with the statewide renewable portfolio standards (currently 20 percent renewable energy supply by 2010). The resource plan will meet or exceed all of the applicable regulatory requirements related to resource adequacy and the renewable portfolio standard. Resource Plan Overview The criteria used to guide development of the proposed resource plan included the following: ➢ Environmental responsibility and commitment to renewable resources; ➢ Price/rate stability; ➢ Reliability and maintenance of adequate reserves; and ➢ Cost effectiveness. To meet these objectives and the applicable regulatory requirements, MEA's resource plan includes a diverse mix of power purchases, renewable energy, new energy efficiency programs, demand response, and distributed generation. A diversified resource plan minimizes risk and volatility that can occur from over -reliance on a single resource type or fuel source. The ultimate goal of MEA's resource plan is to maximize use of renewable resources subject to economic and operational constraints. The result is a resource plan that will source over 60 percent of the resource mix from renewable resources by 2015. The planned resource mix is initially comprised of power purchases from third party electric suppliers and, in the longer- term, may also include renewable generation assets owned and/or controlled by MEA. Once the Program demonstrates it can operate successfully, MEA may begin evaluating opportunities for investment in renewable generating assets, subject to then -current market conditions, statutory requirements and regulatory considerations. Any renewable generation owned by MEA or controlled under long-term power purchase agreement with a proven public power developer, could provide a portion of MEA's electricity requirements on a cost -of -service basis. Electricity purchased under a cost -of -service arrangement should be more cost-effective than purchasing renewable energy from third party developers, which will allow the Program to pass on cost savings to its customers through competitive generation rates. Any investment decisions will be made following thorough environmental reviews and in consultation with the Marin Communities' financial advisors, investment bankers, attorneys, and potentially with customer input. As an alternative to direct investment, MEA may consider partnering with an experienced public power developer and enter into a long-term (20 -to -30 year) power purchase agreement that would support the development of new renewable generating capacity. Such an arrangement could be structured to greatly reduce the Program's operational risk associated with capacity ownership while providing Program customers with all renewable energy generated by the facility under contract. This option may be preferable to MEA as it works to achieve increasing levels of renewable energy supply to its customers. 23 December 2009 MEA's resource plan will integrate supply-side resources with programs that will help customers reduce their energy costs through improved energy efficiency and other demand- side measures. As part of its integrated resource plan, MEA will actively pursue, promote and ultimately administer a variety of customer energy efficiency programs that can cost-effectively displace supply-side resources. Included in this plan is a targeted deployment of over 12 MW of distributed solar by 2019. MEA's proposed resource plan for the years 2010 through 2019 is summarized in the following table: Marin Clean Energy Proposed Researee Plan E3WH) 2010 to 2019 2010 2011 2012 2013 2014 2015 2016 2019 2018 2019 Marin Demand IGWW 0 0 0 0 0 219 219 219 219 219 Retail Demand -94 -160 -970 -774 -728 -281 -285 -989 -793 -797 Distributed Generation 1 l 1 7 8 10 11 11 12 12 Energy Elfiaieney 0 1 1 15 15 15 15 15 15 16 Loaa. and UFS -7 -11 -54 -53 -53 -53 -53 -53 -54 -54 Total Demand -100 -169 -822 -804 -807 -810 -812 -816 -819 -823 Marin Supply lGWR) Renewable Recnurm Generation 0 0 0 0 0 219 219 219 219 219 Pow- Purchase contraots 36 62 296 290 291 234 236 MS 239 242 Total Renewable Res our res 36 62 296 290 291 453 454 457 458 461 Conventional Sesou — Genemnon a u 0 0 0 0 0 a o 0 Power Puxxhase Gntrarts M 108 526 514 516 357 358 360 361 363 Total Conventiunal Resourms 64 108 526 514 516 352 358 360 361 363 Total Supply 100 169 822 804 BD7 810 812 816 $19 823 Supply Requirements The starting point for MEA's resource plan is a projection of participating customers and associated electric consumption. Projected electric consumption is evaluated on an hourly basis, and matched with resources best suited to serving the aggregate of hourly demands or the programs "load profile'. The electric sales forecast and load profile will be affected by MEA's plan to introduce the Program to customers in phases and the degree to which customers choose to remain with PG&E during the customer enrollment and opt -out periods. It is anticipated that MEA's contracted energy supplier will bear a portion of the financial risks associated with deviations from the electric sales forecast during the initial operating period. It will be the obligation of this energy supplier to appropriately reflect these risks in the full requirements energy price. MEA's phased roll-out plan and assumptions regarding customer participation rates are discussed below. Customer Participation Rates Customers will be automatically enrolled in MCE's electricity program unless they opt -out during the customer notification process conducted during the 60 -day period prior to enrollment and continuing through the 60 -day period following commencement of service. NICE anticipates an overall customer participation rate of approximately 80 percent during Phase 1, when service is being offered to the service accounts that are affiliated with MCE's participating members (municipal accounts) and a subset of residential, commercial and/or 24 December 2009 industrial customers, totaling approximately 20 percent of total customer load. Participation rates are expected to be SO percent of bundled service customers and 0 percent of direct access customers during Phase 2 based on experience with similar opt -out style municipal aggregation programs developed in other states and adjustments for assumed aggressive customer retention campaigns to be deployed by the incumbent utility. The participation rate is not expected to vary significantly among customer classes, in part due to the fact that MEA will offer two distinct rate tariffs that will address the needs of cost -sensitive customers within the Marin Communities as well as the needs of both residential and business customers that prefer a highly renewable energy product. These participation rates will also be supported by MEA's focused marketing efforts directed towards commercial and industrial customers who may otherwise be more inclined to remain with a known entity like PG&E. The assumed participation rates will be refined as MEA's public outreach and market research efforts continue to develop. Customer Forecast Once customers enroll in each phase, they will be switched over to service by MCE on their regularly scheduled meter read date over an approximately thirty day period. Approximately 250 service accounts per day will be switched over during the first month of service. For Phase 2, the number of accounts switched over to CCA service will increase to about 2,100 accounts per day. The number of accounts served by MCE at the end of each phase is shown in the table below. Marin Clean Energy Enrolled Retail Service Accounts Phase -In Period (End of Month) The forecast of service accounts (customers) served by MCE for each of the next ten years is shown in the following table: 25 December 2009 Jun -10 Jan -12 Marin Customers Residential 6,944. 62,232 Small Commercial 443 7,501 Medium Commercial 29 635 Large Commercial 3 94 Industrial 2 9 Street Lighting & Traffic 125 373 Ag & Pump. - 154 Total 7,546 70,997 The forecast of service accounts (customers) served by MCE for each of the next ten years is shown in the following table: 25 December 2009 Marin Clean Energy Retail Service Accounts (End of Year) 2010 to 2019 Sales Forecast MCE's forecast of kWh sales reflects the roll-out and customer enrollment schedule shown above. The annual electricity needed to serve MCE's retail customers increases from approximately 160 GWh in 2011 to approximately 800 GWh at full roll-out. Annual energy requirements are shown below. Marin Qean Energy Energy Requirements (GWH) 2010 to 2019 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Marin Customers Residential 6,944 6,979 62,232 62,543 62,855 63,170 63,486 63,803 64,122 64,443 small Commercial 443 446 7,501 7,539 7,576 7,614 7,652 7,691 7,729 7,768 Medium Commercial 29 29 635 638 642 645 648 651 654 658 Large Commercial 3 3 94 94 95 95 96 96 97 97 Industrial 2 2 9 9 9 9 9 9 9 9 Street Lighting&Traffic 125 126 373 375 376 378 380 382 384 386 Ag&Pump. - - 154 155 156 156 157 158 159 159 Total 7,546 7,584 70,997 71,352 71,709 72,068 72,428 72,790 73,154 73,520 Sales Forecast MCE's forecast of kWh sales reflects the roll-out and customer enrollment schedule shown above. The annual electricity needed to serve MCE's retail customers increases from approximately 160 GWh in 2011 to approximately 800 GWh at full roll-out. Annual energy requirements are shown below. Marin Qean Energy Energy Requirements (GWH) 2010 to 2019 Capacity Requirements The CPUC's resource adequacy standards applicable to MEA require a demonstration one year in advance that MEA has secured physical capacity for 90 percent of its projected peak loads for each of the five months May through September, plus a minimum 15 percent reserve margin. On a month -ahead basis, MEA must demonstrate 100 percent of the peak load plus a minimum 15 percent reserve margin. A portion of MEA's capacity requirements must be procured locally, from the Greater Bay area as defined by the CAISO and another portion must be procured from outside the Greater Bay Area. MEA would be required to demonstrate its local capacity requirement for each month of the following calendar year. The local capacity requirement is a percentage of the total (PG&E service area) local capacity requirements adopted by the CPUC based on MEA's forecasted peak load. The formula is as follows: MEA Local Capacity Requirement = [MEA Capacity Requirement/Total PG&E Service Area Capacity Requirement]*Total Local Capacity Requirement in PG&E's Service Area 26 December 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Marin Demand (GWh) Retail Demand 94 160 770 774 778 781 785 789 793 797 Distributed Generation -1 -1 -1 -7 -8 -10 -11 -11 -12 -12 Energy Efficiency 0 -1 -1 -15 -15 -15 -15 -15 -15 -16 Losses and LIFE 7 11 54 53 53 53 53 53 54 54 Total Load Requirement 100 169 822 804 807 810 812 816 819 823 Capacity Requirements The CPUC's resource adequacy standards applicable to MEA require a demonstration one year in advance that MEA has secured physical capacity for 90 percent of its projected peak loads for each of the five months May through September, plus a minimum 15 percent reserve margin. On a month -ahead basis, MEA must demonstrate 100 percent of the peak load plus a minimum 15 percent reserve margin. A portion of MEA's capacity requirements must be procured locally, from the Greater Bay area as defined by the CAISO and another portion must be procured from outside the Greater Bay Area. MEA would be required to demonstrate its local capacity requirement for each month of the following calendar year. The local capacity requirement is a percentage of the total (PG&E service area) local capacity requirements adopted by the CPUC based on MEA's forecasted peak load. The formula is as follows: MEA Local Capacity Requirement = [MEA Capacity Requirement/Total PG&E Service Area Capacity Requirement]*Total Local Capacity Requirement in PG&E's Service Area 26 December 2009 MEA must demonstrate compliance or request a waiver from the CPUC requirement as provided for in cases where local capacity is not available. The forward resource adequacy requirements for 2010 through 2012 are shown in the following tables: Marin Clean Energy Forward Capacity and Reserve Requirements (MW) 2010 to 2012 Month 2010 2011 2012 January - 38 156 February - 37 167 March - 28 134 April - 26 130 May - 25 119 June 31 31 138 July 29 29 134 August 31 30 153 September 32 32 143 October 34 34 143 November 37 37 160 December 38 38 156 MEA's plan ensures sufficient reserves are procured to meet its peak load at all times. MEA's annual capacity requirements are shown in the following table: Local capacity requirements are a function of the PG&E area resource adequacy requirements and MCE's projected peak demand. MEA will need to work with the CPUC's Energy Division and potentially staff at the California Energy Commission to obtain the data necessary to calculate MEA's monthly local capacity requirement. A preliminary estimate of MEA's annual local capacity requirement for the ten year planning period ranges from approximately 14 to 63 MW as shown in the following table: 27 December 2009 Marin Clean Energy Capacity Requirements IMw) 2010 to 2019 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Demand ONN9 RetailL and 32 32 144 144 145 146 146 147 148 149 Distributed Generation (1) (1) (5) (6) (6) (7) (7) (8) (8) (8) Energy Efficiency (a) (0) (3) (3) (.3) (3) (3) (3) (3) (.3) Losses and IM 2 2 9 9 9 9 t0 10 10 10 Total Net Peaklemand 33 33 145 145 145 145 145 145 146 147 R --Requirement(%) 15% 15% 15% 15% 15% 15'% 15% 15% 15% 15% Capacity Reterve Requirement 5 5 22 22 22 22 22 n 22 22 Capacity RrVu oaeotlncludiaglteserve 38 38 167 167 167 166 167 167 168 169 Local capacity requirements are a function of the PG&E area resource adequacy requirements and MCE's projected peak demand. MEA will need to work with the CPUC's Energy Division and potentially staff at the California Energy Commission to obtain the data necessary to calculate MEA's monthly local capacity requirement. A preliminary estimate of MEA's annual local capacity requirement for the ten year planning period ranges from approximately 14 to 63 MW as shown in the following table: 27 December 2009 Marin Clean Energy Local Capacity Requirements (MM 2010 to 2019 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 PG&E Planning Area System Peak W) 22,425 22,712 23,012 23,311 23,614 23,921 24,232 24,547 24,866 25,189 Total Capacity Requirement(115%) 25,789 26,124 26,464 26,808 27,156 27,509 27,867 28,229 28,596 28,968 Authority Peak W) 33 33 145 145 145 145 145 145 146 147 Authority Share of Planning Area 0.1% 0.1% 05% 05% 05% 05% 0.5% 0.5% 0.5% 05% Local Capacity ltequirenent- Greater Bay Area 4,896 4,959 5,024 5,089 5,155 5,222 5,290 5,359 5,429 5,499 Local Capacity Requirement- Other PG&E 6,232 6,313 6,395 6,478 6,562 6,648 6,734 6,822 6,910 7,000 Authority Local Capacity Requirement Greater Bay 6 6 28 28 27 27 28 28 28 2B Authority Local Capacity Requirement Other PG&E 8 8 35 35 35 35 35 35 35 35 MEA intends to coordinate with PG&E and appropriate state agencies to manage the transition of responsibility for resource adequacy from PG&E to MEA during 2010. For system resource adequacy requirements, MEA will make month -ahead showings for each month of 2010 that MEA plans to serve load, and load migration issues would be addressed through the CPUC's approved procedures. Local resource adequacy requirements cannot be trued up monthly, and MEA intends to discuss an appropriate transition mechanism with PG&E. MEA will work with the California Energy Commission and CPUC prior to commencing service to customers to ensure it meets its local and system resource adequacy obligations for 2010 through its agreement with its chosen electric supplier. Renewable Portfolio Standards Energy Requirements Basic RPS Requirements As a CCA, MEA is required by law and ensuing CPUC regulations to procure a minimum percentage of its retail electricity sales from qualified renewable energy resources. Under the California renewables portfolio standard ("RPS") program and policies established in the state's Energy Action Plan, MEA must generally increase its percentage utilization of renewable energy by no less than one percent per year and achieve a minimum of 20 percent by 2010. For purposes of determining MEA's renewable energy requirements, the same standards for RPS compliance that are applicable to the distribution utilities are assumed to apply to MEA. The Commission has ruled that CCAs must comply with five fundamental aspects of the RPS program: 1) meeting the 20 percent requirement by 2010; 2) increasing their renewable sales by at least one percent per year; 3) reporting their progress to the Commission; 4) utilizing flexible compliance mechanisms; and 5) being subject to penalties and penalty processes. Future resource plans adopted by MEA will incorporate any changes in these assumptions that result from the Commissions rulemaking process. RPS Compliance Rules CPUC Decision No. 04-06-014 clarifies the methodology for calculating the annual renewable energy requirements needed to comply with the RPS. In that decision, the Commission defines two related terms to measure a load serving entity's progress toward meeting its RPS obligations. The "Annual Procurement Target" ("APT") is the total amount of renewable energy needed to meet the requirement to increase renewable procurement by at least 1 percent of retail sales per year, subject to Commission rules for flexible compliance. It is the sum of the 28 December 2009 baseline, representing renewable generation needed to continue to satisfy obligations under the RPS targets of previous years, and the "Incremental Procurement Target" ("IPT"), which is at least 1 percent of the previous year's total retail electrical sales. The CPUC's flexible compliance rules allow a load serving entity to defer up to 25 percent of the IPT without explanation, as long as the shortfall is made up within three years. Shortfalls greater than 25 percent of IPT will be permitted upon demonstration of one or more of the following: 1) insufficient response to a request -for -offers; 2) contracts in hand that will make up the deficit in future years; 3) inadequate public goods funds to cover above market renewable contract costs; and 4) seller non-performance. Noncompliance will result in penalties of 5 cents per kWh, capped at $25 million per year. Marin Energy Authority's Renewable Portfolio Standards Requirement Because MEA will have no baseline of renewable energy procurement (i.e., no existing contracts or resources) and no prior retail electrical sales, its first year APT calculated as described above is zero. In 2011 MEA must meet the full 20 percent renewable standard (based on 2010 retail sales). MEA's annual RPS requirements are shown in the table below. Marin (lean Energy RPS Requirements 09IWM 20101o2019 2010 2011 2012 2013 2014 2015 2016 2017 2018 Retail Sales 93,505 158,291 767,843 751,393 753,984 756,595 759,225 762,904 765,675 769,564 Baseline - - 18,701 31,658 153,569 150,279 150,797 151,319 151,845. 152,581 Incremental Procurement Target - 18,701 12,957 121,910 (3,290) 518 522 526 736 554 Annual Procurement Target - 18,701 31,658 153,569 150,279 150,797 151,319 151,845 152,581 153,135 % of Current Year Retail Sales 12% 4% 20% 20% 20% 20% 20% 20% 20% Based on MEA's 25 percent minimum renewable energy supply content and voluntary participation in MCE's 100 percent renewable energy supply option, MEA anticipates that it will significantly exceed the minimum RPS requirements as shown below. 29 December 2009 Marin Clean Energy RPS Requirements an d Program Renewable En ergy Targets (Mwlll 2010 to 2019 2010 2011 2012 2013 2014 2015 2016 2017 2918 2019 Retail Sales(MWh) 93505 158,291 967,843 751,393 753,984 756595 759,225 962,904 765,675 969564 Annual RPS Tarpt(M naum MWh) - 18,701 31,658 153,569 150279 150,797 151,319 151,845 152,581 153,135 Program Target (%dRetail Sales) 39% 39% 39% 39% 39% 60% 60% 60% 60% 60'% Program Renewable Target( Wh) 36,428 61,676 296,016 289,674 290,673 452,850 454,425 456,626 458,285 460,613 Surplaa In Ew- of RPS WM) 36,428. 42,976 264,358 136,106 149,395 302,054 303,106 304,781 305,704 307,478 Annual(nerease(MWh) 36,428 25,248 234,339 (6,342) 999 162,177 1,574 2,202 11659 2,328 29 December 2009 Resources Once the Program demonstrates it can operate successfully, MEA may begin evaluating opportunities for investment in renewable generating assets, subject to then -current market conditions, statutory requirements and regulatory considerations. Any renewable generation owned by MEA or controlled under long-term power purchase agreement with a proven public power developer, could provide a portion of MEA's electricity requirements on a cost -of -service basis. Electricity purchased under a cost -of -service arrangement should be more cost-effective than purchasing renewable energy from third party developers, which will allow the Program to pass on cost savings to its customers through competitive generation rates. Any investment decisions will be made following thorough environmental reviews and in consultation with the Marin Communities' financial advisors, investment bankers, attorneys, and potentially with customer input. As an alternative to direct investment, MEA may consider partnering with an experienced public power developer and enter into a long-term (20 -to -30 year) power purchase agreement that would support the development of new renewable generating capacity. Such an arrangement could be structured to greatly reduce the Programs operational risk associated with capacity ownership while providing Program customers with all renewable energy generated by the facility under contract. This option may be preferable to MEA as it works to achieve increasing levels of renewable energy supply to its customers. Purchased Power Power purchased from utilities, power marketers, public agencies, and/or generators will likely be the exclusive source of supply from 2010 to 2014 (MEA may consider the development of certain renewable energy projects, subject to Board approval, which may supply electric generation to MEA customers as soon as January 2015) and may still remain a significant source of power in the event that MEA considers the development of its own renewable generation assets. During the period from 2010 — 2015, NICE will contract to obtain all of its electricity from a third party electric provider under a full requirements power supply agreement, and the supplier will be responsible for procuring a mix of power purchase contracts, including specified renewable energy targets, to provide a stable and cost-effective resource portfolio for the Program. Based on terms established in this third -party contract, MEA will be able to substitute electric energy generated by MEA-owned/controlled renewable resources for contract quantities in the event that such resources become operational during the delivery period. Initially, the Program's third party electric supplier will be responsible for managing the overall supply portfolio. Details of the electric supply portfolio and risk management practices that will be employed by the Programs electric supplier will be established as the contract is negotiated with the selected electric supplier. A mix of short and long term power purchases will be used to meet the hour -by -hour demand requirements of MCE's customers, and prices will be predominantly fixed for the contract term. Renewable Resources MEA will initially secure necessary renewable power supply from its third party electric supplier(s). Qualified renewable energy resources must supply a minimum of 25 percent of customer energy requirements, which equates to approximately 40,000 MWh in 2011. To 30 December 2009 qualify as eligible for California's RPS, a generation facility must use one or more of the following renewable resources or fuels: ➢ Biomass; ➢ Biodiesel; ➢ Fuel cells using renewable fuels; ➢ Digester gas; ➢ Geothermal; ➢ Landfill gas; ➢ Municipal solid waste; ➢ Ocean wave, ocean thermal, and tidal current; ➢ Photovoltaic; ➢ Small hydroelectric (30 MW or less); ➢ Solar thermal; and ➢ Wind. MEA may supplement the renewable energy provided under the initial full requirements contract with direct purchases of renewable energy or potentially with investments in renewable energy facilities. Renewable technologies that are predominantly and generally commercially available are wind, geothermal, biomass, land fill gas, and solar (thermal or photovoltaic). Studies sponsored by the CEC show that over 7,000 MW of eligible renewable resources are economically developable statewide by 2010, and a study sponsored by the CPUC indicated nearly 50,000 MW of renewable resource potential could be utilized by 2020? The vast majority of the resource potential identified by the CEC is located in Southern California, concentrated in four specific areas: Tehachapi area and Riverside County wind resources (2,800 MW), utility -scale solar in the Southern California deserts (1,000 MW), and geothermal in the Imperial Valley (1,600 MW). There are an estimated 450 MW of resources in the PG&E territory economically developable by 2010, primarily represented by wind resources in Solano and Alameda Counties (400 MW) and geothermal (45 MW) near the Geysers. Near -Terns Renewable Potential While renewable resource potential within the state is vast, the lack of existing transmission facilities necessary to interconnect the renewable resource areas — which are typically far from population centers — and the lack of sufficient transfer capability on key transmission paths to enable delivery to load centers may be a limiting factor in acquiring low cost renewable energy to meet MCE's resource planning goals (until the transmission system is expanded). Existing transmission constraints generally limit the quantity of renewable energy that can be delivered 3 Strategic Value Analysis for Integrating Renewable Energy Technologies in Meeting Target Renewable Penetration; In Support of the 2005 Integrated Energy Policy Report; Davis Power Consultants, June 2005. Costs are in 2005 dollars. Resources identified as being economically developable by the CEC were those found to have positive impacts on the transmission system, if developed and for which the levelized costs are estimated to be at or below a market price benchmark of 6.05 cents per kWh. The referenced CPUC study is Achieving A 33 percent Renewable Energy Target; J.Hamrin, R. Dracker, J. Martin, R. Wiser, K. Porter, D. Clement, M. Bolinger; November 2005. 31 December 2009 to MCE's customers from resources located outside of the larger host utility (PG&E, SCE, SDG&E) service territory, without causing transmission congestion charges to be incurred. Considering transmission constraints and current transmission expansion plans of the investor owned utilities, studies indicate there are an estimated 14 million MWh per year of economically developable renewable resources currently available (by 2010) as shown in the following table, with about 2.6 million MWh of this annual production potential located within the PG&E service territory. Resources Identified for Potential CCA Development by 2010, Considering Existing and Planned Network Transmission System Capacity (MWh) Resource Type PG&E Area SCE Area SDG&E Area4 Geothermal 1,576,800 0 5,085,180 Wind 525,236 4,780,800 394,200 Biomass 525,000 1,094,562 156,366 Total 2,627,036 5,875,362 5,635,746 Source: Community Choice Aggregation Demonstration Project, Renewable Resource Development Roadmap; Nami ant Consulting, Inc., June 2006. Ideally, MEA would be able to procure renewable energy locally, or at least from within the PG&E service area. Transmission capacity for energy imports from outside the host utility service area (PG&E) is available during only certain times of the year, and electricity transmitted from points outside of the region would be subject to potential charges for use of congested transmission lines. Congestion charges will become a more significant economic factor as the CAISO has transitioned from the former zonal congestion pricing model to a nodal model when it implemented its Market Redesign and Technology Update (MRTU) 5 The ideal energy source would be located within the County, near the load center. The next best alternative would be for the resource to be located outside the CCA's boundaries but within or deliverable to the PG&E service territory. A study prepared for Marin County identified nearly 850 MW of renewable resource potential within the County, capable of producing approximately 1,300 GWh per year.6 Considering that PG&E is expected to need over 6.5 million MWh per year of additional renewable energy procurement to meet its RPS obligation by 2010, MCE will look first to local renewable resources and then to procurement of renewable energy from outside the area. MEA may also supplement its procurement of physical resources with purchases of renewable energy certificates, which allow for the purchase of the renewable attributes of electricity generated by a renewable resource without regards to physical delivery to loads. 4 The geothermal resources are located in Imperial Valley and will be deliverable to San Diego area loads following completion of Phase 1 of SDG&E's proposed Sunrise Powedink in 2010. Wind resources in Eastern San Diego County are planned to be connected via tap lines to the Sunrise Powerlink. 5 Under the current zonal model, there are potential congestion costs for transferring electricity between any of the three zones within California (NP15, ZP26 and SPIS). The nodal model expands the number of congestion pricing points, creating thousands of locational pricing nodes. 6 Increasing Renewable Energy Resources in the County of Marin, Jody London Consulting, November 11, 2007. 32 December 2009 For planning purposes, MEA should anticipate procurement from the following types of large scale renewable resources in the near term, which would require little or no transmission expansion to ensure deliverability: ➢ Local resources (solar, wind, biogas, biomass); ➢ Wind resources in Solano County; ➢ Existing Qualifying Facilities with expiring PG&E contracts; ➢ Expansion and re -powering of wind resources in Alameda County; ➢ Geothermal in Lake and Sonoma Counties; ➢ Local biomass projects; and ➢ Renewable Energy Certificates. Medium and Long -Term Renewable Potential In the medium to long term, the Program will be able to utilize the transmission expansion projects that are underway by PG&E, SCE, and potentially other utilities and transmission owners/developers in the West, designed to expand access to renewable resource areas. PG&E, as well as any other utility, must offer access to its transmission system to generators and other market participants and provide transmission service comparable to the service it provides itself, according to well established open access regulations promulgated by the Federal Energy Regulatory Commission (FERC)? The CAISO administers access to PG&E's transmission system on a nondiscriminatory basis in accordance with tariffs on file with the FERC. As of January 2008, over 38,000 MW of renewable resources had applied for transmission interconnections with the CAISO.e According to the CAISO, about one half of all projects in the queue ultimately are developed. These projects represent proposed renewable projects that MCE could potentially use to meet its renewable energy requirements, once the necessary transmission upgrades are completed. PG&E has plans in place to invest up to $3.0 billion in new transmission infrastructure over the next decade, and has identified four major transmission projects specifically designed to expand access to renewable resources.9 In its Plan, PG&E notes that these projects are at "conceptual studying stages', and, as a result, definitive conclusions should not be drawn with respect to project details or timing. However, there is no doubt that PG&E will target certain renewable transmission projects for completion to further its achievement of the state's renewable portfolio standard, which mandates 20 percent renewable energy sales by 2010 and potentially 33 percent by 2020. In addition to these specific projects/focus areas, PG&E is also involved in studying various other projects, such as the development of electric transmission to accommodate the transfer of 41000 MW of wind generation from the Tehachapi Region. Based on CPUC Decision 04-06-010, 9 The open access framework for transmission is set forth in a series of orders by the Federal Energy Regulatory Commission: FERC Orders 888, 889, 889A and 890. E 2008 CAISO Transmission Plan: A Long -Term Assessment of the California ISO's Controlled Grid (2008-2018), California Independent System Operator, January 2008. 9 PG&E 2006 Electric Grid Expansion Plan, December 29, 2006. 33 December 2009 the Tehachapi Collaborative Study Group was formed "to develop a comprehensive transmission development plan for the phased expansion of transmission capabilities in the Tehachapi area." Membership in this group includes PG&E, SCE, the CEC, the CPUC, the CAISO, wind energy developers and other stakeholders. Based on its studies, PG&E identified three transmission development alternatives that would accommodate importing 2,000 MW of wind generation from the Tehachapi region to northern California (another 2,000 MW would be available for southern import). Other projects under consideration by PG&E include those considered by the Northwest Transmission Assessment Committee (NTAC), which would bring renewable and other generating resources to California from Canada and the Pacific Northwest, a submarine transmission interconnection to British Columbia from northern California and the Frontier Line, which would connect California to Wyoming capacity markets (primarily wind and "clean" coal). These projects have not yet been fully developed and are still being studied by PG&E. As noted above, MEA would have the same access as PG&E to this transmission once the projects are completed. For mid and long term planning purposes, MEA should anticipate procurement from the following types of large scale renewable resources": ➢ Wind imports from the Tehachapi Area; ➢ Wind imports from the Pacific Northwest; ➢ Geothermal imports from Nevada; ➢ Geothermal imports from the Imperial Valley; and ➢ Solar CSP imports from Southern California (Riverside and San Bernardino Counties). Although this resource plan identifies likely resource types and locations, it is not possible to predict what projects might be proposed in response to MEA's future solicitations for renewable energy or that may stem from discussions with other public agencies. Renewable projects that are located virtually anywhere in the Western Interconnection can be considered as long as the electricity is deliverable to the CAISO control area, as required to meet the Commission's RPS rules and any additional guidelines ultimately adopted by MEA's Board of Directors. The costs of transmission access and the risk of transmission congestion costs would need to be considered in the bid evaluation process if the delivery point is outside of MEA's load zone, as defined by the CAISO. Initially, the electric supplier selected for the Program will be responsible for meeting the specified renewable energy requirements under a full requirements electricity agreement. In the longer term, MEA may request proposals directly from renewable developers to meet its renewable energy requirements, and responses to the solicitations would determine the specific resource types and locations that may be utilized. Actual procurement of renewable resources can be conducted through a competitive solicitation, either directly by MEA or in conjunction with another public agency. MEA may also explore opportunities to partner with other public 10 In the long term, new technologies such as wave or tidal energy may become economically feasible as well. 34 December 2009 agencies, such as the Sacramento Municipal Utility District (SMUD) or the Northern California Power Agency (NCPA), that are currently developing renewable resources. It bears mentioning that MEA will be in competition for renewable resources with the three investor owned utilities, which together require nearly 12 million MWh annually to meet their RPS requirements by 2010. Over the longer term, the transmission expansion plans of the utilities will provide additional resource options for MEA. The Authority, working with third party electric suppliers, will need to be aggressive in pursuing the renewable resources that are currently available. In contrast to PG&E, which is motivated by regulatory compliance with the Renewable Portfolio Standards, MEA will elevate procurement and potential development of renewable energy as its primary mission, proactively seeking out opportunities to develop local resources and partnering with private developers and other public agencies. Planned Renewable Generation Resources Once the Program demonstrates it can operate successfully, MEA may begin evaluating opportunities for investment in renewable generating assets, subject to then -current market conditions, statutory requirements and regulatory considerations. Any renewable generation owned by MEA or controlled under long-term power purchase agreement with a proven public power developer, could provide a portion of MEA's electricity requirements on a cost -of -service basis. Electricity purchased under a cost -of -service arrangement should be more cost-effective than purchasing renewable energy from third party developers, which will allow the Program to pass on cost savings to its customers through competitive generation rates. Any investment decision will be subject to Board approval and will only be made following thorough environmental reviews and in consultation with the Marin Communities' financial advisors, investment bankers, attorneys, and potentially with customer input. Energy Efficiency The CPUC and State energy policy, as expressed in the Energy Action Plan and reaffirmed in D.04-12-048, is to make energy efficiency the highest priority procurement resource. As such, cost-effective energy efficiency should be first in the "loading order' of resources used to meet customers energy service needs 11 In order to promote the resource procurement policies articulated in the Energy Action Plan and by the CPUC, energy efficiency activities funded by ratepayers should focus on programs that serve as alternatives to more costly supply-side resource optionsiz California electric distribution utilities (investor-owned utilities and municipal utilities) are required by law to include a separate line item on customer bills containing a surcharge, termed the PGC, to fund Public Purpose Programs or Public Good Programs. PGC funded programs include energy efficiency, renewable energy, low-income, and research and development programs. The PGC surcharge is non -bypassable, subject to payment regardless of whether the serving distribution utility provides the energy commodity. Therefore, customers purchasing energy from a private Energy Service Provider (ESP) or a CCA must pay the PGC and may 11 CPUC Rulemaking R.01-08-028, ATTACHMENT 3 ENERGY EFFICIENCY POLICY MANUAL FOR POST -2005 PROGRAMS, Page 2, Rule 11.1. 12Ibid., Page 3, Rule 11.3. 35 December 2009 participate in PGC funded programs. Additionally, AB 117 permits CCAs to apply to administer cost-effective energy efficiency programs. All electric utilities in the state include energy efficiency programs in their resource portfolios and annual budgets for California's distribution utilities exceed $700 million. Energy efficiency programs provide a least cost resource, are environmentally superior to supply side resources, reduce customer bills and enhance customer service. This section addresses the treatment of energy efficiency as a component of MEA's integrated resource plan. As described below there are opportunities for significant cost effective energy efficiency programs within the region, and MEA will seek to maximize end-use customer energy efficiency by facilitating customer participation in existing utility programs as well as by forming new programs that displace MEA's need for procuring electric supply. This energy efficiency potential forecast serves as a means to estimate the scope and types of energy efficiency programs the Program might include within its resource portfolio within the following customer segments: 1) Residential — Low -Income and Multi -Family; 2) Residential; 3) Commercial/Small Commercial; and 4) Large Commercial/Industrial Preliminary program planning has been prepared based on the conduct of an energy efficiency forecast that employs key assumptions and methodologies adopted by California's investor owned utilities, tailored to the County s service territory weather, demographics, and commercial and industrial customer base. The forecast identifies the size and characteristics of customer market segments, energy efficiency technology options, and projects the costs and benefits associated with forecast program achievable energy efficiency potential. Baseline Energy Efficiency Potential Estimates Conservative estimates indicate cost effective ("economic") energy efficiency potential exists in Marin County to save 181,252 MWh annually. Discounting the economic potential for customer awareness and willingness to adopt based on industry standard assumptions yields achievable energy efficiency potential of 15,100 MWh annually achievable through implementing energy efficiency programs funded at approximately $2.8 million. The following table summarizes these findings below: 36 December 2009 Forecast Annualized Energy Efficiency Potential and Program Budgets Achievable Achievable Technical Economic Program Program Sector Use Potential Potential Potential Potential (kWh) (kWh) (kWh) (kWh) (kW) Program Costs Residential 732,840,248 217,934,292 107,356,272 7,459,777 1.0% 2,774 $1,889,983 Commercial 576,235,343 78,085,059 59,356,212 7,380,674 1.3% 1,334 $874,346 Industrial 107,454,070 15,924,110 14,539,192 255,323 0.2% 39 $37,825 Composite 1,416,529,661 311,943,461 181,251,677 15,095,774 . 1.1% 4,147 $2,802,154 36 December 2009 The National Action Plan for Energy Efficiency states among its key findings "consistently funded, well-designed efficiency programs are cutting annual savings for a given program year of 0.15 to 1 percent of energy sales."13 The American Council for an Energy -Efficient Economy (ACEEE) reports for states already operating substantial energy efficiency programs energy efficiency goals of one percent, as a percentage of energy sales, is a reasonable level to target 14 Forecast achievable energy efficiency equal to 1.1 percent of the CCA's forecast energy sales, as indicated in the table above, appears to be a reasonable and conservative baseline for the demand-side portion of CCA's resource plan. These savings would be in addition to the savings achieved by PG&E administered programs. GCA Program Energy Efficiency Goals The Program's energy efficiency goals reflect a strong commitment to increasing energy efficiency within the County and expanding beyond the savings achieved by PG&E's programs. A realistic goal is to increase annual savings through energy efficiency programs to two percent (combined MCE and PG&E programs) of annualized electric sales, as has been adopted by the State of New York. Achieving this goal would mean at least a doubling of energy savings relative to the status quo situation without the CCA program. MEA programs will focus on closing the gap between the vast economic potential of energy efficiency within the County and what is actually achieved. The following table summarizes the estimated energy efficiency potential for each type of energy efficiency initiative:" Energy Efficiency Market Potential EXISTING RESIDENTIAL 53.0% Existing Commercial 18.0% Existing Industrial 14.0% Residential New Construction 1.0% Commercial New Construction 6.0% Industrial New Construction 1.0% Emerging Technologies 7.0% The retrofit of existing buildings represents 85 percent of the total forecast energy efficiency market potential. Studies show that the residential customer sector presents the largest untapped efficiency gains. 13 National Action Plan for Energy Efficiency, July 2006, Section 6: Energy Efficiency Program Best Practices (pages 5- 6) 14 Energy Efficiency Resource Standards: Experience and Recommendations, Steve Nadel, March 2006, ACEEE Report E063 (pages 28 - 30). 15 California Energy Efficiency Potential Study Volume 1, California Measurement Advisory Council (CALMAC) Study ID: PGE0211.01, May 24, 2006, Figure 12-2: Distribution of Electric Energy Market Potential, Existing Incentive Levels through 2016. 37 December 2009 MEA plans to hire Program staff that will develop specific energy efficiency programs that will obtain these energy savings. MCE will also seek requisite PGC program funding from the CPUC to administer the energy efficiency programs. Additional details related to MCE's energy efficiency programs will be developed once the CCA Program is staffed and has begun operations. MEA expects the following elements to be addressed through these programs: Energy Efficiency Programs To enlist community involvement for the greatest possible greenhouse gas reductions, MEA will utilize existing and new avenues of communication between participating governments and their residents and businesses to provide education and outreach on opportunities for energy efficiency. Schools and colleges will be included both as program participants and education and training centers. Energy Efficiency Financing The greatest barrier to energy efficiency for most residents and small businesses is lack of financing. To overcome this, MEA may leverage Public Goods funds and partner with local financial institutions to offer low-interest loans for energy efficiency improvements, in addition to AB811 type programs available for homeowners. Residential Programs MEA's energy efficiency programs can be proposed to offer residential customers a broad choice of efficiency improvements such as insulation, duct -work and other building -shell measures, refrigeration, water heating, space heating/cooling, lighting, as well as sensors and other smart grid systems. MEA may also partner with local water districts to fund water/energy conservation measures in landscaping as well as other household water uses. Municipal, Commercial and Agricultural Programs In addition to the types of improvements available for residential structures, commercial programs will be proposed for municipal loads, schools, and business applications. Examples of potential programs include efficient food service equipment and refrigeration, HVAC systems, electronic controls and advanced lighting technologies such as high efficiency LED street lighting. Demand response programs provide incentives to customers to reduce demand upon request by the load serving entity (i.e., MCE), reducing the amount of generation capacity that must be maintained as infrequently used reserves. Demand response programs can be cost effective alternatives to capacity otherwise needed to comply with the resource adequacy requirements. The programs also provide rate benefits to customers who have the flexibility to reduce or shift consumption for relatively short periods of time when generation capacity is most scarce. Like energy efficiency, demand response can be a win/win proposition, providing economic benefits to the electric supplier and customer service benefits to the customer. In its ruling on local resource adequacy, the CPUC found that dispatchable demand response resources as well as distributed generation resources should be allowed to count for local 38 December 2009 capacity requirements. This resource plan anticipates that MCE's demand response programs would partially offset its local capacity requirements beginning in 2011. PG&E offers several demand response programs to its customers, and MEA intends to recruit those customers that have shown a willingness to participate in utility programs into MCE's demand response programs.16 The goal for this resource plan is to meet 5 percent of the Programs total capacity requirements through dispatchable demand response programs that qualify to meet local resource adequacy requirements. This goal translates into approximately 8 MW of peak demand enrolled in MEA's demand response programs. Achievement of this goal would displace approximately 30 percent of MEA's local capacity requirement within the Greater Bay Area. Marin clean Energy Demand Response G.O. (MW) 2010 to 2019 2010 2011 2012 2013 2019 2015 2016 2017 2018 2019 Total G,dty Requirement (MW) 38 38 167 167 167 166 167 167 168 169 ] nd Response Target - 2 8 8 8 8 8 8 8 8 Per.tage d L.1 Gp.dty R,,irment 0% 30% 30% 30% 30% 30% 30% 30% 30% 30% MEA will adopt a demand response program that enables it to request customer demand reductions during times when capacity is in short supply or spot market energy costs are exceptionally high. The level of customer payments should be pegged to the cost of local capacity that can be avoided as a result of the customer's willingness to curtail usage upon request. This value can range from $50 to $125 per kW -Year. For planning purposes, the customer incentive is assumed to be $75 per kW -year, which is near the backstop price for local capacity resources and above the incentive levels currently offered by PG&E 17 Appropriate limits on customer curtailments, both in terms of the length of individual curtailments and the total number of curtailment hours that can be called should be included in MEA's demand response program design. It will also be important to establish a reasonable measurement protocol for customer performance of its curtailment obligations. Performance measurement should include establishing a customer specific baseline of usage prior to the curtailment request from which demand reductions can be measured. MEA will likely utilize experienced third party contractors to design, implement and administer its demand response programs. Distributed Generation Consistent with MEA's environmental policies and the state's Energy Action Plan, clean distributed generation is a significant component of the integrated resource plan. MEA will work with state agencies and PG&E to promote deployment of photovoltaic (PV) systems 16 These utility programs include the Base Interruptible Program (E -BIP), the Demand Bidding Program (E -DBP), Critical Peak Pricing (E -CPP), Optional Binding Mandatory Curtailment Plan (E-OBMC), the Scheduled Load Reduction Program (E-SLRP), and the Capacity Bidding Program (E-CBP). MEA plans to develop its own demand response programs, which may be similar to those currently administered by the incumbent utility. 17 For example, the annual customer incentive in PG&E's Capacity Bidding Program is fixed at $43.35 per kW -year in 2007-2008. 39 December 2009 within MEA's jurisdiction, with the goal of maximizing use of the available incentives that are funded through current utility distribution rates and public goods surcharges. There are significant associated environmental benefits and strong customer interest in distributed PV systems. The economics of PV should improve over time as utility rates continue to increase and the costs of the systems decline with technological improvements and added manufacturing capacity. MEA can promote distributed PV without providing direct financial assistance by being a source of unbiased consumer information and by facilitating customer purchases of PV systems through established networks of pre -qualified vendors. It may also provide direct financial incentives from revenues funded by customer rates to further support use of solar power within the Marin Communities. Finally, MEA plans to provide direct incentives for PV by offering a net metering rate to Customers who install PV systems so that customers are able to sell excess energy to MEA. MEA's CCA customers will contribute funds to the California Solar Initiative (CSI) through the public goods charge collected by PG&E, and will be eligible for the incentives provided under that program for installation of PV systems. The California Solar Initiative provides $2.2 billion of funding to target installation of 1,940 MW of solar systems within the investor owned utility service areas by 2017. All electric customers of PG&E, SCE, and SDG&E are eligible to apply for incentives. Approximately 44 percent of program funding is allocated to the PG&E service territory. Assuming solar deployment would be proportionate to funding, the program is intended to yield approximately 775 MW of solar within the PG&E service area. A minimum of 8 MW should be deployed within the jurisdictional boundaries of MEA. There are multiple opportunities for distributed generation located within the County including photovoltaics, small and mid-sized wind turbines, methane recovery from waste and dairies, biomass, fuel cells, combined heat and power, and energy storage systems such as batteries. The NICE Distributed Generation program will explore alternative funding and financing sources for local distributed generation, such as federal and state grants, tax credits, AB811 tax assessments, revenue bonds, federal zero -interest CREB bonds, low cost commercial financing, and third party power purchase agreements that reduce or eliminate upfront cost. MCE will also explore ways to integrate and support local distributed generation directly from ratepayer revenues to the extent that it is cost effective. For example, purchases of Renewable Energy Credits, or a fixed payment rate for purchasing renewable energy directly from customer -owned facilities, will be studied within the framework of affordable and competitive customer rates. 40 December 2009 The Authority will work to ensure that customers within its jurisdiction take full advantage of this solar incentive and will develop programs of its own with the goal of exceeding the deployment targets shown above by at least 50 percent (a minimum of 12 MW of distributed solar installations are targeted within the jurisdictions of the Member Agencies). 41 December 2009 California Solar Initiative Deployment 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 IOU Territory Target (KM) 705 882 1,058 1,235 1,411 1,587 1,764 1,940 1,940 1,940 Total Funding($Millions) 240 240 240 160 160 160 5 0 0 0 PG&E Funding($Millions) 105 105 105 70 70 70 2 0 0 0 PG&E Incentives Share 44% 44% 44% 44% 44% 44% 40% 40% 40% 40% PG&E Area Deployment (NM) 309 386 463 540 617 694 705 776 776 776 Marin Share of PG&ELoad 0.2% 0.2% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Marin Solar Deployment (MM) 1 1 5 6 6 7 7 8 8 8 The Authority will work to ensure that customers within its jurisdiction take full advantage of this solar incentive and will develop programs of its own with the goal of exceeding the deployment targets shown above by at least 50 percent (a minimum of 12 MW of distributed solar installations are targeted within the jurisdictions of the Member Agencies). 41 December 2009 This Chapter examines the monthly cash flows expected during the phase-in period of the CCA Program and identifies the anticipated financing requirements for the overall CCA Program by MEA. It includes estimates of program startup costs, including the necessary staffing and capital outlays which will commence once the CPUC accepts the Implementation Plan submitted by MEA. It also describes the requirements for working capital and long-term financing for the potential investment in renewable generation, consistent with the resource plan contained in Chapter 6. Description of Cash Flow Analysis This cash flow analysis estimates the level of working capital that will be required during the phase-in period. In general, the components of the cash flow analysis can be summarized into two distinct categories: (1) Cost of CCA Program Operations, and (2) Revenues from CCA Program Operations. The cash flow analysis identifies and provides monthly estimates for each of these two categories. A key aspect of the cash flow analysis is to focus primarily on the monthly costs and revenues associated with the CCA Program phase-in period, and specifically account for the transition or "Phase -In" of CCA Customers from PG&E's service territory described in Chapter 5. Cost of CCA Program Operations The first category of the cash flow analysis is the Cost of CCA Program Operations. To estimate the overall costs associated with CCA Program Operations, the following components were taken into consideration: ➢ Electricity Procurement; ➢ Ancillary Service Requirements; ➢ Exit Fees; ➢ Staffing Requirements; ➢ Contractor Costs; ➢ Infrastructure Requirements; ➢ Billing Costs; ➢ Scheduling Coordination; ➢ Grid Management Charges; ➢ CCA Bond Premiums; ➢ Interest Expense; and ➢ Franchise Fees. The focus of this cash flow analysis is during the phase-in period. 42 December 2009 Revenues from CCA Program Operations The cash flow analysis also provides estimates for revenues generated from CCA operations or from electricity sales to customers. In determining the level of revenues, the cash flow analysis assumes the customer phase-in schedule noted above, and assumes that MEA's CCA Program provides a Light Green Tariff at comparable generation rates to those of the existing distribution utility for each customer class and a 100 percent Green Tariff at a premium reflective of incremental renewable power costs. Over time, MCE's preference for renewable energy will significantly reduce its exposure to volatile input costs (fuel — natural gas) associated with natural gas-fired generation, which are expected to increase steadily, and potentially significantly, for the foreseeable future. Because a significant portion of MEA's power supply will be from renewable energy sources, upward price pressures on its power supply should be significantly reduced over long-term operations. Projected long-term cost savings can be passed on to Program customers in the form of lower generation rates or can be applied to the procurement of additional renewable energy supplies (moving the programs renewable energy supply closer to its 100 percent goal), energy efficiency programs or other energy/climate initiatives within the scope of broad-based powers established for MEA. Ultimately, MEA will have flexibility when making these decisions and can respond to the evolving needs of local residents and businesses when developing rate tariffs and energy/climate-focused programs. Cash Flow Analysis Results The results of the cash flow analysis provide an estimate of the level of working capital required for MEA to move through the CCA phase-in period. This estimated level of working capital is determined by examining the monthly cumulative net cash flows (revenues from CCA operations minus cost of CCA operations) based on assumptions for payment of costs by MEA, along with an assumption for when customer payments will be received. This identifies, on a monthly basis, what level of cash flow is available in terms of a surplus or deficit. With the assumptions regarding payment streams, the cash flow analysis identifies funding requirements while recognizing the potential lag between payments received and payments made during the phase-in period. The estimated financing requirements for the phase-in period, including working capital, based on the phase-in of customers as described above is approximately $10 million. Working capital requirements reach this peak immediately after enrollment of the Phase 2 customers. CCA Program Implementation Feasibility Analysis In addition to developing a cash flow analysis which estimates the level of working capital required to get MEA through full CCA phase-in, a summary analysis that evaluates the feasibility of the CCA program during the phase-in period has been prepared. The difference between the cash flow analysis and the CCA feasibility analysis is that the feasibility analysis does not include a lag associated with payment streams. In essence, costs and revenues are reflected in the month in which service is provided. All other items, such as costs associated with CCA Program operations and rates charged to customers remain the same. 43 December 2009 The results of the feasibility analysis are shown in the following table. Under these assumptions, over the entire phase-in period the CCA program is projected to accrue a reserve account balance of approximately $10 million. Marin Clean Energy Summary of CCA Program Phase -In (January 2010 through December 2015) CATEGORY L REVENGES FROM OPERATIONS ($L (A) ELECTRICTTYSALES: RESIDENTIAL GENERAL SERVICE(A-1) SMALLTIME -OF -USE (Afi) ALTERN. RATE FOR MEDIUM USE (A-10) 500-900kW DEMAND (E-19) 1000 ♦ kW DEMAND (&20) STREET LIGHTING & TRAFFIC CONTROL AGRSCULTURALFUMPING TOTAL REVENUES E. COST OF OPERATIONS($): (A) ADMIMSTRATIVE&GENERAL(A&G): STAFFAIG CONTRACTOR COSTS IOU FEES (INLCUDMG BILLMG) CONTRACTSTAFF SUBTOTAL-A&G (B) CCA PROGRAM OPERATIONS: 2010 2011 2012 2013 2014 2015 TOTAL $10,509,091 $18,526,704 $45,512,848 $48,113,912 $50522,190 $51,382,217 $224,521,742 $198,657 $328,250 $9,711,582 $10,266,557 $10,781,544 $10,963,995 $42,250,585 $557,610 $860,852 $3,561,789 $3,765,330 $3,954,205 $4,021,120 $16,720,907 $337,456 $559,177 $13,118,500 $13,868,166 $14,563,814 $14,810,271 $57,257,385 $216,669 $350,085 $5,336,771 $5,641,745 $5,924,744 $6,025,005 $23,495,019 $597,871 $966,897 $4,121,134 $4,356,640 $4,575,175 $4,652,599 $19,270,316 $181,866 $312,378 $493,880 $522,104 $548,293 $557572 $2,616,093 $0 0 $44L925 $467,179 $490,614 $498,916 $1,898,634 $12,599,220 $21,904,343 $82,298,430 $87,001,432 $91,365,559 $92,911,695 $388,080,680 $940,582 $1,112,400 $2,595,600 $2,673,468 $2,753,622 $2,836,282 $12,912,004 $1,555,000 $1,545,000 $2,163,000 $2,227,890 $$.294,227 $2,363569 $12,149,185 $265,000 $123,600 $1,050,600 $1,082,118 $1,114,582 $1,148,019 $4,783,919 $165,000 $185,400 $222,480 $229,154 $236,029 $243,110 $1,281,173 $2,925,582 $2,966,400 $6,031,680 $6,212,630 $6,399,009 $6,590,980 $31,126,281 ELECTRICITYPROCUREME $8,138,715 $14,744,468 $69,710,310 $71,548,998 $73,321,131 $72,767,969 $310,231,592 EMT FEES $1,979,328 $2,336,657 $7,967,904 $5,764,028 $4,470,990 $5,313,869 $27,832,T28 RENEWABLE PORTFOLIO AOIUSTMENT $187,629 $318,683 $1,616,676 $1,624,760 $1,632,883 $3,347,738 $8,728,369 SUBTOTAL-CCAPROGRAMOPERATONS $10,305,672 $17,399,808 $79,294,891 $78,937,786 $79,425,005 $81,429,576 $346,792,738 TOTAL COST OF OPERATION $13,23L254 $20,366,208 $85,326,571 $85,150,417 $85,824,015 $88,020,555 $37$919,020 CCA PROGRAM SURPLUS /(DEFICYO ($632,034) $1,538,135 ($3,028,141) $1,851,016 $5,541,544 $4,89,140 $10,161,661 The surpluses achieved during the phase-in period serve as operating reserves for MEA in the event that operating costs (such as power purchase costs) exceed collected revenues for short periods of time. Marin Clean Energy Financings It is anticipated that three financings may be necessary in support of the CCA Program. The anticipated financings are listed below and discussed in greater detail. CCA Program Start-up and Working Capital (Phase 1) As previously discussed, the anticipated start-up and working capital requirements for the CCA Program are $2 million. Once the CCA Program is up and running, these costs would be recovered from the retail customers through retail rates. Actual recovery of these costs will be dependent on third -party electricity purchase prices and decisions regarding rates, and negotiations between the electric supplier and MEA's Board of Directors regarding initial rates for Phase 1 customers. 44 December 2009 It is assumed that this financing will be via a letter of credit (LOC), which would allow MEA to draw cash as required. This financing would need to commence no later than early 2010. CCA Program Working Capital (Phase 2) The next potential financing would be working capital for Phase 2. As mentioned above, this could be just an extension (increase) of the LOC for the Program's start-up and working capital. Depending upon market conditions, and payment terms established with the third -party supplier, it may be necessary to increase the LOC to an approximate amount of $10 million (or more) in "float" for the start of Phase 2. This number would be refined as the CCA Program was operational and bids were received and evaluated from power providers for the Phase 2 load requirements. Renewable Resource Project Financing MEA's CCA Program may consider large project financings for renewable resources (likely wind, solar, biomass or geothermal), which may total as much as $375 million (combined). These financings would only occur after a sustained period of successful Program operation and after appropriate project opportunities are identified and subjected to appropriate environmental review. Such financing would occur no sooner than late 2012 - early 2013. In the event that such financing becomes necessary, funds would include any short-term financing for the renewable resource project development costs, and would extend over a 20- to 30 -year term. The security for such bonds would be a hybrid of the revenue from sales to the retail customers of MEA, including a Termination Fee as described in Chapter 9, and the renewable resource project itself. The following table summarizes the potential financings in support of the CCA Program: Proposed Financing Estimated Total Estimated Tenn Estimated Issuance Amount 1. Start -Up and Working $2 million No longer than 7 years Early 2010 Capital (Phase 1) 2. Working Capital (Phase $10 million No longer than 5 years Mid 2011 2) 3. Potential Renewable $375 million Late 2012 -Early Resource Project (aggregate) 20-30 years 2013 Financings 45 December 2009 Introduction This Chapter describes the initial policies proposed for the Authority in setting its rates for electric aggregation services. These include policies regarding rate design, objectives, and provision for due process in setting Program rates. Initial Program rates will be approved by the Board and included in the initial customer opt -out notices for customer comparison purposes. MEA's Board of Directors would approve the rate policies and procedures set forth in MEA's adopted Implementation Plan to be effective at Program initiation. The Board would retain authority to modify program policies from time to time at its discretion. Rate Policies MEA would establish rates sufficient to recover all costs related to operation of the program, including any reserves that may be required as a condition of financing and other discretionary reserve funds that may be approved by the Board of Directors. As a general policy, rates will be uniform for all similarly situated customers enrolled in the Program throughout the service area of MEA, comprised of the jurisdictional boundaries of its members. It is not anticipated that each member would establish its own rates. The primary objectives of the ratesetting plan are to set rates that achieve the following: ➢ 100 percent renewable energy supply option —100 percent Green Tariff; ➢ Rate competitive tariff option — Light Green Tariff; ➢ Rate stability; ➢ Equity among customers in each tariff; ➢ Customer understanding; and ➢ Revenue sufficiency. Each of these objectives is described below. Rate Competitiveness The goal is to offer competitive rates for the electric services MEA would provide to participating customers. For participants in MEA's Light Green Tariff, the goal would be for MEA's rates to be equivalent to (potentially less than) the generation rates offered by PG&E. For participants in MEA's 100 percent Green Tariff, the goal would be to offer the lowest possible customer rates with an incremental monthly cost premium of approximately 10 percent. Competitive rates will be critical to attracting and retaining key customers. As discussed above, the principal long-term Program goal is to achieve 100 percent renewable energy supply subject to economic and operating constraints. As previously discussed, the Program will significantly increase renewable energy supply to Program customers, relative to the incumbent utility, by 46 December 2009 offering two distinct rate tariffs. The default tariff for Program customers will be the 25 percent Light Green Tariff, which will maximize renewable energy supply (minimum 25 percent) while maintaining generation rates that are equivalent to PG&E. MEA will also offer its customers a voluntary Deep Green Tariff, which will supply participating customers with 100 percent renewable energy supply at rates that reflect the Programs cost for procuring necessary energy supplies. As previously suggested, the default tariff for Program customers will be the Light Green Tariff. Consistent with this MEA policy, participating qualified low- or fixed-income households, such as those currently enrolled in the California Alternate Rates for Energy (CARE) program, will be automatically enrolled in the Light Green Tariff and will continue to receive related discounts on monthly electricity bills. Based on projected participation in each tariff, the amount of renewable energy supplied to Program customers as a percentage of the Program's total energy requirements is projected to exceed 60 percent in 2015. This estimate is based on discussions with local policy makers, municipal management, potential suppliers and members of the public. Rate Stability MEA will offer stable rates by hedging its supply costs over multiple time horizons. Rate stability considerations may mean that program rates relative to PG&E's may differ at any point in time from the general rate targets set for the Program. Although MEA's rates will be stabilized through execution of appropriate price hedging strategies, the distribution utility's rates can fluctuate significantly from year-to-year based on energy market conditions such as natural gas prices, the utilities' hedging strategies, and hydro -electric conditions; and from rate impacts caused by periodic additions of generation to utility rate base. MEA will have more flexibility in procurement and ratesetting than PG&E to stabilize electricity costs for customers. Equity among Customer Classes MEA's policy will be to provide rate benefits to all customer classes relative to the rates that would otherwise be paid to the local distribution utility. Rate differences among customer classes will reflect the rates charged by the local distribution utility as well as differences in the costs of providing service to each class. Rate benefits may also vary among customers within the major customer class categories, depending upon the specific rate designs adopted by the Board of Directors. Customer Understanding The goal of customer understanding involves rate designs that are relatively straightforward so that customers can readily understand how their bills are calculated. This not only minimizes customer confusion and dissatisfaction but will also result in fewer billing inquiries to MEA's customer service call center. Customer understanding also requires rate structures to make sense (i.e., there should not be differences in rates that are not justified by costs or by other policies such as providing incentives for conservation). Revenue Sufficiency MEA's rates must collect sufficient revenue from participating customers to fully fund MEA's annual budget. Rates will be set to collect the adopted budget based on a forecast of electric 47 December 2009 sales for the budget year. Rates will be adjusted as necessary to maintain the ability to fully recover all of MEA's costs, subject to the disclosure and due process policies described later in this chapter. Rate Design Marin Clean Energy's rate designs will initially generally mirror the structure of PG&E's generation rates so that similar rate impacts can be provided to MEA's customers. For example, PG&E's residential rates include different rates applicable to five increasing tiers of consumption; as customers use more energy, the rate progressively increases to encourage conservation. MEA's rates may similarly follow a five -tier structure. Rates for other customer classes include peak demand charges and other charges that vary based on the time period during which the energy or peak demand is consumed (time -of -use rates). MEA will generally match the rate structures from the utilities' standard rates to avoid the possibility that customers would see significantly different bill impacts as a result of changes in rate structures when beginning service in MEA's program. MEA may also introduce new rate options for customers, such as rates designed to encourage economic expansion or business retention within MEA's service area. Net Energy Metering Customers with on-site generation eligible for net metering from PG&E will be offered a net energy metering rate from MEA. Net energy metering allows for customers with certain qualified solar or wind distributed generation to be billed on the basis of their net energy consumption. The PG&E net metering tariff (E -NEM) requires the CCA to offer a net energy metering tariff in order for the customer to continue to be eligible for service on Schedule E - NEM. The objective is that MEA's net energy metering tariff will apply to the generation component of the bill, and the PG&E net energy metering tariff will apply to the utility's portion of the bill. MEA will pay customers for excess power produced from net energy metered generation systems in accordance with the rate designs adopted by the MEA Board. Disclosure and Due Process in Setting Rates and Allocating Costs among Participants Initial program rates would be adopted by the Board of Directors following the establishment of the first year's operating budget prior to initiating the customer notification process. Subsequently, the General Manager, with support of appropriate staff, advisors and committees, will prepare an annual budget and corresponding customer rates and submit these as an application for a change in rates to the Board of Directors. The rates will be approved at a public meeting of the Board of Directors no sooner than sixty days following submission of the proposed rates, during which affected customers will be able to provide comment on the proposed rate changes. MEA will initially adopt customer noticing requirements similar to those the CPUC requires of PG&E. These notice requirements are described as follows: Notice of rate changes will be published at least once in a newspaper of general circulation in the county within ten days of after submitting the application. Such notice will state that a copy of said application and related exhibits may be examined at the offices of MEA as are specified in the notice, and shall state the locations of such offices. 48 December 2009 Within forty-five days after the submitting an application to increase any rate, MEA will furnish notice of its application to its customers affected by the proposed increase, either by mailing such notice postage prepaid to such customers or by including such notice with the regular bill for charges transmitted to such customers. The notice will state the amount of the proposed increase expressed in both dollar and percentage terms, a brief statement of the reasons the increase is required or sought, and the mailing address of MEA to which any customer inquiries relative to the proposed increase, including a request by the customer to receive notice of the date, time, and place of any hearing on the application, may be directed. 49 December2009 This chapter discusses customer rights, including the right to opt -out of the CCA Program, as well as obligations customers undertake upon agreement to enroll in the CCA Program. All customers that do not opt out within 30 days of the fourth opt -out notice will have agreed to become full status program participants and must adhere to the obligations set forth below, as maybe modified and expanded by the MEA Board from time to time. By adopting this Implementation Plan, the MEA Board approved the customer rights and responsibilities policies contained herein to be effective at Program initiation. The Board retains authority to modify program policies from time to time at its discretion. Customer Notices At the initiation of the customer enrollment process, a total of four notices will be provided to customers describing the Program, informing them of their opt -out rights to remain with utility bundled generation service, and containing a simple mechanism for exercising their opt -out rights. The first notice will be mailed to customers approximately sixty days prior to the date of automatic enrollment. A second notice will be sent approximately thirty days later. MEA will likely use its own mailing service for the initial opt -out notices rather than including the notices in PG&E's monthly bills. This is intended to increase the likelihood that customers will read the opt -out notices, which may otherwise be ignored if included as a bill insert. As required by CPUC regulations, MEA will use PG&E's opt -out processing service. Customers may opt out by notifying PG&E using the utility's automated telephone system or internet opt out processing services. Consistent with CPUC regulations, notices returned as undelivered mail would be treated as a failure to opt out, and the customer would be automatically enrolled. Following automatic enrollment, a third opt -out notice will be included with the final bill containing utility generation charges, and a fourth and final opt -out notice will be included with the first bill containing Program charges. Opt -out requests made on or before the sixtieth day following start of MEA service would result in customer transfer to utility service with no penalty. Such customers will be obligated to pay MEA's charges for electric services provided during the time the customer took service from the Program, but will otherwise not be subject to any penalty or transfer fee from MEA. New customers who establish service within the Program service area will be automatically enrolled in the Program and will have sixty days from the start of MEA service to opt out of the Program. Such customers will be provided with two opt -out notices within this sixty-day post enrollment period. MEA's Board of Directors will have the authority to implement entry fees for customers that initially opt out of the Program, but later decide to participate. Entry fees, if deemed necessary, would help prevent potential gaming, particularly by large customers, and aid in resource planning by providing additional control over the Programs customer base. Entry fees would not be practical to administer, nor would they be necessary, for residential and other small customers. 50 December 2009 Termination Fee Customers that are automatically enrolled in the Program can elect to transfer back to the incumbent utility without penalty within the first two billing cycles of service. After this free opt -out period, customers will be allowed to terminate their participation subject to payment of a Termination Fee, which will be similar to the "Cost Responsibility Surcharge" fees charged by PG&E to customers that take generation service from alternative suppliers. The Termination Fee may apply to all Program customers that elect to return to bundled utility service or elect to take "direct access" service from an energy services provider. Program customers that relocate within the Program's service territory would have their CCA service continued at the new address. If a customer relocating to an address within the Program service territory elected to cancel CCA service, the Termination Fee may apply. Program customers that move out of the Program's service territory would not be subject to the Programs Termination Fee. The Termination Fee will consist of two parts: an Administrative Fee set to recover the costs of processing the customer transfer and other administrative or termination costs and a Cost Recovery Charge that would apply in the event MEA is unable to recover the costs of supply commitments attributable to the customer that is terminating service. PG&E will collect the Administrative Fee from returning customers as part of the final bill to the customer from the CCA Program and will collect the Cost Responsibility Charge (CRC) as a lump sum or on a monthly basis pursuant to a negotiated servicing agreement between MEA and PG&E. The Administrative Fee would vary by customer class as set forth in the table below. Administrative Fee for Service Termination Customer Class Fee Residential $5 Small Commercial $5 Medium Commercial $10 Large Commercial $25 Industrial $25 Street Lighting $10 Agricultural and Pumping $10 The customer CRC will be equal to a pro rata share of any above market costs of MEA's actual or planned supply portfolio at the time the customer terminates service. The proposed CRC is similar in concept to the Cost Responsibility Surcharge charged by PG&E, and it is designed to prevent shifting of costs to remaining Program customers. The CRC will be set on an annual basis by MEA's Governing Board as part of the annual ratemaking process. The long-term financial projections contained in Chapter 7 indicate that MEA may be able to offer rates that are equivalent to those charged by PG&E and that MEA's supply portfolio is projected to be competitive in the marketplace in part because of the financing advantages that MEA enjoys. Under those conditions, most customers would not be expected to terminate their service with MEA to return to the utility. Furthermore, if customers do terminate service, MEA should be able to re -market the excess supply and fully recover its costs. Although the Cost 51 December 2009 Recovery Charge may not be needed for recovery of stranded costs, MEA's ability to assess a Cost Recovery Charge, if necessary, is an important condition for obtaining financing for MCE's power supply. The low cost financing will, in turn, enable MEA to charge rates that are competitive with PG&E's. The CRC will also enhance the credit profile of the Program as it relates to credit exposure from the electricity suppliers' point of view. Absent a CRC, the Program will likely need to post cash collateral to match its credit exposure to the Programs electric supplier(s), which would increase costs to MEA customers. The circumstance that would trigger application of the CRC would be if PG&E rates unexpectedly drop below those of MEA and customers wish to leave the Program to return to PG&E or take service from a different generation supplier. In that scenario, the CRC would reduce some of the customer benefits from switching back to PG&E or the alternative supplier. The Termination Fee will be clearly disclosed in the four opt -out notices sent to customers during the sixty-day period before automatic enrollment and following commencement of service. The fee could be changed prospectively by MEA's Board of Directors, subject to MEA's customer noticing requirements. Customers electing to terminate service would be transferred to PG&E on their next regularly scheduled meter read date if the termination notice is received a minimum of fifteen days prior to that date. Customers who voluntarily transfer back to PG&E would also be liable for the nominal reentry fees imposed by PG&E as set forth in the applicable utility CCA tariffs. Such customers would also be required to remain on bundled utility service for a period of three years, as described in the utility tariffs. Customer Confidentiality MEA will establish policies covering confidentiality of customer data. MEA's policies will maintain confidentiality of individual customer data. Confidential data includes individual customers' name, service address, billing address, telephone number, account number and electricity consumption. Aggregate data may be released at MEA's discretion or as required by law or regulation. Responsibility for Payment Customers will be obligated to pay MEA charges for service provided through the date of transfer including any applicable Termination Fees. Pursuant to current CPUC regulations, MEA will not be able to direct that electricity service be shutoff for failure to pay MEA's bill. However, PG&E has the right to shut off electricity to customers for failure to pay electricity bills, and Rule 23 mandates that partial payments are to be allocated pro rata between PG&E and the CCA. In most circumstances, customers would be returned to utility service for failure to pay bills in full and customer deposits would be withheld in the case of unpaid bills. PG&E would attempt to collect any outstanding balance from customers in accordance with Rule 23 and the related CCA Service Agreement. The proposed process is for two late payment notices to be provided to the customer within 30 days of the original bill due date. If payment is not received within 45 days from the original due date, service would be transferred to the utility 52 December 2009 on the next regular meter read date, unless alternative payment arrangements have been made. The proposed policy limits collections exposure to two months bills, consistent with the proposed deposit policy explained below. This policy may be modified by MEA's Board based on experience or regulatory changes that would provide MEA with shutoff rights for non- payment. Consistent with the CCA tariffs, Rule 23, service cannot be discontinued to a residential customer for a disputed amount if that customer has filed a complaint with the CPUC, and that customer has paid the disputed amount into an escrow account. Customer Deposits Customers may be required to post a deposit equal to two months' estimated bills for MEA's charges to obtain service from the Program. Failure to post deposit as required would cause the account service transfer request to be rejected, and the account would remain with PG&E. Customer deposits would be required based on the Program's credit policy to be adopted by MEA's Board of Directors. It is anticipated that the Program's credit policy would be similar to the customer credit policies employed by PG&E. 53 December2009 Introduction This Chapter describes MEA's initial procurement policies and the key third party service agreements by which MEA will obtain operational services for the CCA Program. By adopting this Implementation Plan, the Authority's Board of Directors approved the general procurement policies contained herein to be effective at Program initiation. The Board retains authority to modify Program policies from time to time at its discretion. Procurement Methods MEA will enter into agreements for a variety of services needed to support program development operation and management. It is anticipated MEA will generally utilize Competitive Procurement methods for services but may also utilize Direct Procurement or Sole Source Procurement, depending on the nature of the services to be procured. Direct Procurement is the purchase of goods or services without competition when multiple sources of supply are available. Sole Source Procurement is generally to be performed only in the case of emergency or when a competitive process would be an idle act. MEA will utilize a competitive solicitation process to enter into agreements with entities providing electrical services for the program. Agreements with entities that provide professional legal or consulting services, and agreements pertaining to unique or time sensitive opportunities, may be entered into on a direct procurement or sole source basis at the discretion of MEA's General Manager or Board of Directors. The General Manager will be required to periodically report (e.g., quarterly) to the Board a summary of the actions taken with respect to the delegated procurement authority. Authority for terminating agreements will generally mirror the authority for entering into the agreements. Key Contracts Electric Supply Contrast MEA is in the process of negotiating a long-term (through May 31, 2015) electricity supply contract with a qualified provider. For the initial five years of program operations (6/1/2010 through 5/31/2015), the third party provider will supply electricity to customers under a full requirements contract between the provider and MEA. For the post -2015 period, MEA will be obligated to complete additional solicitations to secure its resource portfolio. MEA will seek to begin such procurement sufficiently in advance so that the transition from the initial full requirements contract occurs smoothly, avoiding dependence on market conditions existing at any single point in time. Under the initial full requirements contract, the supplier commits to serve the composite electrical loads of customers in the Program. The supplier is responsible for ensuring that a certified Scheduling Coordinator schedules the loads of all customers in the Program, providing necessary electric energy, capacity/resource adequacy requirements, 54 December 2009 renewable energy and ancillary services. The supplier is wholly responsible for the Program's portfolio operations functions and managing the predominant supply risks for the term of the contract. The supplier must meet the Programs renewable energy goals and comply with all applicable resource adequacy and regulatory requirements imposed by the CPUC or FERC. Certain financial risks related to changes in Program loads during the term of the agreement are borne by the supplier, within the ranges specified in the electric supply agreement. The supplier must also specify the renewable content of the supply portfolio that will be used to supply the program for each year of the agreement term. Renewable energy disclosed must qualify to meet the California RPS and must be no less than 25 percent throughout the delivery period. The supplier is also required to procure sufficient renewable energy to meet the requirements of serving customers enrolled in the Deep Green MEA service option. MEA anticipates executing the electric supply contract for Phase 1 loads in February 2010. The contract for Phase 2 loads will be executed approximately four months prior to commencement of service to Phase 2 customers. Data Management Contract A data manager will provide the retail customer services of billing and other customer account services (electronic data interchange or EDI with PG&E, billing, remittance processing, and account management). Recognizing that some qualified wholesale energy suppliers do not typically conduct retail customer services whereas others (i.e., direct access providers) do, the data management contract is separate from the electric supply contract. A single contractor will be selected to perform all of the data management functions?B The data manager is responsible for the following services: ➢ Data exchange with PG&E; ➢ Technical testing; ➢ Customer information system; ➢ Customer call center; ➢ Billing administration/retail settlements; and ➢ Reporting and audits of utility billing. Utilizing a third party for account services eliminates a significant expense associated with implementing a customer information system. Such systems can cost from five to ten million dollars to implement and take significant time to deploy. A longer term contract is appropriate for this service because of the time and expense that would be required to migrate data to a new system. Separation of the data management contract from the energy supply contract gives MEA greater flexibility to change energy suppliers, if desired, without facing an expensive data migration issue. 16 The contractor performing account services may be the same entity as the contractor supplying electricity for the program. 55 December 2009 It is anticipated that MEA will execute a contract for data management services in January 2010. Electric Supply Procurement Process MEA issued a request for proposals for full requirements energy, renewable energy and resource adequacy capacity as part of a competitive solicitation process. The short list of potential energy suppliers selected as a result of this process reflected a highly qualified pool of suppliers for further negotiations, which will be completed prior to the Authority's registration as a CCA. The timeline for the initial solicitation is as follows: Release RFP Pre -Bid Meeting Deadline for Question Submittal Responses Due Notification of Short List Short List Interviews Contract Negotiation Contract Approval and Execution Commence Service May 11, 2009 May 27, 2009 June 10, 2009 July 20, 2009 August 11, 2009 Week of August 17, 2009 August - November, 2009 February 2010 June 2010 On July 20, 2009, MEA received bids for third -party power supply from twelve companies. The bids were ranked based upon the following criteria: ➢ Price of energy supply; ➢ Financial viability of respondent; ➢ Operational experience of respondent; ➢ Reliability and environmental attributes of proposed power supply; and ➢ Demonstrated understanding of Program requirements. Based upon these criteria, subsequent negotiations and final energy pricing MEA selected three energy suppliers, described below, for the short list of firms who may provide electricity for the Program under an initial full requirements contract. Final supplier selection is scheduled to be made by the MEA Board in February 2010. Shell Energy North America Shell Energy North America (US), L.P. (SENA) is a leading supplier of energy and associated services in North America. SENA provides natural gas, electrical energy and capacity, scheduling and asset optimization, risk management, and renewable energy and environmental products to a wide variety of customers. SENA is 100% owned by Royal Dutch Shell Company and its subsidiaries. SENA owns and manages a variety of energy assets in the West, including generation, a portfolio of renewable energy, transmission capacity, natural gas production, liquefied natural gas capacity, natural gas storage capacity, and natural gas pipeline capacity. 56 December 2009 SENA's West Region operation includes regional offices in San Diego, Portland, Spokane, Berkeley, Salt Lake City, Denver and Mexico City, with 7 X 24 power and gas operations in San Diego and Spokane. SENA has an extensive list of public and privately owned customers in the West, including all WECC region investor-owned utilities, twenty-five publicly owned (municipal) electric utilities/other public agencies in California, and publicly owned utilities/public agencies in neighboring states. SENA's West Region full requirements power experience includes provision of retail electric service, including provision of resource adequacy, for direct access customers in California. Renewable energy products offered by SENA include renewable energy, bundled renewable energy, landfill gas, biogas and renewable energy credits. SENA states it is actively developing renewable portfolios and provides related services such a scheduling and shaping of intermittent energy. SENA's affiliate, Shell WindEnergy, develops and owns wind generation in California and other parts of North America. SENA also offers a variety of environmental products including emission offsets and other carbon reducing products. SENA is rated A- by S&P and A2 by Moody's. Constellation Energy Commodities Group Constellation Energy Commodities Group, Inc. ("CCG") is a wholly owned subsidiary of Constellation Energy Group, Inc. with experience in serving wholesale and retail load throughout North America. In 2008 CCG reports it served a peak load of approximately 27,000 MW. CCG serves approximately 750 MW of direct access load in California and has been a Scheduling Coordinator for nine years. CCG's portfolio management team consists of several traders managing day -ahead and term positions, as well as at least 8 real-time traders managing positions on an hourly basis. CCG also has several Originators focused on both adding to and optimizing its load -serving positions. CCG's team has several decades of combined experience serving load in both California and across North America. CCG owns and operates 9,042 MW of generation throughout North America, including several Qualifying Facilities in California. CCG's parent company is rated BBB by S&P and Baa3 by Moody's. Macquarie Cook Power Inc. Macquarie Cook Power Inc. (MCP) is a Houston based electricity trading and marketing company servicing North American electricity generators, utilities, municipalities and cooperatives. MCP is a wholly owned subsidiary of Macquarie Group Limited, based in Sydney, Australia, a diversified, global financial services organization with total assets under management of US$200 billion. MCP was established in 2006 and currently trades physically and/or financially in PJM, NYISO, NEPOOL, MISO, CAISO, and the WECC markets. MCP staff has worked on all aspects of the development and management of generation including, fuel management for and power sales and scheduling of the units. MCP maintains a fully -staffed 24 hour real time trading desk. 57 December 2009 MCP parent company, Macquarie Bank Limited, is rated A by S&P and Al by Moody's MCP's relevant experience includes: recent acquisition of rights to hydro -electric facilities in the Pacific Northwest, energy management agreements for two peaking natural gas plants in Southern California, management of a combined cycle plant in Southern New Jersey through a tolling agreement, provision of full requirements load following service in Maryland and New Jersey, and provision of shaping and firming services for imports of renewable energy into California to meet RPS requirements. 58 December 2009 Introduction This Chapter describes the process to be followed in the case of Program termination. By adopting this Implementation Plan, the Authority's Board of Directors approved the general termination process contained herein to be effective at Program initiation. In the unexpected event that MEA would terminate the Program and return its customers to PG&E service, the proposed process is designed to minimize the impacts on its customers and on PG&E. The proposed termination plan follows the requirements set forth in PG&E's tariff Rule 23 governing service to CCAs. The Board retains authority to modify program policies from time to time at its discretion. Termination by Marin Clean Energy The Authority plans to offer services for the long term with no planned Program termination date. In the unanticipated event that the majority of the Member's governing bodies (County Board of Supervisors and/or City/Town Councils) decide to terminate the Program, each governing body would be required to adopt a termination ordinance or resolution and provide adequate notice to MEA consistent with the terms set forth in the JPA Agreement. Following such notice, MEA would vote on Program termination subject to a two-tiered vote, as described in the JPA Agreement. In the event that the Board affirmatively votes to proceed with JPA termination, the Board would disband under the provisions identified in its JPA Agreement. After any applicable restrictions on such termination have been satisfied, notice would be provided to customers six months in advance that they will be transferred back to PG&E. A second notice would be provided during the final sixty -days in advance of the transfer. The notice would describe the applicable distribution utility bundled service requirements for returning customers then in effect, such as any transitional or bundled portfolio service rules. At least one year advance notice would be provided to PG&E and the CPUC before transferring customers, and MEA would coordinate the customer transfer process to minimize impacts on customers and ensure no disruption in service. Once the customer notice period is complete, customers would be transferred en masse on the date of their regularly scheduled meter read date. MEA will post a bond or maintain funds held in reserve to pay for potential transaction fees charged to the Program for switching customers back to distribution utility service. Reserves would be maintained against the fees imposed for processing customer transfers (CCASRs). The Public Utilities Code requires demonstration of insurance or posting of a bond sufficient to cover reentry fees imposed on customers that are involuntarily returned to distribution utility service under certain circumstances. The cost of reentry fees are the responsibility of the energy services provider or the community choice aggregator, except in the case of a customer returned for default or because its contract has expired. MEA will post a bond in the appropriate amount as part of its registration materials and will maintain the bond in the required amount, as necessary. 59 December 2009 Termination by Members The JPA Agreement defines the terms and conditions under which Members may terminate their participation in the program. 60 December2009 Appendix A: Authority Resolution 2009-10 Appendix B: Marin Energy Authority Joint Powers Agreement 61 December 2009 Exhibit V 2009-2010 Marin County Civil Grand Jury Marin Glean Energy: Pull the Plug Date of Report. Pecember 2.2009 SUMMARY Marin County Civil Grand Jury Marin Clean Energy: Pull the Plug Programs to preserve the environment clearly serve the interests of all Marin residents. The Grand Jury strongly supports the goal of achieving greater use of renewable and alternative energy sources as a means of reducing greenhouse gases. The issue explored in this report is not the need for "going green", but rather how to achieve that goal in a manner that can be measured for success. The Grand Jury has concluded that the costs of the Marin Clean Energy (MCE) program remain undefined and the benefits are IikeIy to be minimal. We believe there are alternative approaches that will better serve the community than the unproven and risky one now being proposed by the Marin Energy Authority (MEA). . The MEA, a recently formed Joint Powers Authority (JPA), is proposing the creation of the MCE program. The intent is to provide a higher percentage of electricity from renewable sources than is currently available through Pacific Gas & Electric (PG&E). This energy would be resold to residents, businesses and municipalities in the participating communities. The MEA Board would establish rates and policies and would eventually. own and operate commercial power generating facilities. The transmission and distribution of electric power, as well as maintenance and billing, would.continue to be performed by PG&E. Natural gas would not be part of this program_ The county and eight municipalities have expressed a tentative willingness to join, while the cities of Corte Madera, Larkspur and Novato have declined. The MEA Board has' scheduled a final vote on February 4, 2010 regarding Whether to proceed with the proposal. Unless a city council or the Board of Supervisors (BOS) decides to withdraw, that community will automatically be a participant. According to the 2008 Community Choice Aggregation (CCA) Business Plan, the JPA plans to borrow approximately $6.4 million during its initial year for start-up and working capital. An additional $15.8 million of working capital will be required in subsequent years. The availability and sources of these funds have not been determined. Emphasis will be placed on providing long-term stability by eventually owning and operating renewable energy resources such as geothermal power plants, and wind and solar farms. To achieve this goal MEA plans to borrow an additional $475 million. The MEA Board of Directors, composed of one elected official from each of the participating jurisdictions, will have responsibility for signing contracts for the purchase of December $ 2009 Marin County Civil Grand Jury Page 1 of 23 Marin Clean Energy* Pull the Plug power, setting rates for consumers, and overseeing the construction and financing of new generating facilities. MEA projects it will have approximately 100,000 customers who will be paying the costs of this new layer of bureaucracy. Protecting the environment is in everyone's best interests. We believe there are many pathways to accomplish this, but any solution must be achievable and measurable. More stringent national and state regulations are requiring all energy producers to meet increased carbon neutral standards. PG&E will be required to meet these standards, as well. In these economically challenged and difficult times, we question the decision to put the county into the business of operating commercial power generation facilities, a function not usually associated with the government of a small county. The Grand Jury recommends that the MCE program be abandoned. We strongly urge the county and MEA to step away from their adversarial public posturing and seriously work with PG&E. No matter what has happened before, the time has come to foster cooperation. Efforts and money need to be directed toward forming a public/private partnership that will create an effective clean energy program that will help the county and cities achieve present and future environmental goals. To PG&E we say, return to the table and work with Marin County. We support the efforts of all communities to work toward a more favorable mix of renewable energy. We also recognize that you have the expertise and the financial strength to be California's leader in protecting the environment. We ask you to partner with Marin to become a model for reducing greenhouse gas (GHG) emissions. It is a mutually beneficial goal.. Citizens of Marin are being led down a costly and extremely risky path not yet traveled by any other community in California. All costs incurred by MCE must be home by the ratepayers as they are its sole source of revenue. An increment above the cost of power will be added to the ratepayer bill to cover all operating and financing expenses. Finally, MCE could present unforeseen legal and financial risks to the participating cities, the County of Marin, and the citizens as taxpayers. Every dollar expended by MEA must be recovered from the ratepayers. Therefore, it is the Grand Jury's recommendation that the Marin Clean Energy program be abandoned. BACKGROUND The passage of the CCA law in 2002, Assembly Bill 117 (ABI 17), enabled local governments to assume an active role in managing their electricity -supplies through the selection of generation sources, investments in new power facilities, and rate setting. Once formed, a CCA is responsible for providing the energy commodity to its ratepayers. The existing utility provider, PG&E, remains responsible for the delivery, service, and billing of the electrical product as well as the supply of natural gas. To reap the benefits, the CCA will need to plan for financing, development, ownership, and operation of electric generating resources. Since passage of the law, many California communities have December 2, 2009 Marin County Civil Grand Jury Page 2 of 23 Merin Clean Energy: Pull the Plug investigated, researched, and/or attempted to form a CCA. As of the writing of this report, no CCA has yet been created in California. MEA was formed in December 2008. As stated in the business'plan, the county and participating cities would form a partnership to facilitate efforts to reduce greenhouse gas emissions from energy, provide more renewable energy.choices, and create price stability. By June of 2009, this Authority counted among its tentative members the County of Marin and the cities of Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San.Rafael, Sausalito and Tiburon. The legislation created clear off -ramps so that communities could withdraw during the study period. To date, Corte Madera, Larkspur and Novato have elected not to pursue membership. Marin Clean Energy is the CCA program proposed by MEA to buy power directly from a contracted supplier in order to increase the percentage of renewable energy provided to participating customers. Under its current business plan, the MEA would sign a 5 -year contract with an independent service provider.to supply the energy. At some point, long term financing would be sought to actually begin the purchase and/or construction of renewable energy sources, i.e., wind farms, large-scale solar installations, biomass, and geothermal. According to the proposal, the MCE program would reduce Marin's greenhouse gas emissions, increase price stability, fuel small locally based green businesses, and enable local decision-making over the source, rate, and mix of electrical power used in Marin. Legislation and executive orders are having a powerful impact on the rapid move toward carbon -neutral production. These mandates will force PG&E and all other energy suppliers to move aggressively toward renewable and carbon -free production. Energy innovation is changing daily. As a result, legislative and regulatory bodies are quickly adopting policies and procedures to take advantage ofthe latest technology. The most current and important legislative programs to be enacted are: • California's landmark green legislation was signed three years ago (AB32), requiring the reduction of greenhouse gases to 1990 levels by 2020. • California's existing Renewable Facilities Program set a goal of having 20% of retail electricity generated from renewable sources by 2010. This program is designed to establish a competitive, self-sustaining renewable energy supply while increasing the near -tern quantity of renewable energy generated within California. • On September 17, 2009, Governor Sebwarzenegger signed Executive Order S-21-09, requiring that at least 33% of the state's energy creation and use by 2020 will be from renewable energy. A major purpose for this Order is to assure that utilities will have access to renewable power sources outside of California in order to meet the state's aggressive goals. December 2, 2009 Marin County 001 Grand Jury Page 3 of 23 Marin Clean Energy: Pull the Plug • AB 811 passed in July 2008, allows California cities and counties the ability, to offer.low-interest loans for energy -efficiency projects and solar panels to homeowners and small businesses. Relieved of high up -front costs, residents would repay the loans through assessments on property tax bills. If the home is sold, the outstanding loan balance is taken over by the new owner. Two solar bills were signed into law in California on October 12, 2009. AB 920 requires owners of solar or wind generation systems to be compensated for any surplus energy that they produce. SB32 was passed to encourage solar installations on large commercial spaces such as parking facilities and warehouse rooftops. The Bill requires utility companies to purchase excess solar electricity at a set rate over a twenty-year period. . METHODOLOGY Like any new program or project that is in the development stage, MEA is subject to change as new information comes to light. The difficulty for the Grand Jury has been to determine what and when changes have been made. The 2008 CCA Business Plan was produced in April 2008. Since its publication, significant changes have been made. However, the documentation for these changes is absent. The business plan is an outdated document. The Grand Jury interviewed representatives and staff of the County of Marin, representatives and committee members of the MEA, and members of the Board of Supervisors (BOS). Interviews -were also conducted with representatives of several of Marin's municipalities. In addition, interviews were conducted with consultants of the firm that prepared the business plan, as well as independent consultants hired to review that plan. Representatives of PG&E, the California Independent System Operator (CAISO) and the California Public Utilities Commission (CPUC) were also interviewed. Jurors attended council meetings of municipalities participating in MEA, meetings of the MEA Board and its working committees, and meetings of the BOS. Individuals representing opinions or organizations that support and oppose the proposed CCA also were interviewed. The Grand Jury reviewed information including budgets, business plans and independent reviews of CCA viability, MEA studies and reports, minutes of MEA , the Board of Supervisors and municipal council meetings, and archived video and Power Point presentations from MEA and the BOS. CCA programs considered by four other California communities were studied for applicable comparison to the proposed MCE program. 'A significant body of literature on the formation, risks and benefits of a CCA was also studied. For more detail on the information considered by the Grand Jury, please refer to the bibliography at the end of this report: December 2, 2009 Mann County Civil Grand Jury � Page 4 of 23 Marin Clean Energy: Pull the Plug DISCUSSION The following discussion is designed to enable Marin's elected officials and the citizens they represent to fully appreciate and understand the scope and implications of the decision they are about to make. Due to the. complexity of the issue, most citizens have not taken the time to review the 100+ page business plan or the various alternative options. The major questions are: . • Do consumers and municipalities understand this complex plan and what it will mean to them? • How does the opt -out policy work? • How many households and businesses will opt -out? • If the opt -out number is large, will the remaining pool of customers be enough to support MEA's fixed expenses? •. Does the MEA Board have the professional expertise to compete in what has been a historically volatile and highly competitive business? • Does it make sense to create anew level of bureaucracy by putting the county into the power business at a time when core services are being severely reduced? • Will MCE accomplish the environmental goals outlined by MEA? What will the benefits be and at what cost? Where is the cost benefit analysis? Organization of MEA MEA is governed by a Board of Directors, composed of one elected representative from each of the participating jurisdictions. The primary duties of the Board are to establish program policies; set rates; provide policy direction to the Executive Director, and determine staffing, and compensation. The day-to-day operations of MCE will be under the direction of an Executive Director to be hired by the Board of Directors. During the initial stage of the program, most of the operational responsibilities will be performed by the third party electric provider. These will include the technical functions associated with managing electric supplies and retail customer accounts. In the long-term, MEA may choose to have these functions performed by internal staff. December 2, 2009 Marin County Civil Grand Jury. Page 5 of 23 Marin Clean Energy: Pull the Plug Where Do We Stand Today? At this time, the MEA member cities, towns and the BOS, are in a 90 -day period to review the contract that has been drafted with Shell Energy of North America, (US) PL. The MEA board is currently scheduled to vote on formation of the MCE program on February 4, 2010. The absence of a vote to withdraw would result in the wholesale transfer of all PG&E customers in those respective jurisdictions to MCE upon contract execution. Transfer of service will follow a phased approach: • Phase I - municipal, commercial, industrial, and some residential accounts (20% of the customer base) by June 2010; • Phase Il -all remaining commercial and residential 'accounts (80% of the customer base) by January 2012. As proposed, all utility customers within the unincorporated area of the County of Marin and the participating cities and towns in the JPA, will automatically have their electricity supplied by MCE instead of PG&E unless they take affirmative action not to participate (opt -out). Regardless of the consumer's election, as owner of the electric transmission and distribution network, PG&E will continue to transmit the electricity to homes and. businesses, maintain all physical infrastructure, and process billing. Resource Procurement Strategy: In May 2009, MEA issued a Request for Proposal (RFP) for the supply of electric energy. The RFP requested that the bidders provide two fixed prices: • Light Green with a minimum of 25% renewable energy • Deep Green with 100 % renewable energy Of the twelve bidders to the RFP three were deemed acceptable. Shell was selected as the prime candidate. The contract is based on the standard "Master Power Purchase and Sale Agreement" Version 2.1 (4/25/2000) developed by Edison Electric Institute. Although a good basis from which to start, this version of the Master Agreement by no means covers all of the requirements and unique Marin conditions and contingencies that would be involved in the supply of energy from renewable sources. Selected sections have been released, but a complete contract has not been available for a comprehensive review. The objective of MEA is to provide Light Green energy (25% renewable) to the ratepayer at a price at or below PG&E's generating price. The promised rate to "meet or beat" only applies to year one for Phase I. Firm prices for Phase 1 will not be known until the completion of the 90 -day review period, after the city and town councils have voted on their final participation in the JPA_ The price for Phase II residential (80% of the program base) may not be set or known until late 2011 or early 2012. No such guarantee has been Decennber Z, 2009 Mann County Civil Grand Jury Page 6 of 23 Marin Clean Energy. Pull the Plug made for Phase II customers. In making this statement MEA is comparing -its probable Price to the projected PG&E generating rates. Energy pricing can be very volatile, and use of historical data may not always reflect future rates. It is purported by MEA that the firm price for Deep Green energy (100% renewable sourced) will be offered at a premium price of 5 to 10% above the Light Green option. It remains speculative how much this will actually be until. the contract is executed. Based on information reviewed, the Grand Jury believes this projection to be low. As of the publication date of this report, MEA has developed a Phase I contract with Shell Energy of.North America, in first position as the energy service provider. The Phase I pricing when set in February 2010, is to be for a period of 5 years, starting June 1, 2010. In addition to this contract, the MEA must file an Implementation Plan with the CPUC. It is expected to be filed in December 2009. MEA estimates that of those customers who do not opt -out of MCE, 80% will elect the Light Green option and 20% will opt for the Deep Green alternative. Although not revealed in available public documents, MEA representatives have stated at public meetings that customers not choosing the Deep Green option will be automatically enrolled in the Light Green option. How Will These Goals Be Achieved? The goal of MEA for the first 5710 years is to provide customers of the Light Green option a rate offering at or below the projected rates of PG&E, and an estimated Deep Green rate ata 5 to 10% premium. The electrical service provider will act as a commodity broker but might not generate the power to fulfill the conditions of the contract. This power will have to be purchased from existing renewable sources. No new sources will necessarily be developed. MEA plans to acquire and own renewable sourced generation facilities. The objective over the next 20 years is to progressively meet the demand with a mix of solar, wind, biomass, and geothermal power. Assuming that reserves can be accumulated to provide debt service, ownership or part ownership of renewable sourced power is envisioned. The belief is that ownership should help stabilize price volatility and reduce energy price risk. Renewable generation does not require a fossil fuel source. A key aspect of the business plan is that it will benefit Marin County by bringing new jobs and employment to the local economy. The Marin County General Plan envisions, the main population and business centers are to be in the City Centered Corridor along Highway 101. Open space and agricultural are to be concentrated in West Marin. Considering the size and topography of each sector, there is very little opportunity to develop large wind and solar installations. The most feasible power generating installations in the City Ccntered Corridor would be limited to solar panels on roollops of businesses, parking facilities and homes. With all of the environmental restrictions in West Marin, it would be December 2, 2009 - Marin County Civil Grand Jury Page 7 of 23 Marin Clean Energy: Pull the Plug difficult to imagine any major solar or wind project surviving the environmental review stage. The business plan states that large generation facilities may also be developed or purchased in areas outside of Marin such as Solano and the Altamont Pass. The potential for increased employment and new job opportunities in the county appears to be very limited. The business plan that was introduced in April 2008 has become a moving target that needs updating. Since that time, some of the assumptions, dates and financials have changed due to new information and decisions. For example, the plan stated that the default plan for customers would be the 100% renewable product, now called Deep Green. As publicly stated in presentations by MEA, the default plan has subsequently been.changed to the Light Green product of 25% renewable. The decision to switch default positions reduces revenue while not materially reducing expenses. In addition, the order in which customers will be added to the program was modified, and will have an impact on the timing of revenue and expenses. These adjustments may bave been quantified, but they are not reflected in the plan. Presentations given to the participating cities have contained updated projections that differ from the plan.. Financing is another concern. The plan identifies approximately $6.4 million needed for working capital to initiate the program, i.e. purchase.the power to bring municipal and commercial customers online. Traditional costs to.be covered include payroll, consultants, contractors, and deposit requirements. The need for credit may increase by $15.8 million to serve Phase 11 customers. This working capital provides for power purchases and overhead prior to the time MEA develops its own generation facilities. At that time, MEA plans to seek a final round of long-term financing, estimated to be $475 million, in order to support development of renewable generation facilities.. The original "seed" money fol• the MEA consists of a series of grants and a January, 2009 loan from the Marin County BOS in three distributions totaling $540,000 to date. This loan is to be repaid during the first year of operation. 1f the MEA does not proceed, it is unclear how the county taxpayers will be repaid. The entity will have no assets or cash flow until . the actual delivery of power and the collection of the payments for that power. . If a government entity guarantees, endorses or collateralizes loans to the MEA, there is financial risk to the taxpayers_ While there may be some financing alternatives available to the MEA, it would appear that it will have to rely on the credit of, or collateral. from, some other entity in order to be deemed "creditworthy". On October 13, 2009, the BOS was advised that it will be asked to provide a guarantee to enable MEA to borrow $2 million. This funding will occur prior to the planned contract execution of February 2010. Total initial credit projections indicate the need for working capital and start-up could exceed $22 million. Following the start-up of the program, the long-term intent of the MEA is to develop and own renewable generation capabilities. Financing appears to be more feasible since that event would not occur until the program had an established ratepayer base in addition to December 2, 2009 ' Marin County Civil Grand Jury Page 8 of 23 Marin Clean Energy; Pull the Plug having built up some reserves during the early years of operation. With proven cash flow and the ability to use the developed generation sources as collateral, the MEA would find receptivity in the markets and would probably be able to accomplish long-term financing to build the sources of power and repay the earlier incurred debt. The burden of repayment will be on the ratepayers. This may be reflected in higher monthly utility bills. if financing fails, MEA will be in the business of purchasing power. indefinitely. Opt -Out Provision Once operational, all participating cities and the county will be transferred to the MCE program. As noted by multiplestudies, this project is dependent upon the automatic transfer of all customers. The participation level that is critical to success may not be achieved if the consumer is required to opt -in. AB117 allows the nine members of the MEA Board to vote for formation. Consequently, all customers within the participating jurisdictions would automatically be transferred to MCE without customer or voter approval. A recent New York Times article (November 17, 2009) explains that the sign-up rate for alternative renewable programs run by utilities is only about 2%, despite growing public interest. Solar and wind power generally are more costly than power generated by fossil fuel's. The article goes on to say that while many people support alternative energy in principle, they personally may not want to spend hundreds of dollars more for electricity, especially in the current economic environment. The burden of choice, therefore, is placed upon the individual customer. Residents will be required to respond to the MCE opt -out notification if they prefer to stay with PG&E. MCE plans to send out four such notifications over a 120 -day period; beginning 60 days prior to automatic transfer. The following attributes of the opt -out provision remain to be addressed in public documents: How much will the ratepayers pay in penalties and exit fees if they opt -out after the 120 -day period? How will ratepayers be notified of the opt -out process and the effective dates of withdrawal? Benefits MEA sees implementation of the MCE program as the best too] available to achieve significant progress toward its goals. MCE continues to be perceived as the major driving force to reduce greenhouse gas emissions in Marin County. Benefits may include: • Customer Choice: The cities and county will have the ability to choose different renewable energy levels and benefit from long-term cost competition. December 2, 2009 Marin County Civil Grand Jury Page 9 of 23 Marin Clean Energy: Pull the Plug • Cost Stability: Costs may be locked in through power purchase agreements and owned generation assets. • Focus on Customer Needs: The MCE program will bring value to customers by setting rates that are tailored to local needs. • Local Control: Policy direction and rate setting will be the responsibility of the MEA board. • Greenhouse Gas Reduction: The MCE program will aid in reducing GHG levels and help reduce potential compliance costs of AB32. MCE can help by increasing local consumption of renewable energy. Risks The business plan explicitly states that a quantitative risk analysis will be included in a future revision or supplement. Two independent reviews of the business plan repeatedly referred to the need for specific areas to be studied in such a review., The Grand Jury has requested the risk analysis on multiple occasions; it has not yet been provided. Consultants have informed the Grand Jury that further analyses of the contract and pricing may be performed immediately before and after contract execution. The specifies of these reviews are not outlined; whether these reviews will cover the depth of risk analysis suggested by peer reviews is unknown. In an effort to better inform their elected officials, the participating city managers and the County Administrator contracted for an additional review of the service contract. Released by MRW and Associates on November 20, 2009, this report highlights significant risks to MCE customers. The report explores the volatility of energy pricing and encourages MEA to clarify that it may not "meet or beat" PG&E rates going forward. It recommends that MEA develop and publicize their proposed rate structure, identify and address unknown costs in the contract and potential rate discrepancies as Phase lI customers are brought on- line. The Grand Jury strongly urges all participants in MEA to review this report and all others available on the MCE website. The following risks have been identified by the Grand Jury through its research and are categorized as either near-term or long-term. The Grand Jury recognizes that there may be ways to mitigate these risks, but they should be made clear to all involved. With a few exceptions, the risks of MEA are actually risks to the ratepayers who are its sole source of revenue. Near -Term Risks The Contract. The timing of the contract with a supplier may result in a price that does not meet the commitment of MEA to be at or below PG&E's price. As a result, if the MCE program does not go forward, all costs incurred to date will remain with the county. If the contract does deliver the promised price., then additional ratepayer concerns will be: December 2, 2009 Marin County Civil Grand Jury Page 10 o123 - Marin Clean Energy: Pull the Plug • How do the Deep Green rates compare to the current utility rates? How will termination fees be determined in the event MCE customers opt -out? •. How are uncertainties about the number of participants being addressed? • Will a deposit be required? • Have all potential costs been delineated in the contract? Competitive Action. PG&E may take aggressive action to prevent the loss of customers to the MCE program. Such action might include customer outreach; legislative, regulatory and legal challenges, and the introduction of innovative public/private programs. The challenges could significantly impact MCE if ratepayers elect to remain with PG&E. The cost incumbent in combating such competitive action has not been quantified, and could be significant. Market Movement Energy costs are subject to volatile changes. MEA, along with all other buyers and sellers, will be subject to market volatility. PG&E may find it possible to ameliorate the effects of volatility as a high percentage of its generation costs have been fully amortized. With the intensity of legislative activity in this area, costs for renewable energy will likely increase with demand; therefore, long-term contracts may not prove advantageous for MEA. The Grand Jury has been told by various sources that the firm . price for Deep Green energy (100% renewable sourced) will be offered at a premium cost over Light Green energy. It remains speculative as to how much this premium will be until the actual fixed contract prices are known. Credit Availability. As already noted elsewhere, MEA will need to borrow money for start up and working capital before selling any electricity or owning any assets. The county has loaned funds thus far which, according to recent MEA presentations, total $540,000. Repayment is expected during the first year. Larger sums will require more formal credit accommodations, which may be available only with some assistance from the county, or one or more cities. On October 13, 2009, county staff informed the BOS that if the program goes forward, MEA may, need to request guarantees from the county and participating cities in. order to secure credit. It should be noted that even if the cities do not guarantee MEA credit, -it is possible that they would be exposed to future legal action. Reduced Ratepayer Base. The CCA legislation provides that all ratepayers in participating cities and the county will be included in the MEA unless, they take specific action to opt - out. Once a contract is signed for a specific amount of power, any reduction in the number of ratepayers will mean the MEA will have excess power that. must be sold at the current market price. For this reason the business plan states that a "termination fee" will be charged to those that elect to return to PG&E after the initial opt -out period. Neither the amounts nor the calculation formula has been determined. The composition of the ratepayer base is highly skewed to the small business and residential ratepayers, a significant benefit to MEA. Marin demographics include few large users such as the Marin Municipal Water District (MMWD) that would pose risk if they elect to opt -out and return to PG&E. December 2, 2009 - Marin County Civil Grand Jury - Page 11 of 23 Marin Clean Energy: Pull the Plug Legislative and Regulatory Changes. The CCA concept has yet to be activated in California. Any start-up assumes risk that the rales may change. In the New York Times article previously cited, an example of regulatory risk is illustrated with a Florida Power and Light green power program called "Sunshine Energy". The program was terminated last year by the Florida State Public Service Commission, after an audit discovered that promised solar power facilities were far behind schedule and approximately 76% of homeowners' payments went to administrative and marketing expense instead of providing renewable energy. Organization and Staffing. The appointed members of the MEA Board have little or no professional experience in the management of an electric utility company. It is essential that the key managers and staff members should, in addition to managerial and leadership abilities, have knowledge and prior experience in the electric utility business. Expertise in the procurement of power, rate setting, load forecasting, planning, risk management, and customer service will be essential. According to the Business Plan, key positions such as the Executive Director, Policy Analyst, and Sales and Marketing Manager were to be hired prior to the completion of the negotiations of the power supply contract(s). At this time, MEA has not identified individuals ready to step into.these positions. Significant risk exists if there is a lack of personnel possessing proven track records. Long -Term Risks The business plan envisions MEA reducing its reliance on a contract from a single supplier by purchasing or constructing facilities to produce renewable energy. Any look into the fixture must include the possibility that this industry will be substantially different. Some of the short-term risks remain, and some additional considerations are apparent. Technology Changes New technology will almost certainly alter the energy markets. More efficient solar and wind driven energy production is under development. Tidal and other. concepts may be perfected. Tools, sucb.as smart meters that focus on managing the demand side for energy, are already being implemented. This rapidly changing landscape calls for experienced and highly qualified experts to monitor and anticipate changes. For example, such an undertaking as purchasing or building a large scale production facility that is less than state-of-the-art would pose far-reaching consequences for MEA. Failure to anticipate large-scale changes in technology or markets could be devastating. Market Dynamics. As in the near-term, the demand for renewable energy may cause market disruption. Compliance requirements to increase renewable content could drive major suppliers to buy up large segments of the market either by contracting for power or outright purchase of sources. MCE may find it challenging to get into this market and meet the 100% Deep Green option. It should also be recognized that the supply and procurement of renewable sourced energy requires special attention_ The energy production profiles of solar and wind sourced generation are quite different from those of the conventional sourced generation. The production curve of solar, for example, is not a flat production curve even during full sunny days. The production could vary as much as December 2, 2009 - Marin County Civil.Grand Jury Page 12 of 23 Marin Clean Energy: PO the Plug 20 to 30% in a day due to atmospheric conditions. Similarly, wind sourced generation can vary during the day due to variations in wind speed, wind direction and ambient temperature. Consequently the MCE 100% Deep Green plan could be flawed because large hydroelectric, nuclear, and gas -feed generating capacity may be part of the power mix during certain times. Since solar and wind cannot be provided 24 hours a day, MCE would have to purchase Renewable Energy Credits (RECS) to off -set these non-renewable power sources. Construction Feasibility. Current interest rates and construction costs are low due to a slow market. That could change before the MEA is in a position to take advantage of favorable market conditions. Environmental, neighborhood forces and litigation may delay or prevent the approval process and require that production facilities be located far from Mann County, thereby eliminating many of the benefits of local employment and local control. Execution Risk and Accountability. The short and long-term plan for MEA is dependent on the ability to keep abreast of a series of moving targets. The elected officials who will comprise the Board of Directors will need to find highly qualified staff to run MCE on a day-to-day basis. Identification, compensation, and retention will be major elements in staffing MCE. A hiring mistake or a poor business decision will cost both ratepayers and politicians_ MCE will not be a primary concern for the Board as the members are elected to govern other local entities. This is not to say that they will not be diligent, but it does say that their already busy schedules will;become busier. The design and concept of a CCA does not provide much transparency for either the ratepayers or the voters (taxpayers) to determine accountability for the successes or failures of MCE. It's All About the Ratepayers The business plan and presentations have emphasized that the cities and county will have no liability for debts incurred by the MEA. However, the ratepayers will. All of the following expenditures will be added to the ratepayer's bill: • Salaries and benefits • Consultants and legal costs • Marketing and servicing • Contract revision costs • Interest and amortization expense for debt • Bonding obligation • Customer exit fees • All other overhead In addition, in a slow -growth county such as Marin, the number of ratepayers will not grow significantly, and no one really knows how many will choose to opt -out. Coupled with a continued emphasis on energy efficiency, conservation, and the expansion of solar facilities, a scenario similar to what was recently experienced by the MMWD can be December 2, 2009 Mann Caunty Civil Grand Jury Page 13 o123 Marin Clean Energy: Pull the Plug envisioned. Successful conservation efforts reduced the demand for water, yet rates were increased to cover the built-in overhead costs. Demand for electricity may fall if more and more customers install solar and conserve through smart meters. However, the fixed costs of VICE, which include costs for salaries, benefits and debt service, are likely to remain static or increase. For example, the interest cost alone on the $475 million is $19 million per year at a 4% interest rate. Again, the ratepayers will be the only source of revenue for MCE. Claims by MCE and PG&E as to the reductions of GHG are difficult to reconcile. A primary cause for the difficulty is that the definitions of qualifying renewable energy do not include nuclear or large hydroelectric plants, neither of which, once constructed, contributes to GHG. When these sources are included, along with solar and wind; the emission -free content of PG&E generation is already in excess of 50%. In contrast, the emission -free content of MCE for the first year will be close to 25% for an estimated 20% of their ratepayers. At the outset MCE renewable energy will not be new, but purchased from existing sources. No net reductions of GHG will occur until new production comes on line either from their supplier or through the purchase or construction of new facilities. Other Approaches Proponents of MCE have attempted to convince planners and elected officials that the purchase of renewable energy will lessen the need for the difficult task of addressing energy efficiency and the impacts of transportation. The Grand Jury finds that the degree of commitment to MCE has distracted from efforts to reduce the carbon diet of Marin residents. Communities throughout California are aggressively and creatively exploring programs to meet the goal of greenhouse gas reduction. The Grand Jury found innovative and targeted efforts directed at a wide range of improved methods of energy consumption. These include: s Expand cleaner transportation options: 62% of Marin's GHG emissions come from gasoline -powered vehicles. Addressing this issue calls for trip reduction; increased use and availability of public transportation; bicycling; electric and plug- in hybrid vehicles; a shift to alternative fuel vehicles; alternative fuel infrastructure. • Improve building efficiency: Support and promote existing green building standards and programs for residential, commercial, industrial, and governmental structures, and conduct energy audits and require energy efficiency efforts for buildings. • Increase community resource efficiency and reuse: Encourage efficient water use and reuse efforts; promote waste recycling and energy generation; support efficient public and private land use strategies. • Grow renewable energy use: Provide financial incentives, regulatory streamlining, and related efforts to promote rooftop solar systems; support utility shifts to renewable energy sources; support legislative efforts to reach renewable goals. December 2, 2009 - Marin County Civil Grand Jury Page 14 of 23 i Marin Clean Energy: Pull the Plug • Transform business products and practices: Encourage private sector efforts to move to new green product lines in established industries; shift to new materials and more efficient technology. Energy infrastructure: Encourage efforts to build a smart grid, which is a combination of transmission lines and information networks that allows for seamless integration of distributed, renewable sources of electricity, provide better information about usage and pricing (via "smart metering") that can improve energy efficiency. The efforts described above approach goals in a realistic order. Transportation is the major contributor to GHG emissions in Marin. Energy efficiency is also ranked high. Eliminating the need, or reducing the demand for energy, equates to a savings of never having to produce the energy in the first place. Sonoma and Berkeley, two equally environmentally conscious communities, have already implemented other less costly and risky alternatives to achieve reductions in GHG emissions. The Grand Jury notes the efforts of the City of Berkeley as a forerunner in the development of local energy efficiency management. The County of Sonoma and the Silicon Valley Joint Venture have engaged in equally aggressive planning, and have seriously targeted cleaner transportation. Most of these communities include all of the above options and have some form of partnership with PG&E. They have moved ahead without forming new bureaucracies. We found little evidence that either MEA or MCE has fully or seriously explored alternatives, including the partnerships offered by PG&E In addition, the Grand Jury did find evidence of PG&E's willingness.to work with county departments through a variety of cooperative relationships to support green energy and to create the basic components of the MCE program without the above-described risk to ratepayers and taxpayers. That offer was followed by a detailed proposal presented to county staff and the Board of Supervisors in November 2008. At that meeting, the board - voted to discontinue pursuing efforts with PG&E and approved the formation of MEA FINDINGS Fl . The formation of the Marin CIean Energy Community Choice Aggregation creates a new level of government while the county and local communities are experiencing reductions in basic municipal services. F2. The Marin Energy Authority is not required to submit the Marin Clean Energy program to a vote of the public; although legal, this process runs contrary to transparent governance and consumer protection standards. F3. Unless a participating city, town or the County of Marin votes to withdraw from the Marin Energy Authority, residential and business customers will be transferred to the Marin Clean Energy program. December 2, 2009 Marin County Civil Grand Jury - Page 15 of 23 Marin Clean Energy: Pull the Plug F4. The opt -out option means that all consumers in the participating jurisdictions will automatically become subscribers to the new Marin Clean Energy program, unless they decide to take affirmative action not to participate. F5. Neither the Board of Supervisors nor the Marin Energy Authority has fully explored or tried to negotiate partnerships offered by PG&E. F6. The 2008 Community Choice Aggregation Business Plan is outdated and lacks sufficient detail, including current pro -forma data,, updated, market analysis, load projections, customer exit fees and the specified quantitative risk analysis. F7. The construction of owned facilities is a requirement for the success of the Marin Clean Energy program. Due to community resistance and planning constraints, it is highly unlikely that the Marin Energy Authority will succeed with local construction of sufficient large-scale renewable energy sources within Mann County. F8. Neighboring communities have successfully implemented a wide variety of efforts to target energy efficiency and greenhouse gas reduction within their communities through partnerships with local agencies, foundations and PG&E. F9. The degree of commitment to Marin Clean Energy has distracted local agencies from the pursuit of the wide range of other options available to reduce greenhouse gas emissions. FI O. The risks of this venture are far too great to ignore in spite of repeated assurances from the Marin Energy Autbority. Multiple reviews have identified significant ratepayer risks. Fl 1. The service contract recently approved by the Marin Energy Authority Board is incomplete and only covers Phase I and excludes pricing. F12. The actual rates Marin Clean Energy will charge the majority of its customers, most of whom are residential, may not be known until late 2011 or early 2012. 1713. The Grand Jury finds that most monies spent to date have been for professional services of attorneys, consultants and outside peer reviews. The Grand Jury believes that these expenses are indicative of the highly complex nature of this undertaking. F14. Placing this complex, expensive. and volatile business venture in the hands of rotating city/county elected officials charged with other obligations, presents the Marin taxpayers with an unacceptable risk. December 2, 2009 Marin County Civil Grand Jury Page 16 of 23 Marin Clean Energy: Pon the Plug RECOMMENDATIONS The Grand Jury recommends: R1. That the Marin Clean Energy program be abandoned. R2. That the county and all participating municipalities of Marin Energy Authority should step away from their adversarial public posturing and seriously work with foundations, federal, state and local agencies and PG&E to foster cooperation. Moreover, rather than create a costly and very risky new county bureaucracy, efforts and resources should go forward to form public/private partnerships that will enable the county and all of the cities to achieve their present and future environmental goals R3. That in the event the Marin Clean Energy program is not abandoned, the Board of Supervisors and all participating municipalities review all available documentations and demonstrate their confidence, understanding and commitment to this project by voting at a publicly noticed meeting prior to committing their respective jurisdictions to final membership. R4. That the full contract, including all terms, conditions, and pricing be provided to all parties prior to the final opportunity to withdraw. REQUESTS FOR RESPONSES Pursuant to Penal Code Section 933.05, the Grand Jury requests responses from the following governing bodies: • Marin County Board of Supervisors: All Findings and Recommendations 1, 2, & 3 • The city and town councils of Belvedere, Fairfax, Mill Valley, Ross, San Anselmo, San Rafael, Sausalito and Tiburon: All Findings and Recommendations 1, 2 & 3 • The Marin Energy Authority Board of Directors: All Findings and Recommendations 1, 2 & 4 The governing bodies indicated above should be aware that the comment or response of the governing body must be conducted in accordance with Penal Code Section 933 (c) and subject to the notice, agenda and open meeting requirements of the Ralph M. Brown Act. California Penal Code Section 933 (c) states that "...the governing body of the public agency shall comment to thepresiding judge on the findings and recommendations pertaining to matters under the control of the governing body." Further, the Ralph M. December 2, 2009 Marin County Civil Grand Jury Page 17 of 23 Marin Clean Energy-* Pull the Plug Brown Act requires that any action of a public entity governing board occur only at a noticed public meeting. Disclaimer This report was voted on and approved by the Grand Jury with the exception of one member who abstained from final deliberations and voting because of ownership of publicly traded stock in one of the companies mentioned in this report. Reports issued by the Civil Grand Jury do not identify individuals interviewed. Penal Code Section 929 requires that reports of the Grand Jury not contain the name of any person, or fads leading to the identity of any person who provides information to the Civil Grand Jury. The California State Legislature has stated that it intends the provisions of the Penal Code 929 prohibiting disclosure of witness identities to encourage full candor in testimony in Civil Grand Jury investigations by protecting the privacy and confidentiality of those who participate in any Civil Grand Jury investigation. 1:1 a'4 [61c] W California Solar Resources: California Energy Commission, April 2005_ California Energy Commission 500-2005-072-D Community Choice Aggregation: The Viability ofAB117 and its Role in California's Energy Markets — An Analysis for the California Public Utilities Commission. The Goldman School of Public Policy, University of California, Berkeley, June 13, 2005. Community Choice Aggregation Pilot Project PIER Final Project Report. California Energy Commission, February 2009, 500-2008-091 Customer Credit Renewable Resource Account: Report to the Governor and Legislature. California Energy Commission, Commission Report, April 2003, 500-03-008F The Economics of Community Choice Aggregation: The Municipalization of Local Power Acquisition and Production. Bay Area Economic Forum. A Partnership of the Bay Area Council and the Association of Bay Area Governments, June 2007_ Print, Final Opinion and Recommendations on Greenhouse Gas Regulatory Strategies. California Energy Commission and California Public Utilities Commission, October 2008_ Print. Galbraith, Kate. Shorted: Paying for Green Power, and Getting Ads Instead. New York Times, 17 November, 2009. Increasing Renewable Energy Resources in the County of Marin, Jody London Consulting, November 2007. December 2, 2009. . Marin County Civil Grand Jury Page 18 of 23 Marin Clean Energy: Pull the Plug Marin -California Community Choice Aggregation Plan. Navigant Consulting, April, 2008. Print. Marin Community Choice Aggregation Project — Local Government Task Force Update. Navigant Consulting, March 6, 2008. Print. Marin County Greenhouse Gas Reduction Plan. October 2006. Web. htip://www,co.mayin.ca.us/dents/CD/main/comdev/advance/Sustainabilite/susinitiatives/cli mate/Climate.cfin. Marin County -PG&E Renewable Energy Program. August 2008. Web. bLtp://marincleanenergy.info/newMCE/updates.cfm Marin -PG&E Partnership Proposal. November 2008. Web: http:/ImarincleanengLrgy.info/newMCE/Updates.efin Marcus, William B., Review of the (Draft) Business Plan for the MarinCounty Choice Aggregation Program. JBS Energy, Inc., February 29, 2008. Print McGinn, Daniel. "fhe Greenest Big Companies in America." Newsweek, 28 September, 2009:34. http://www.newsweelc.com/id/215577 Print. Monsen, William and Fulmer, Mark, MRW & Associates; Marcus, William, JBS Energy, Inc. Review ofNavigant Consulting's Community Choice Aggregation Feasibility Studies_ August 17, 2005. Print Monsen, William and Fulmer, Mark. Community Choice Aggregation Review. MRW and Associates, October 15, 2008. Print. Monsen, William and Fulmer, Mark. Analysis of Service Agreements and Financial Risk to MEA, MRW and Associates, November 20, 2009. Print. PG&E and Marin: A Green Community Partnership. November 2007. Web. http:%Imarincleaneneray.info/newMCE/uMdates.cfm PG&E Proposal. May 2008. Web. hgp://marineleaneneiv.info/newMCE/updates cfin PG&E Proposed Greenhouse Gas Reduction and Renewable Energy Partnership Plan. December 2008. Wel . btip://marincleanenerpy.info/newMCE/updates.cfin Renewable Resources and the California Electric Power Industry: Systems Operations, Wholesale Markets and Grid Planning:, California ISO, July 20, 2009, December 2, 2009 Marin County Civil Grand Jury Page 19 of 23 Marin Clean Energy: Pull the Plug Rodgers, Connie. "MEA: Ever Changing and Extraordinarily Expensive" NorthBaybiz, August, 2009. Solar & Energy Efficiency District (SEED), Draft Program Implementation Plan — MEA, June 2009. Sustainable Marin Nature, Built Environment, and People, Mann Countywide Plan — Marin County Community Development Agency, October 2008 WEBSITES: Air Resources Board of California: www.arb.ca.¢ov Bill Documents. Sacramento, CA: State of California. htip://www.lcginf6.ca.gov Center for Resource Solutions: www.resource-solutions_ore California Energy Commission: www.energy.ca.gov California Independent System Operator: www.caiso.comm California Natural Resources Agency: bttp://ceres.ca.gov California Public Utilities Commission: www.Muc.ca,gov California Solar Initiative: www.califomiasolarstatistics.ca.gov City of Berkeley, Energy and Sustainability Development: http://www.ci.berkeley.ca.us County of Marin, BOS Meetings: htip:Hco.mann.ca.us/dppts/BS/Archive/Meetings.cfin Environment California: www.environmentcalifornia.org Green Marin: www.greeDmarin.org Marin Clean Energy: http://www.marincleanenerey.info Marin Community Development: http://www.co.mann.ca.us/dwts/CD/Main/index.cfm Marin Energy Authority: http://www.marinenergyauthority.org/ Pacific Gas and Electric: www.pge.com Sierra Club of the Bay Area: http://sfbay.sierraclub.org Sonoma County Energy (SCEIP): http://www.sonomacountyenergy.orw Wikipedia: http://en.wildpedia.org Glossary AB 32 Assembly Bill 32 (2006), the California Global Warning Solutions Act AB 117 Assembly Bill 117 (2002), the Community Choice Aggregation Law AB 560 Assembly Bill 560 (proposed), would increase the cap on "net metering" from 2.5% of peak demand in the utility's system to 10% (net metering gives solar customers credit on electric bill for surplus they transfer to the utility) AB 811 Assembly Bill 811, allows land -secured loans for homeowners and. businesses that install energy -efficiency projects and clean-exiergy generation systems to be paid back through assessments on individual property tax bills. December Z 2009 Marin County Civil Grand Jury Page 20 of 23 Marin Clean Energy: Pull the Plug AB 920 Assembly Bill 920, requires utilities to pay for credits on any electricity left over at the end of the year (at present leftover credits are zeroed out at the end of the year) Berkeley FIRST: Financing Initiative for Renewable and Solar Technology: Berkeley FIRST is a solar financing program operating in the City of Berkeley which provides property owners an opportunity to borrow from the City's Sustainable Energy Financing District to install solar photovoltaic electric systems and allow the cost to be repaid over 20 years through an annual special tax on their property tax bill. ht ://www.ci.berkelg .ca_us/ContentDis la .as x7id=26580 Berkeley Solar America: Through its Solar America Cities partnership with the Department of Energy, Berkeley's goal is to develop a "tum -key" solar installation program in its municipality. The city also plans to increase local capacity for solar energy installations by working with local suppliers, installers, trade associations, and financiers. Biomass Energy: Energy generated from plants and plant -derived materials such as trees, agricultural products, and other living plant materials. CAISO California Independent System Operator: Agency charged with operating the majority of California's high voltage wholesale power grid. CCA Community Choice Aggregation enables local governments to assume an active role in managing electricity supplies, investing in new power facilities and setting rates. CEC California Energy Commission, State energy policy and planning agency. CPUC California Public Utility Commission CSI California Solar Initiative CTC Competition Transition Charge ESP Energy Service Provider Geothermal energy: Energy generated from the heat of the earth usually from geothermal water, steam, or other hot fluids brought up to the surface from wells. . GUG Greenhouse Gas emissions, any of the atmospheric gases that contribute to the greenhouse effect by absorbing infrared radiation produced by solar warming of the Earth's surface_ They include carbon dioxide (CO2), methane (CII4), nitrous oxide NO2), and water vapor. IOU Independent Owned Utility IPP Independent Power Producer. JPA Joint Powers Agreement KW Kilowatt, unit of electric power output or consumption. KWh Kilowatt hour, unit of electric generation or consumption measure during one hour. The average. annual energy consumption of a household in the United States is about 8,900 KWh _ LARS Local Area Reliability Service December 2, 2009 Marin County Civil Grand Jury Page 21 of 23 Marin Clean Energy: Pull the Plug Marin Climate and Energy Partnership: A group of representatives from all Marin municipalities, Marin County, the Marin Municipal Water District and the Transportation Authority of Marin to assist municipalities assess, prioritize and implement greenhouse gas (GHG) reduction activities in 'their greenhouse gas reduction programs. Marin Clean Energy Initiative - MCE: A program initiated by MEA calls for MEA to compete with PG&E as retailer of electricity to Marin customers in order to boost usage of renewable energy Marin Energy Authority - MEA:. A JPA established in 2008 and made up of Marin County and 8 cities and towns MW Megawatt, equivalent to 1000 KW MWh Megawatt hour, equivalent to 1000 KWh NCPA Northern California Power Agency PG&E Pacific Gas and Electric PPP Public Purpose Program, energy efficiency program that provides rebates for energy efficiency RAR Resource Adequacy Requirements, requirements by CAISO to (a) establish appropriate levels of reserve margins, and (b) ensure adequate resources are committed to the region Renewable Resources: Power generated from resources that can be replenished. Eligible Renewable Resources: Renewable resources meeting specific requirements as determined by the California Energy Commission. To qualify a generation must use one or more of the following renewable resources: biodiesel, biomass, fuel cells, geothermal, landfill gas, ocean wave, ocean thermal, tidal currents, photovoltaic solar, thermal solar, small hydroelectric. (30 megawatts or less), wind. RFP Request for Proposal San Rafael BERST- Green Building, Energy Retrofit and Solar Transformation Collaboration. The Marin Green BERST collaborative was recently initiated by San Rafael as an effort to study and pursue policy and model program options for green building regulations and energy efficiency retrofitting for existing buildings. SB 32' California Senate Bill 32, increases the size of generation facilities eligible for California's feed -in tariff program from 1.5 megawatts (MW) to 3 MW, increases the statewide cap from 500 MW to 750 MW, and expands the program to include municipal utilities. . SCEIP The Sonoma County Energy Independence Program, Sonoma County's Energy Independence Program is a new opportimity for property owners to finance energy efficiency, water efficiency and renewable energy improvements through a voluntary assessment. www_sovomacountyenergy_org. SJ VPA San Joaquin Valley Power Authority Smart Grid: Using wireless technology to improve the ability to analyze the grid and manage power transmission and delivery of electricity in the most efficient manner. December 2, 2009 Marin County Civil Grand Jury Page 22 of 23 Marin Clean Energy: Pull the Plug Smart Meter: A wireless electric meter that identifies consumption in more detail than a conventional meter and transmits that information to the local utility for monitoring and billing purposes. Decemher 2, 2009 - Marin County Civil Grand Jury Page 23 of 23 marin energy authority D.YwN WEISZ rr¢ilojm Dhcdol TOM CROM W ELL City of 13ehrerdere LEw TRIWAME '(invn al f=air/n.e 0HARLF5 MCGLAM IAN Coo dy aJ Marin Exhibit VI PRELIMINARY RESPONSE TO GRAND JURY REPORT Dated December 2, 2009 Prepared by the Board of Directors of the Marin Energy Authority As Noticed In Special Session December 7, 2009 [At the January 7, 2010 regular meeting of the Marin Energy Authority Board of Directors, the Board will finalize this Preliminary Response as its formal response to the Grand Jury report.] F1: Partially Disagree. The Marin Energy Authority (MEA) is a new government agency, but is not a 'new level of government', and is to be financed with ratepayer revenues that do not cost the member agencies or MEA any general funds. The implied argument that general funds are at risk is patently false. F2: Disagree. SHAWN MARSHALL MEA, per the enabling legislative statute (ABI 17), does not submit its Marin Clean Energy city o/ m491 valley (MCE) program to a direct vote of the public on the program itself in advance of the program's implementation. The representative vote is through the publicly elected CHR(sTORHRR MAIMN representatives who serve on the MEA Board. Furthermore, the MCE program has been 'Aiwn of rias, submitted to a vote of the public's elected representatives in their constituent cities, towns and in the county. BARBARA THORNTON 1'own ojson Anschno Via the extensive hearing process used to evaluate risks and opportunities from the Marin Clean Energy Program, the standards of transparency and consumer protection have and DA MON CONNOLIX will be honored and preserved. In addition, information about the MCE program will be Cirygfsari Rafael provided to every ratepayer (homes and/or businesses with an electricity bill), using 4 notices of their individual right to vote themselves out of the program. Extensive )ONATHAN LEONE information on MEA, MCE, energy products, and ratepayer rights will be provided to each City ofsaasafifo residence and business in the service area during this period of time. All documentation has been available to the public on a 24 hour basis on the agency's website, RICHARD COLUNs www.marinenenavauthoritv.oro. 'Ibuva o('1'iHuran The voting public has been participating in the process through dozens of public meetings, and ratepayers have the additional opt -out opportunities provided during the official opt - out period. This process will occur over the first 90 days of the program launch, so there are 4 opportunities to vote for each ratepayer. Once enrolled in the MCE program the ratepayer can still opt out at any time, but there is a possibility they will pay a nominal exit c a I I f c r n i a fee to the agency to cover any stranded costs of prior energy procurement made on their A9 32 behalf. F3: Agree. Marin Only the cities that did not join MEA have denied their ratepayers the opportunity to vote Clean on whether to participate in the program (via the opt -out procedure). Energy This is a preliminary response by the MEA Board to the Grand Jury report dated December 2, 2009. The purpose of this response is to immediately address the findings and recommendations in the report and clarify some misperception and rectify some of the misinformation contained in that report. A final and Formal Response will be approved by the MEA Board of their next regularly scheduled meeting on January 7, 2010 and released to the public on January 8, 2010. 3;71. CMC CENTER, DR, n308 SATO )SAFAEL, CA 9; 9133-4tS,7 ell$ 499 6269 FAx415 499 7890 t111{PiIl2tleY,l�h`ntltiAr�Y $5',�JC� With respect to cities that do not opt -out, their residential and commercial customers will be transferred to the MCE program, at which point they will have 4 ballots to vote themselves out if they choose. Only cities that remain in the agency allow their ratepayers this choice. F4: Agree. See item F2 and F3 above. F5: Disagree. The Board of Supervisors as well as the staff and Chair of MEA have held numerous meetings with PG&E over the last four years to explore and determine whether PG&E could or would offer programs to 1. decrease greenhouse gas emissions on a level comparable to that offered by the MCE program, 2. increase focus on energy efficiency programs in Marin County, and 3. offer special partnership programs to help Marin meet its AB 32 obligations and internally, locally established goals. No substantive proposal was ever submitted to the Marin County Board of Supervisors or to the staff, Chair or Board of Directors of MEA. PG&E stated that they would only partner with the County and other jurisdictions if the jurisdictions left the MCE program, and if there was no Request for Proposals (RFP) process. PG&E refused to participate if they were required to compete with other bidders. Discussions with MEA were terminated by PG&E in April, 2009. 176: Disagree. The Business Plan is an extremely detailed document, prepared in cooperation with energy industry experts. The Business Plan underwent two independent peer reviews. Both peer reviews found the plan to be comprehensive and containing no fatal flaws. In addition, the draft Implementation Plan, dated November 18, 2009, was made available to the Grand Jury as requested and provides an even higher level of specificity and detail, as it is more current. The Grand Jury's Report does not make reference to the detailed information contained in the draft Implementation Plan, approved by the MEA Board on December 3, and submitted to the CPUC on December 4. The Implementation Plan is, in effect, an update to the Business Plan. FT Disagree. The MCE Business Plan does not state that the construction of owned assets is a requirement for the success of the Marin Clean Energy program. While potentially advantageous, it is neither necessary for "owned" facilities to be used for program success, nor is it "highly unlikely" that MEA will be able to successfully locate and support projects within Marin County to meet its local generation goals. Distributed generation, for example, has tremendous potential in Marin County, and is a stated goal of the program. Future energy sources could be developed by private companies which sell to MEA, by joint projects between MEA, other governments and private companies, or via public financings by MEA. Each specific project proposal will be analyzed for economic feasibility, land use issues, and environmental impacts at the appropriate time in the future. With a potential renewable energy source capability over five times the size of maximum electricity demand within the borders of Marin County, MEA is confident that some projects will be located in Marin over time. Others will benefit our entire North Bay economy. Z This is a preliminary response by the MEA Board to the Grand Jury report dated December 2, 2009. The purpose of this response is to immediately address the findings and recommendations in the report and clarify some misperception and rectify some of the misinformation contained in that report. A final and Formal Response will be approved by the MEA Board at their next regularly scheduled meeting on January 7, 2010 and released to the public on January 8, 2010. 178: Partially Disagree While neighboring communities have launched successful programs, the quantity of greenhouse gas reduction projected by MEA is over 50 times greater with MCE than by using all other programs combined, including the implementation of a Solar and Energy Efficiency District (SEED) Program in Marin (using AB 811 property -based financing mechanism), and all other locally based energy efficiency and renewable energy initiatives. The major obstacle with all the other possible greenhouse gas reduction initiatives is that they require General Fund monies. Only the MCE program offers non -General Fund revenue to support efficiency and renewable energy programs at no cost increase to the ratepayer. The costs to all jurisdictions to address AB32 goals are projected to be $394 million (California Air Resources Board data), and the establishment of MCE avoids 2/3 of that cost. F9: Disagree. There has been no slowdown in implementation of County energy efficiency programs (quite the opposite), nor has there been a slowdown of CREBs and other energy programs within the Marin communities; and MEA staff has applied for multiple federal, state, and local grants for renewable energy and energy efficiency projects, all while exploring the feasibility of the MCE program. MEA is not a distraction but the most significant tool for local agencies to employ as the costs and challenges of meeting AB 32 requirements are considered. In fact, the investigation and analysis of CCA within Marin has been a complimentary process in developing these other energy programs that may reduce greenhouse gas emissions. A significant portion of the analysis completed throughout CCA investigation has informed discussion and analysis focused on other complimentary energy programs and has heightened Merin's overall analysis to climate mitigation, greenhouse gas emissions reductions and renewable energy promotion. F10: Partially Disagree. There are risks associated with any new venture, but MEA staff and board members have identified and worked to mitigate all major rate payer risks and all risks to member jurisdictions. The remaining risk is that at sometime during MCE program operation, a ratepayer may identify an opportunity to purchase cheaper electricity (with less renewable energy content) by transferring generation service back to the incumbent utility. While this circumstance is not anticipated, Marin residents will be afforded a choice with respect to electric generation service and may base their service preference on any factor (such as price and/or renewable energy content), they so choose. If ratepayers so desire, they may, at any time, opt out of MCE (but may have to pay a nominal exit fee in the event of certain market conditions, similar to that charged by PG&E). F11: Disagree. The Contract elements are complete for both Phase I and Phase II ratepayers. Pricing methodology is stated and understood, based on indicative bids submitted in July, and will be finalized prior to contract execution by the Executive Director and Chair of MEA in the Spring of 2010 and again in early 2011 for Phase H. It is not possible for anyone, including PG&E, to know in advance of the execution of any power supply contract, what the price of energy will be on any given day because of the nature of the business of energy supply. MEA's default position is that its costs of its energy in Phase I and Phase 11 must be "at or below PG&E's projected costs", or there will be no executed contract. The MEA Board passed a resolution at its November 4i" meeting assuring that MEA will NOT execute the contract unless 3 This is a preliminary response by the MEA Board to the Grand Jury report dated December 2, 2009. The purpose of this response is to immediately address the findings and recommendations in the report and clarify some misperception and rectify some of the misinformation contained in that report. A final and Formal Response will be approved by the MEA Board at their next regularly scheduled meeting on January 7, 2010 and released to the public on January 8, 2010. Light Green Customers' (who will enjoy a minimum of 25% qualifying renewable energy content as compared to the 15% provided by PG&E) costs are at or below PG&E's projected costs. It is worth noting that California's current Renewables Portfolio Standard requires all electric utilities to provide a minimum of 20% of energy deliveries from qualifying renewable generating resources by 2010, and PG&E will not meet this target until at least 2012. F12: Agree. Most residential customers will not be enrolled into MCE until Phase 11 which is scheduled to occur in early to mid- 2011. The pricing for Phase 11 customers will be known prior to execution of the Phase 11 confirmation agreement. F13: Agree. F14: Disagree. Taxpayers have no risk associated with the MCE program. Elected representatives manage the policy formation for numerous complex issues in their respective cities and in the County, including land use, public works projects, transportation, and energy. Furthermore, 1 in 4 Californians receive their electricity from public utilities, which generally charge their ratepayers 20% less than the investor-owned utilities and are governed by elected boards. MEA and the MCE program is only 'new' in the sense that it is a hybrid model between the public utilities and investor owned utilities that supply all energy, that is gas and electricity both. MCE will only be responsible for the procurement of electricity, and PG&E will remain responsible for transmission, distribution, and maintenance. Taxpayers will actually have less risk because MCE will provide rate stability and rate -setting control at the local level. There is considerable risk to the taxpayers of each jurisdiction of not doing MCE, as the costs associated with implementing AB32 mitigations will constitute a considerable drain on every jurisdiction's general fund. Recommendations R1: This recommendation will not be implemented The risks of implementing MCE are understood and manageable, and the opportunity to reduce green house gas emissions, pursue energy independence and long term price stability, and reap the local economic benefits of this program should not be abandoned out of fear, political opposition or lack of understanding. In fact, the MEA board believes that it may be significantly more risky to forego consideration of MCE program implementation in consideration of projected AB32 compliance costs burden on general funds and highly volatile natural gas markets (which are currently favorable for the CCA program). In addition, the MEA Business Plan anticipates the formation of an Energy Commission of on-going assistance and use to the Executive Director, as well as the experience of the ad hoc Advisory Committee, comprised of citizens with technical expertise in rate -setting, generation, procurement, energy efficiency, renewable energy generation, etc. R2: This recommendation will not be implemented As described in response to F5 above, cooperative approaches have been tried and, in some cases, are continuing. For example, PG&E has worked with local Marin governments, including MEA representatives, to implement an Energy Efficiency Partnership program detailed in a previous Grand Jury report (2008) on the County Sustainability Team. PG&E is unable to provide additional service and funding in Marin County without violating CPUC requirements for fairness across the PG&E territory. This is a preliminary response by the MEA Board to the Grand Jury report dated December 2, 2009. The purpose of this response is to immediately address the findings and recommendations in the report and clarify some misperception and rectify some of the misinformation contained in that report. A final and Formal Response will be approved by the MEA Board at their next regularly scheduled meeting on January 7, 2010 and released to the public on January 8, 2010. The so-called bureaucracy of MEA is not expensive, and costs nothing to member jurisdictions' general funds, unlike all other energy programs suggested by the Grand Jury. MEA estimates that the fully -loaded staff cost will comprise only 3% of the annual budget. No other possible programs that reduce greenhouse gas emissions, such as SEED, Energy Efficiency, solar panels on public buildings, etc., approach the projected level of greenhouse gas emissions reductions that can be obtained by MCE. R3: This recommendation will not be implemented. The Councils and BOS are following proper analytical, public notice and public hearing procedures for the County and the other governmental member agencies of MEA to approve or reject membership of their respective agencies in the MEA. As previously stated, the final decision on participation rests with the individual ratepayers, who will have four opportunities to opt out in the 120 day opt -out period. R4: This recommendation will not be implemented. To avoid compromising the negotiation process, to avoid abrogating the confidential nature of the bidding process, or of the information submitted by the bidders, and/or MEA's pricing strategy, the final contract will only be released publicly after execution. As stated previously, pricing will be refreshed and will be known with certainty prior to the execution of the contract for both Phase I and Phase II. This is a preliminary response by the MEA Board to the Grand Jury report dated December 2, 2009. The purpose of this response is to immediately address the findings and recommendations in the report and clarify some misperception and rectify some of the misinformation contained in that report. A final and Formal Response will be approved by the MEA Board at their next regularly scheduled meeting on January 7, 2010 and released to the public on January 8, 2010. Exhibit VII Marin Energy Authority Responses to Current Frequently Asked Questions 12-7-09 1. Issue: Rate payer risk and bond repayment Response: Ratepayers are not obligated to pay for energy they do not use. Revenue bonds are secured by the sale of the power from the asset. The bonds that would be issued for building a new project would be covered by ratepayers in the normal course of business, just as is now the case with the incumbent utility. But to take it a step further, it is actually the revenue from the newly created asset that will secure payback on the bonds. So, for example, if a solar field is built using a bond issuance, the energy being created from that asset is sold to repay the bond over time. In the normal course of business the ratepayers would be covering that debt by paying for the energy generated each month. If MEA failed, however, or ratepayers were not available to cover the cost, then the power would be sold elsewhere and revenue from that sale would cover the bond repayment. Rate payers are only obligated to pay for the electricity they purchase from MEA, and rates will include debt service on any bond issuances as is now the case with the current utility. Under no scenario would ratepayers be obligated to help pay for energy they do not use or to "bail out" MEA in the unlikely event of an organizational default. 2. Issue: MEA Member General Fund Exposure Response: Cities and Towns do not have any financial liability for MEA debts and liabilities or NICE costs. There is a legal firewall between MEA and its member agency general funds that is codified by State law and further codified in the JPA Agreement and the Marin Clean Energy Power Supply Contract. Although cities and towns are members of MEA, it will function as a governmental, non-profit agency whose operations and financial obligations are completely separate from that of its local government members. In fact, there are multiple layers of protection for member agencies against the debts, liabilities and obligations of the MEA. Under Government Code Section 6507, the MEA is a legal entity separate from its members. Government Code Section 6508.1 authorizes a Joint Powers Agreement to provide that the debts, liabilities and obligations of the Joint Powers Authority shall not be the debts, liabilities or obligations of the individual members of the JPA. The MEA Joint Powers Authority Agreement provides that the debts, liabilities and obligations of the MEA shall not be the debts, liabilities and obligations of the members of the MEA. The final layer of protection is that under the contract with our proposed energy services provider, Shell Energy North America, Shell agrees that its only legal recourse is against the MEA and that will have no legal rights or remedies against the individual JPA members. 3. Issue: Contract Pricing and Execution Response: Prices for the contract will be refreshed and known prior to contract execution. Indicative pricing will be refreshed in late January and early February 2010, just before the MEA Board approves the final contract. Actual prices will be known at the time the contract is executed. Market pricing is the key factor in determining costs for electricity. As stipulated in an MEA Board resolution passed on November 4, 2009, the contract will not be executed until the pricing refresh allows costs to be at or below PG&E's projected costs for the light green option. This is true for both Phase I and Phase II customers. 4. Issue: Consumer Awareness and Notification Response: MEA's ratepayers will be notified about the shift in energy provider and their cost of electricity 60 days before service begins. Customers in member jurisdictions will be notified 60 days before service begins through four opt -out notices and other marketing material. For phase I customers, opt -out notification will begin in March to prepare for service beginning in June. 5. Issue: Energy Market Volatility Response: The cost of power will be locked in for the term of the five year contract. The cost of power will be locked in on the date of contract execution and will include a capped escalation rate that keeps costs at or below PG&E's projected costs. 6. Issue: MEA and PG&E Costs Response: MEA's costs will be lower than PG&E's projected costs. The difference between MEA and PG&E is the difference between a locked in cost and a fluctuating cost. MEA will be locking in costs that start -out at or below PG&E in year one and will remain below PG&E's projected costs in future years. The MEA Board will review its pricing structure annually (and more often 2 as necessary) to remain competitive with PG&E rates. It should be noted that in the unlikely event that PG&E's costs drop below their historic threshold, their cost could drop below MEA costs. Conversely, if what market analysis suggests is true and the costs of fossil -based energy and natural gas continue to rise, then PG&E's prices will continue to climb above MEA's projected costs. The good news here is that with MEA, customers will have a choice of energy providers and can choose the lower cost of two options (subject to nominal exit fees) at any time. 7. Issue: Staff Expertise and Expense MEA has and will hire additional highly qualified professional staff whose costs account for only 3% of the MEA budget. MEA has and will continue to draw on the same market expertise that has served many utilities and municipal utilities for several decades. MEA will combine that expertise with reliable technical and legal support under a governmental, not -for profit structure, which has significant economic benefits over that of a private utility, helping keep costs down. Currently, MEA has three staff, three legal firms, multiple technical consultants, and is making full use of expert consultants in the areas of energy modeling and implementation support, transactional and municipal law, infrastructure finance and planning. In the future, MEA's plans call for a staff of 20.5 professionals, which is quite small compared to other municipal utilities and also the incumbent utility. 8. Issue: Exit Fees and Customer Choice Response: Most PG&E exit fees for customers will be covered by MEA; Customers have the option of switching suppliers at any time MEA will cover the projected PG&E "exit fee' for customers that choose to stay with MEA as their energy supplier during the 120 -day opt -out period. During that opt out period consumers can make a decision with no exit fee either way. After the opt -out period, both suppliers (i.e. MEA and PG&E) will charge a nominal exit fee for customers that choose to switch between companies. This fee covers the cost of unused power purchased on their behalf and amounts to a few dollars per month on the monthly bill. 9. Issue: Contract Support and Review Response: The Contract, or Power Supply Agreement (PPA), has been subject to extensive review from industry experts, member agencies and the public. The PPA has been reviewed by City and Town Councils, City and Town Attorneys, City Managers, and an extensive cadre of Legal and Technical support for MEA including Navigant Consulting, Nixon -Peabody LLP, Milbank, 3 Tweed, Hadley & McCloy LLP, and Richards, Watson & Gershon LLP and members of the public. Also, a peer review of the PPA was conducted on behalf of the City Managers by MRW & Associates, an independent energy consulting firm with years of expertise in this area. The Final Draft PPA was approved by the MEA Board on November 5, 2009 and is now undergoing a 90 -day review period. It is then scheduled to be approved by the MEA Board on February 4, 2010. The current draft of the PPA can be found on the MEA website: www.marinenergyauthorU.org Please stay tuned and check MEA's website often. More answers to FAQs forthcoming. 12 Exhibit VIII PUBLIC CORRESPONDENCE Charles McGlashan, Chair Marin Energy Authority Board of Directors 3501 Civic Center Drive, 4308 San Rafael, CA 94903 Re: MEA non -fulfillment of 90 day review period Dear Charles: December 23, 2009 DEC 2 9 zoos The Marin United Taxpayers Association (MUTA) and Californians for Renewable Energy (CARE) understand that MEA has provided to member Marin towns and cities a document that purports to be its electricity supply agreement, and the circulation of this document is not, in actuality, utilizing the 90 day period which MEA is required to provide Marin cities and towns to review the proposed agreement in order that they may consider whether or not to withdraw from the Authority. Furthermore, after spending seven years of study, suddenly this 90 days is rushed as well over the Christmas and New Year's holidays. While February 4th is the "deadline", cities and towns have only until January 12th to withdraw. Why the rush when so much is at stake? MUTA and CARE believe that the contract which you have provided to the cities and towns lacks the real terms that are necessary for any meaningful decision making. It does not identify the electricity supplier, despite the fact that Barbara George of Women's Energy Matters announced at the Ross Town Meeting on December 10th, that you, Damon Connelly, Dawn Weitz and two Navigant Consultants were delayed from attending that meeting and because you were detained in the airport in Houston, arfter meeting with the CEO and others at Shell Energy North America, a wholly owned subsidiary of Royal Dutch Shell. Why not name Shell in the contract, when it obvious that Shell is your choice? And why not at least provide tentative prices, even though the actual pricing, we are well aware, is the very day and minute you enter the contract. Why not also reveal that only 20% of Marin's load, the cities and towns' governmental electrical needs are to be "nailed down with certainty" for five years, that those of us who are citizens do not have such certainty as our contract will have to be negotiated at the time the "80%" of MEA's load enters into a contract one year hence? Therefore both MUTA and CARE believe that without including such basic terms, i.e. as naming Shell Energy and at least providing some tentative even ball park pricing, you are asking the cities and towns to sign a blank — fill in the spaces — document. MUTA and CARE are aware that other members of the public as well as the Marin Civil Grand Jury have questioned whether the document sent out by MEA contains sufficient information for adequate review and evaluation. We request that MEA provide Marin towns and cities with the full required 90 -day review period including the above requested information. Thank you for your consideration. If you have questions, please feel free to contact either of US. Sincerely yours,` Basia Crane, Marin United Taxpayers Association 67 Kent Avenue Kentfield, CA 94904 (/,'' uliette Anthony Legislative & Regulatory Consultant Californians for Renewable Energy 678 Blackberry Lane San Rafael, CA 94903 cc: MUTA Board of Directors CARE President & Board of Directors All MEA member cities & towns Honorable Michael Peevey, President CPUC and Commissioners Senator Mark Leno Assemblyman Jared Huffman Senator Barbara Boxer Senator Diane Feinstein Honorable Susan Kennedy, Chief of Staff, Governor's Office (Marin Resident) Honorable Terry Tamminen, Governor's Energy Consultant New York Times SF Bay Bureau SF Chronicle Marin Independent Journal L CITYIOFSAR RAFAEL MI DEC 30 AM 10:42 M d �s d da RIO .n G W q q D, q q,m ' o �bJ)m m" .D.�w aqi o m amid• m WA P, W q Y® m D+ �4 d 00 CIL , ❑Uw eDw6�°cd W' ciro� me Y ° o m cod El *\J o m"�pdawa cGs1b Komi °°' +°' m m' o`� Y ca aYW� o a.tl �.D' W (� Q W q 'a -0 .0 o o '60 �g myto WoRdWe 0° �ro m.a.:���Lq '-°m i100pWUO O W mp cd O a 0 W W W ro W m 0 bob cs 10 R. pq m q0" `.°. 03;8,am'qO g 0 m a�" q�� w a ai 0 a y.� m Y d 4 w 'a yp� w d d bD 91 a D Oy :P,� fO A c W� m m m q d q, S� �.q o m d d w.s7 +� �yy m 72 d H W •IV.�.O tj _E01 � .0 d � W 40 A -HA 4 aawogloa 1P, , B>,ll.� 114 W d W � 0 a " -•� .m •tl M bwA A w o d m � a co, m`aD,a d g B q P q �tim om 0. .q�EDW �d •d .�:.i Y.,ri"Wq URS C4°•�Om Oa�� �'F �•��I..^q..m.Wyy, w.W m W. ai'm.+� � �y;yW dga� tib aow m v mEDqW �N waAWq";mIIcd cd :�.q Fi m" m B m"ma mbpm p, m m mn, p B o °po"m.� W,q� a i m w•W 0 agi B w q.Y.. m•Yq � m.,0y O'N w 0.�+ m� Pro C Q ED �.� D m ffl d O.g g q mom, y, aw°"> o d 6 C7 All w m.5.a 0}j mmw Od'Mqc7.�:m m'a, Ep awi •^CC'•Fy WOdW 0 W mYC W m a W y, Ci- m m. 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