HomeMy WebLinkAboutOrdinance 1871 (MERA JPA)CLERK'S CERTIFICATE
I, ESTHER C. BEIRNE, Clerk of the City of San Rafael, and Ex -Officio Clerk of the
Council of said City, do hereby certify that the foregoing Charter Ordinance No. 1871 entitled:
AN ORDINANCE OF THE CITY OF SAN RAFAEL APPROVING THE MARIN ENERGY
AUTHORITY JOINT POWERS AGREEMENT AND AUTHORIZING THE
IMPLEMENTATION OF A COMMUNITY CHOICE AGGREGATION PROGRAM
is a true and correct copy of an Ordinance of said City and was introduced at a REGULAR
meeting of the City Council of the City of San Rafael, held on the 1st day of December, 2008, a
SUMMARY of Ordinance No. 1871 was published as required by City Charter in the MARIN
INDEPENDENT JOURNAL, a newspaper published in the City of San Rafael, and passed and
adopted as an Ordinance of said City at a REGULAR meeting of the City Council of said City,
held on the 15`' day of December, 2008, by the following vote, to wit:
AYES COUNCILMEMBERS: Brockbank, Connolly and Heller
NOES: COUNCILMEMBERS: Vice -Mayor Miller
ABSENT: COUNCILMEMBERS: Mayor Boro, due to potential conflict of interest.
WITNESS my hand and the official
seal of the City of San Rafael this
17`h day of December, 2008
ESTHER C. BEIRNE ,
City Clerk
ORDINANCE NO. 1871
(Uncodified)
AN ORDINANCE OF THE CITY OF SAN RAFAEL
APPROVING THE MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT AND
AUTHORIZING THE IMPLEMENTATION OF
A COMMUNITY CHOICE AGGREGATION PROGRAM
The City Council of the City of San Rafael does hereby ordain as follows:
SECTION 1. Tile City of San Rafael has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24, 2002, the Governor signed into law Assembly Bill 117
(Stat. 2002, ch. 838; see California Public Utilities Code section 366.2; hereinafter referred to as
the "Act'), which authorizes any California city or county, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community -wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the City of San
Rafael has been participating since 2003 in the evaluation of a CCA program for the County of
Marin and the cities and towns within it.
SECTION 4. On June 22, 2006, the City of San Rafael joined a Local Government Task
Force (LGTF), which was comprised of elected officials and representatives of the County of
Marin and each municipality within the County of Marin. The purpose of the LGTF was to
jointly participate in the investigation of CCA for Marin communities and customers. The LGTF
had five meetings with the final meeting taking place on March 6, 2008. The LGTF meetings
looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by which
the California Public Utilities Commission will review "Implementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
SECTION 6. Representatives from the City of San Rafael along with the other LGTF
members have developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers
Agreement", attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy Authority"
and,
(b) To specify the terms and conditions by which participants may participate as
a group in energy programs, including but not limited to the preliminary implementation
of a Community Choice Aggregation program.
SECTION 7. Representatives fi•om the City of San Rafael along with the LGTF
members have developed a Business Plan (attached hereto as Exhibit B) that describes the
formation of Marin Clean Energy and the Community Choice Aggregation program to be
implemented by and through the Marin Energy Authority.
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions.
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases which are emitted by creating electricity for the
community.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION 11. The Joint Powers Agreement expressly allows the City of San Rafael to
withdraw its membership in the Marin Energy Authority (and its participation in the Community
Choice Aggregation program) prior to the actual implementation of a Community Choice
Aggregation program through Program Agreement 1.
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the City Council of the City of San Rafael
approves the Joint Powers Agreement attached hereto as Exhibit A and elects to implement a
Community Choice Aggregation program within the City's jurisdiction by and through the City's
participation in the Marin Energy Authority, as described in the Business Plan in substantially the
form attached hereto as Exhibit B, and subject to the City's right to forego the actual
implementation of a Community Choice Aggregation program pursuant to specified withdrawal
rights described in the Joint Powers Agreement. The Vice Mayor is hereby authorized to execute
the attached Joint Powers Agreement.
SECTION 14. A summary of this Ordinance shall be published and a certified copy of
the full text of this Ordinance shall be posted in the office of the City Clerk at least five (5) days
prior to the City Council meeting at which it is adopted. This Ordinance shall be in full force and
effect thirty (30) days after its final passage, and the summary of this Ordinance shall be
published within fifteen (15) days after the adoption, together with the names of the
Councilmembers voting for or against same, in the Marin Independent Journal, a newspaper of
general circulation published and circulated in the City of San Rafael, County of Marin, State of
California. Within fifteen (15) days after adoption, the City Clerk shall also post in the office of
the City Clerk, a certified copy of the full text of this Ordinance along with the names of those
Councilmembers voting for or against the Ordinance
ATTEST:
UCYR N. MILLER, Vice Mayor
ESTHER BEIRNE, City Clerk
The foregoing Ordinance No. 1871 was read and introduced at a Regular Meeting of the City
Council of the City of San Rafael, held on the 1" day of December, 2008 and ordered passed to print
by the following vote, to wit:
AYES: Councilmembers: Brockbank, Connolly and Heller
NOES: Councilmembers: Vice -Mayor Miller
ABSENT: Councilmembers: Mayor Boro, due to potential conflict of interest.
and will come up for adoption as an Ordinance of the City of San Rafael at a Regular Meeting of the
Council to be held on the 15th day of December, 2008.
ESTHER BEIRNE, City Clerk
Exhibit `A'
Marin Energy Authority
- Joint Powers Agreement -
Effective DATE
Among The Following Parties:
[City of Belvedere]
[Town of Corte Madera]
[Town of Fairfax]
[City of Larkspur]
[City of Mill Valley]
[City of Novato]
[Town of Ross]
[Town of San Anselmo]
[City of San Rafael]
[City of Sausalito]
[Town of Tiburon]
[County of Marin]
MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT
This Joint Powers Agreement ("Agreement"), effective as of DATE, is made and
entered into pursuant to the provisions of Title 1, Division 7, Chapter 5, Article 1
(Section 6500 et seq.) of the California Government Code relating to the joint exercise of
powers among the parties set forth in Exhibit B ("Parties"). The term "Parties" shall also
include an incorporated municipality or county added to this Agreement in accordance
with Section 3.1.
RECITALS
1. The Parties are either incorporated municipalities or counties sharing various
powers under California law, including but not limited to the power to purchase,
supply, and aggregate electricity for themselves and their inhabitants.
2. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act,
which mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels.
The California Air Resources Board is promulgating regulations to implement AB
32 which will require local government to develop programs to reduce
greenhouse emissions.
The purposes for the Initial Participants (as such term is defined in Section 2.2
below) entering into this Agreement include addressing climate change by
reducing energy related greenhouse gas emissions and securing energy supply and
price stability, energy efficiencies and local economic benefits. It is the intent of
this Agreement to promote the development and use of a wide range of renewable
energy sources and energy efficiency programs, including but not limited to solar
and wind energy production.
4. The Parties desire to establish a separate public agency, known as the Marin
Energy Authority ("Authority"), under the provisions of the Joint Exercise of
Powers Act of the State of California (Government Code Section 6500 et seq.)
("Act") in order to collectively study, promote, develop, conduct, operate, and
manage energy programs.
5. The Initial Participants have each adopted an ordinance electing to implement
through the Authority Community Choice Aggregation, an electric service
enterprise agency available to cities and counties pursuant to California Public
Utilities Code Section 366.2 ("CCA Program"). The first priority of the Authority
will be the consideration of those actions necessary to implement the CCA
Program. Regardless of whether or not Program Agreement 1 is approved and the
CCA Program becomes operational, the parties intend for the Authority to
continue to study, promote, develop, conduct, operate and manage other energy
programs.
AGREEMENT
NOW, THEREFORE, in consideration of the mutual promises, covenants, and
conditions hereinafter set forth, it is agreed by and among the Parties as follows:
ARTICLE 1
CONTRACT DOCUMENTS
1.1 Definitions. Capitalized terms used in the Agreement shall have the meanings
specified in Exhibit A, unless the context requires otherwise.
1.2 Documents Included. This Agreement consists of this document and the
following exhibits, all of which are hereby incorporated into this Agreement.
Exhibit A:
Definitions
Exhibit B:
List of the Parties
Exhibit C:
Annual Energy Use
Exhibit D:
Voting Shares
1.3 Revision of Exhibits. The Parties agree that Exhibits B, C and D to this
Agreement describe certain administrative matters that may be revised upon the
approval of the Board, without such revision constituting an amendment to this
Agreement, as described in Section 8.4. The Authority shall provide written
notice to the Parties of the revision of any such exhibit.
ARTICLE 2
FORMATION OF MARIN ENERGY AUTHORITY
2.1 Effective Date and Term. This Agreement shall become effective and Marin
Energy Authority shall exist as a separate public agency on the date this
Agreement is executed by at least two Initial Participants after the adoption of the
ordinances required by Public Utilities Code Section 366.2(c)(10). The Authority
shall provide notice to the Parties of the Effective Date. The Authority shall
continue to exist, and this Agreement shall be effective, until this Agreement is
terminated in accordance with Section 7.4, subject to the rights of the Parties to
withdraw from the Authority.
2.2 Initial Participants. During the first 180 days after the Effective Date, all other
Initial Participants may become a Party by executing this Agreement and
delivering an executed copy of this Agreement and a copy of the adopted
ordinance required by Public Utilities Code Section 366.2(c)(10) to the Authority.
Additional conditions, described in Section 3. 1, may apply (i) to either an
incorporated municipality or county desiring to become a Party and is not an
Initial Participant and (ii) to Initial Participants that have not executed and
delivered this Agreement within the time period described above.
2.3 Formation. There is formed as of the Effective Date a public agency named the
Marin Energy Authority. Pursuant to Sections 6506 and 6507 of the Act, the
Authority is a public agency separate from the Parties. Unless otherwise agreed,
the debts, liabilities, and obligations of the Authority shall not be debts, liabilities
or obligations of the Parties.
2.4 Purnose. The purpose of this Agreement is to establish an independent public
agency in order to exercise powers common to each Party to study, promote,
develop, conduct, operate, and manage energy and energy-related climate change
programs, and to exercise all other powers necessary and incidental to
accomplishing this purpose. Without limiting the generality of the foregoing, the
Parties intend for this Agreement to be used as a contractual mechanism by which
the Parties are authorized to participate as a group in the CCA Program, as further
described in Section 5.1. The Parties intend that subsequent agreements shall
define the terms and conditions associated with the actual implementation of the
CCA Program and any other energy programs approved by the Authority.
2.5 Powers. The Authority shall have all powers common to the Parties and such
additional powers accorded to it by law. The Authority is authorized, in its own
name, to exercise all powers and do all acts necessary and proper to carry out the
provisions of this Agreement and fulfill its purposes, including, but not limited to,
each of the following:
2.5.1 make and enter into contracts;
2.5.2 employ agents and employees, including but not limited to an Executive
Director;
2.5.3 acquire, contract, manage, maintain, and operate any buildings, works or
improvements;
2.5.4 acquire by eminent domain, or otherwise, except as limited under Section
6508 of the Act, and to hold or dispose of any property;
2.5.5 lease any property;
2.5.6 sue and be sued in its own name;
2.5.7 incur debts, liabilities, and obligations;
2.5.8 issue revenue bonds and other forms of indebtedness;
2.5.9 apply for, accept, and receive all licenses, permits, grants, loans or other
aids from any federal, state or local public agency;
2.5.10 submit documentation and notices, register, and comply with orders,
tariffs and agreements for the establishment and implementation of the
CCA Program and other energy programs;
2.5.11 adopt rules, regulations, policies, bylaws and procedures governing the
operation of the Authority ("Operating Rules and Regulations"); and
2.5.12 make and enter into service agreements relating to the provision of
services necessary to plan, implement, operate and administer the CCA
Program and other energy programs, including the acquisition of electric
power supply and the provision of retail and regulatory support services.
2.6 Limitation on Powers. As required by Government Code Section 6509, the
power of the Authority is subject to the restrictions upon the manner of exercising
power possessed by the County of Marin.
2.7 Compliance with Local Zoning and Building Laws. Notwithstanding any other
provisions of this Agreement or state law, any facilities, buildings or structures
located, constructed or caused to be constructed by the Authority within the
territory of the Authority shall comply with the General Plan, zoning and building
laws of the local jurisdiction within which the facilities, buildings or structures are
constructed.
ARTICLE 3
AUTHORITY PARTICIPATION
3.1 Addition of Parties. Subject to Section 2.2, relating to certain rights of Initial
Participants, other incorporated municipalities and counties may become Parties
upon (a) the adoption of a resolution by the governing body of such incorporated
municipality or such county requesting that the incorporated municipality or
county, as the case may be, become a member of the Authority, (b) the adoption,
by an affirmative vote of the Board satisfying the requirements described in
Section 4.9.1, of a resolution authorizing membership of the additional
incorporated municipality or county, specifying the membership payment, if any,
to be made by the additional incorporated municipality or county to reflect its pro
rata share of organizational, planning and other pre-existing expenditures, and
describing additional conditions, if any, associated with membership, (c) the
adoption of an ordinance required by Public Utilities Code Section 366.2(c)(10)
and execution of this Agreement and other necessary program agreements by the
incorporated municipality or county, (d) payment of the membership payment, if
any, and (e) satisfaction of any conditions established by the Board.
Notwithstanding the foregoing, in the event the Authority decides to not
implement a CCA Program, the requirement that an additional party adopt the
ordinance required by Public Utilities Code Section 366.2(c)(10) shall not apply.
Under such circumstance, the Board resolution authorizing membership of an
additional incorporated municipality or county shall be adopted in accordance
with the voting requirements of Section 4.10.
3.2 Continuing Participation. The Parties acknowledge that membership in the
Authority may change by the addition and/or withdrawal or termination of Parties.
The Parties agree to participate with such other Parties as may later be added, as
described in Section 3.1. The Parties also agree that the withdrawal or termination
of a Party shall not affect this Agreement or the remaining Parties' continuing
obligations under this Agreement.
ARTICLE 4
GOVERNANCE AND INTERNAL ORGANIZATION
4.1 Board of Directors. The governing body of the Authority shall be a Board of
Directors ("Board") consisting of one director for each Party appointed in
accordance with Section 4.2.
4.2 Annointment and Removal of Directors. The Directors shall be appointed and
may be removed as follows:
4.2.1 The governing body of each Party shall appoint and designate in writing
one regular Director who shall be authorized to act for and on behalf of the
P on r rs within the powers of the Authority. The governing body
also shall appoint and designate in writing one alternate
Directur who may vote on matters when the regular Director is absent
from a Board meeting. The person appointed and designated as the
Director or the alternate Director shall be a member of the governing body
of the Party.
4.21 TI `perating Rules and Regulations, to be developed and approved by
accordance with Section 2.5.11, shall specify the reasons for
auu associated with the removal of an individual Director for
cause. Notwithstanding the foregoing, no Party shall be deprived of its
right to seat a Director on the Board and any such Party for which its
Director and/or alternate Director has been removed may appoint a
anent.
V.3 Terms of Office. Each Director shall serve at the pleasure of the governing body
r,f the Party that the Director represents, and may be removed as Director by such
erring body at any time. If at any time a vacancy occurs on the Board, a
acement shall be appointed to fill the position of the previous Director in
aLL )rdance with the provisions of Section 4.2 within 90 days of the date that such
position becomes vacant.
Quorum. A majority of the Directors shall constitute a quorum, except that less
than a quorum may adjourn from time to time in accordance with law.
4.5 Powers and Function of the Board. The Board shall conduct or authorize to be
conducted all business and activities of the Authority, consistent with this
Agreement, the Authority Documents, the Operating Rules and Regulations, and
applicable law.
4.6 Executive Committee. The Board may establish an executive committee
consisting of a smaller number of Directors. The Board may delegate to the
executive committee such authority as the Board might otherwise exercise,
subject to limitations placed on the Board's authority to delegate certain essential
functions, as described in the Operating Rules and Regulations. The Board may
not delegate to the Executive Committee or any other committee its authority
under Section 2.5.11 to adopt and amend the Operating Rules and Regulations.
4.7 Commissions. Boards and Committees. The Board may establish any advisory
commissions, boards and committees as the Board deems appropriate to assist the
Board in carrying out its functions and implementing the CCA Program, other
energy programs and the provisions of this Agreement.
4.8 Director Comnensation. Compensation for work performed by Directors on
behalf of the Authority shall be borne by the Party that appointed the Director.
The Board, however, may adopt by resolution a policy relating to the
reimbursement of expenses incurred by Directors.
4.9 Board Voting Related to the CCA Proeram.
4.9.1. To be effective, on all matters specifically related to the CCA Program, a
vote of the Board shall consist of the following: (1) a majority of all
Directors shall vote in the affirmative or such higher voting percentage
expressly set forth in Sections 7.2 and 8.4 (the "percentage vote") and (2)
the corresponding voting shares (as described in Section 4.9.2 and Exhibit
D) of all such Directors voting in the affirmative shall exceed 50%, or
such other higher voting shares percentage expressly set forth in Sections
7.2 and 8.4 (the "percentage voting shares"), provided that, in instances in
which such other higher voting share percentage would result in any one
Director having a voting share that equals or exceeds that which is
necessary to disapprove the matter being voted on by the Board, at least
one other Director shall be required to vote in the negative in order to
disapprove such matter.
4.9.2. Unless otherwise stated herein, voting shares of the Directors shall be
determined by combining the following: (1) an equal voting share for each
Director determined in accordance with the formula detailed in Section
4.9.2.1, below; and (2) an additional voting share determined in
accordance with the formula detailed in Section 4.9.2.2, below.
4.9.2.1 Pro Rata Voting Share. Each Director shall have an equal voting
share as determined by the following formula: (1/total number of
Directors) multiplied by 50, and
4.9.2.2 Annual Enersv Use Voting Share. Each Director shall have an
additional voting share as determined by the following formula:
(Annual Energy Use/Total Annual Energy) multiplied by 50, where
(a) "Annual Energy Use" means, (i) with respect to the first 3 years
following the Effective Date, the annual electricity usage, expressed
in kilowatt hours (' Whs"), within the Party's respective jurisdiction
and (ii) with respect to the period after the third anniversary of the
Effective Date, the annual electricity usage, expressed in kWhs, of
accounts within a Party's respective jurisdiction that are served by
the Authority and (b) "Total Annual Energy" means the sum of all
Parties' Annual Energy Use. The initial values for Annual Energy
use are designated in Exhibit C, and shall be adjusted annually as
soon as reasonably practicable after January 1, but no later than
March 1 of each year.
4.9.2.3 The voting shares are set forth in Exhibit D.
4.10 Board Voting on General Administrative Matters and Programs Not
Involving CCA. Except as otherwise provided by this Agreement or the
Operating Rules and Regulations, each member shall have one vote on general
administrative matters, including but not limited to the adoption and
amendment of the Operating Rules and Regulations, and energy programs not
involving CCA. Action on these items shall be determined by a majority vote
of the quorum present and voting on the item or such higher voting percentage
expressly set forth in Sections 7.2 and 8.4.
4.11 Meetings and Special Meetings of the Board. The Board shall hold at least four
regular meetings per year, but the Board may provide for the holding of regular
meetings at more frequent intervals. The date, hour and place of each regular
meeting shall be fixed by resolution or ordinance of the Board. Regular meetings
may be adjourned to another meeting time. Special meetings of the Board may be
called in accordance with the provisions of California Government Code Section
54956. Directors may participate in meetings telephonically, with full voting
rights, only to the extent permitted by law. All meetings of the Board shall be
conducted in accordance with the provisions of the Ralph M. Brown Act
(California Government Code Section 54950 et seq.).
4.12 Selection of Board Officers.
4.12.1 Chair and Vice Chair. The Directors shall select, from among
themselves, a Chair, who shall be the presiding officer of all Board
meetings, and a Vice Chair, who shall serve in the absence of the Chair.
The term of office of the Chair and Vice Chair shall continue for one year,
but there shall be no limit on the number of terms held by either the Chair
or Vice Chair. The office of either the Chair or Vice Chair shall be
declared vacant and a new selection shall be made if. (a) the person
serving dies, resigns, or the Party that the person represents removes the
person as its representative on the Board or (b) the Party that he or she
represents withdraws form the Authority pursuant to the provisions of this
Agreement.
4.12.2 Secretary. The Board shall appoint a Secretary, who need not be a
member of the Board, who shall be responsible for keeping the minutes of
all meetings of the Board and all other official records of the Authority.
4.12.3 Treasurer and Auditor. The Board shall appoint a qualified person to
act as the Treasurer and a qualified person to act as the Auditor, neither of
whom needs to be a member of the Board. If the Board so designates, and
in accordance with the provisions of applicable law, a qualified person
may hold both the office of Treasurer and the office of Auditor of the
Authority. Unless otherwise exempted from such requirement, the
Authority shall cause an independent audit to be made by a certified public
accountant, or public accountant, in compliance with Section 6505 of the
Act. The Treasurer shall act as the depositary of the Authority and have
custody of all the money of the Authority, from whatever source, and as
such, shall have all of the duties and responsibilities specified in Section
6505.5 of the Act. The Board may require the Treasurer and/or Auditor to
file with the Authority an official bond in an amount to be fixed by the
Board, and if so requested the Authority shall pay the cost of premiums
associated with the bond. The Treasurer shall report directly to the Board
and shall comply with the requirements of treasurers of incorporated
municipalities. The Board may transfer the responsibilities of Treasurer to
any person or entity as the law may provide at the time. The duties and
obligations of the Treasurer are further specified in Article 6.
4.13 Administrative Services Provider. The Board may appoint one or more
administrative services providers to serve as the Authority's agent for planning,
implementing, operating and administering the CCA Program, and any other
program approved by the Board, in accordance with the provisions of a written
agreement between the Authority and the appointed administrative services
provider or providers that will be known as an Administrative Services
Agreement. The Administrative Services Agreement shall set forth the terms and
conditions by which the appointed administrative services provider shall perform
or cause to be performed all tasks necessary for planning, implementing,
operating and administering the CCA Program and other approved programs. The
Administrative Services Agreement shall set forth the term of the Agreement and
the circumstances under which the Administrative Services Agreement may be
terminated by the Authority. This section shall not in any way be construed to
limit the discretion of the Authority to hire its own employees to administer the
CCA Program or any other program.
ARTICLE 5
IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS
5.1 Preliminary Implementation of the CCA Program.
5.1.1 Enabling Ordinance. Except as otherwise provided by Section 3. 1, prior
to the execution of this Agreement, each Party shall adopt an ordinance in
accordance with Public Utilities Code Section 366.2(c)(10) for the purpose
of specifying that the Party intends to implement a CCA Program by and
through its participation in the Authority.
5.1.2 Implementation Plan. The Authority shall cause to be prepared an
Implementation Plan meeting the requirements of Public Utilities Code
Section 366.2 and any applicable Public Utilities Commission regulations
as soon after the Effective Date as reasonably practicable. The
Implementation Plan shall not be filed with the Public Utilities
Commission until it is approved by the Board in the manner provided by
Section 4.9.
5.1.3 Effect of Vote On Required Implementation Action. In the event that
two or more Parties vote to approve Program Agreement 1 or any earlier
action required for the implementation of the CCA Program ("Required
Implementation Action"), but such vote is insufficient to approve the
Required Implementation Action under Section 4.9, the following will
occur:
5.1.3.1 The Parties voting against the Required Implementation
Action shall no longer be a Party to this Agreement and
this Agreement shall be terminated, without further notice,
with respect to each of the Parties voting against the
Required Implementation Action at the time this vote is
final. The Board may take a provisional vote on a
Required Implementation Action in order to initially
determine the position of the Parties on the Required
Implementation Action. A vote, specifically stated in the
record of the Board meeting to be a provisional vote, shall
not be considered a final vote with the consequences
stated above. A Party who is terminated from this
Agreement pursuant to this section shall be considered the
same as a Party that voluntarily withdrew from the
Agreement under Section 7.1.1.1.
5.1.3.2 After the termination of any Parties pursuant to Section
5.1.3.1, the remaining Parties to this Agreement shall be
only the Parties who voted in favor of the Required
Implementation Action.
5.1.4 Termination of CCA Program. Nothing contained in this Article or this
Agreement shall be construed to limit the discretion of the Authority to
terminate the implementation or operation of the CCA Program at any
time in accordance with any applicable requirements of state law.
5.2 Authoritv Documents. The Parties acknowledge and agree that the affairs of the
Authority will be implemented through various documents duly adopted by the
Board through Board resolution, including but not necessarily limited to the
Operating Rules and Regulations, the annual budget, and specified plans and
policies defined as the Authority Documents by this Agreement. The Parties agree
to abide by and comply with the terms and conditions of all such Authority
Documents that may be adopted by the Board, subject to the Parties' right to
withdraw from the Authority as described in Article 7.
ARTICLE 6
FINANCIAL PROVISIONS
6.1 Fiscal Year. The Authority's fiscal year shall be 12 months commencing July 1
and ending June 30. The fiscal year may be changed by Board resolution.
6.2 Denositorv.
6.2.1 All funds of the Authority shall be held in separate accounts in the name
of the Authority and not commingled with funds of any Party or any other
person or entity.
6.2.2 All funds of the Authority shall be strictly and separately accounted for,
and regular reports shall be rendered of all receipts and disbursements, at
least quarterly during the fiscal year. The books and records of the
Authority shall be open to inspection by the Parties at all reasonable times.
The Board shall contract with a certified public accountant or public
accountant to make an annual audit of the accounts and records of the
Authority, which shall be conducted in accordance with the requirements
of Section 6505 of the Act.
6.2.3 All expenditures shall be made in accordance with the approved budget
and upon the approval of any officer so authorized by the Board in
accordance with its Operating Rules and Regulations. The Treasurer shall
draw checks or warrants or make payments by other means for claims or
disbursements not within an applicable budget only upon the prior
approval of the Board.
6.3 Budtet and Recovery Costs.
6.3.1 Budget. The initial budget shall be approved by the Board. The Board
may revise the budget from time to time through an Authority Document
as may be reasonably necessary to address contingencies and unexpected
expenses. All subsequent budgets of the Authority shall be prepared and
approved by the Board in accordance with the Operating Rules and
Regulations.
6.3.2 County Funding of Initial Costs. The County of Marin shall fund the
Initial Costs of the Authority in implementing the CCA Program in an
amount not to exceed $500,000 unless a larger amount of funding is
approved by the Board of Supervisors of the County. This funding shall
be paid by the County at the times and in the amounts required by the
Authority. In the event that the CCA Program becomes operational, these
Initial Costs paid by the County of Marin shall be included in the customer
charges for electric services as provided by Section 6.3.3 to the extent
permitted by law, and the County of Marin shall be reimbursed from the
payment of such charges by customers of the Authority. The Authority
may establish a reasonable time period over which such costs are
recovered. In the event that the CCA Program does not become
operational, the County of Marin shall not be entitled to any
reimbursement of the Initial Costs it has paid from the Authority or any
Party.
6.3.2 CCA Program Costs. The Parties desire that, to the extent reasonably
practicable, all costs incurred by the Authority that are directly or
indirectly attributable to the provision of electric services under the CCA
Program, including the establishment and maintenance of various reserve
and performance funds, shall be recovered through charges to CCA
customers receiving such electric services.
6.3.3 General Costs. Costs that are not directly or indirectly attributable to the
provision of electric services under the CCA Program, as determined by
the Board, shall be defined as general costs. General costs shall be shared
among the Parties on such basis as the Board shall determine pursuant to
an Authority Document.
6.3.4 Other Energy Program Costs. Costs that are directly or indirectly
attributable to energy programs approved by the Authority other than the
CCA Program shall be shared among the Parties on such basis as the
Board shall determine pursuant to an Authority Document.
ARTICLE 7
WITHDRAWAL AND TERMINATION
7.1 Withdrawal.
7.1.1 General.
7.1.1.1 Prior to the Authority's execution of Program Agreement 1, any
Party may withdraw its membership in the Authority by giving no
less than 30 days advance written notice of its election to do so,
which notice shall be given to the Authority and each Party. To
permit consideration by the governing body of each Party, the
Authority shall provide a copy of the proposed Program Agreement
1 to each Party at least 90 days prior to the consideration of such
agreement by the Board.
7.1.1.2 Subsequent to the Authority's execution of Program Agreement 1, a
Party may withdraw its membership in the Authority, effective as of
the beginning of the Authority's fiscal year, by giving no less than 6
months advance written notice of its election to do so, which notice
shall be given to the Authority and each Party, and upon such other
conditions as may be prescribed in Program Agreement 1.
7.1.2 Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its
membership in the Authority following an amendment to this Agreement
in the manner provided by Section 8.4.
7.1.3 Continuing Liability; Further Assurances. A Party that withdraws its
membership in the Authority may be subject to certain continuing
liabilities, as described in Section 7.3. The withdrawing Party and the
Authority shall execute and deliver all further instruments and documents,
and take any further action that may be reasonably necessary, as
determined by the Board, to effectuate the orderly withdrawal of such
Party from membership in the Authority. The Operating Rules and
Regulations shall prescribe the rights if any of a withdrawn Party to
continue to participate in those Board discussions and decisions affecting
customers of the CCA Program that reside or do business within the
jurisdiction of the Party.
7.2 Involuntary Termination of a Partv. This Agreement may be terminated with
respect to a Party for material non-compliance with provisions of this Agreement
or the Authority Documents upon an affirmative vote of the Board in which the
minimum percentage vote and percentage voting shares, as described in Section
4.9.1, shall be no less than 67%, excluding the vote and voting shares of the Party
subject to possible termination. Prior to any vote to terminate this Agreement with
respect to a Party, written notice of the proposed termination and the reason(s) for
such termination shall be delivered to the Party whose termination is proposed at
least 30 days prior to the regular Board meeting at which such matter shall first be
discussed as an agenda item. The written notice of proposed termination shall
specify the particular provisions of this Agreement or the Authority Documents
that the Party has allegedly violated. The Party subject to possible termination
shall have the opportunity at the next regular Board meeting to respond to any
reasons and allegations that may be cited as a basis for termination prior to a vote
regarding termination. A Party that has had its membership in the Authority
terminated may be subject to certain continuing liabilities, as described in Section
7.3. In the event that the Authority decides to not implement the CCA Program,
the minimum percentage vote of 67% shall be conducted in accordance with
Section 4.10 rather than Section 4.9.1.
7.3 Continuing Liabilitv; Refund. Upon a withdrawal or involuntary termination of
a Party, the Party shall remain responsible for any claims, demands, damages, or
liabilities arising from the Party's membership in the Authority through the date
of its withdrawal or involuntary termination, it being agreed that the Party shall
not be responsible for any claims, demands, damages, or liabilities arising after
the date of the Party's withdrawal or involuntary termination. In addition, such
Party also shall be responsible for any costs or obligations associated with the
Party's participation in any program in accordance with the provisions of any
agreements relating to such program provided such costs or obligations were
incurred prior to the withdrawal of the Party. The Authority may withhold funds
otherwise owing to the Party or may require the Party to deposit sufficient funds
with the Authority, as reasonably determined by the Authority, to cover the
Party's liability for the costs described above. Any amount of the Party's funds
held on deposit with the Authority above that which is required to pay any
liabilities or obligations shall be returned to the Party.
7.4 Mutual Termination. This Agreement may be terminated by mutual agreement
of all the Parties; provided, however, the foregoing shall not be construed as
limiting the rights of a Party to withdraw its membership in the Authority, and
thus terminate this Agreement with respect to such withdrawing Party, as
described in Section 7.1.
7.5 Disposition of Proaerty uaon Termination of Authoritv. Upon termination of
this Agreement as to all Parties, any surplus money or assets in possession of the
Authority for use under this Agreement, after payment of all liabilities, costs,
expenses, and charges incurred under this Agreement and under any program
documents, shall be returned to the then -existing Parties in proportion to the
contributions made by each.
ARTICLE 8
MISCELLANEOUS PROVISIONS
8.1 Disuute Resolution. The Parties and the Authority shall make reasonable efforts
to settle all disputes arising out of or in connection with this Agreement. Should
such efforts to settle a dispute, after reasonable efforts, fail, the dispute shall be
settled by binding arbitration in accordance with policies and procedures
established by the Board.
8.2 Liabilitv of Directors. Officers, and Emplovees. The Directors, officers, and
employees of the Authority shall use ordinary care and reasonable diligence in the
exercise of their powers and in the performance of their duties pursuant to this
Agreement. No current or former Director, officer, or employee will be
responsible for any act or omission by another Director, officer, or employee. The
Authority shall defend, indemnify and hold harmless the individual current and
former Directors, officers, and employees for any acts or omissions in the scope
of their employment or duties in the manner provided by Government Code
Section 995 et seq. Nothing in this section shall be construed to limit the defenses
available under the law, to the Parties, the Authority, or its Directors, officers, or
employees.
8.3 Indemnification of Parties. The Authority shall acquire such insurance coverage
as is necessary to protect the interests of the Authority, the Parties and the public.
The Authority shall defend, indemnify and hold harmless the Parties and each of
their respective Board or Council members, officers, agents and employees, from
any and all claims, losses, damages, costs, injuries and liabilities of every kind
arising directly or indirectly from the conduct, activities, operations, acts, and
omissions of the Authority under this Agreement.
8.4 Amendment of this Agreement. This Agreement may be amended by an
affirmative vote of the Board in which the minimum percentage vote and
percentage voting shares, as described in Section 4.9.1, shall be no less than 67%.
The Authority shall provide written notice to all Parties of amendments to this
Agreement, including the effective date of such amendments. A Party shall be
deemed to have withdrawn its membership in the Authority effective immediately
upon the vote of the Board approving an amendment to this Agreement if the
Director representing such Party has provided notice to the other Directors
immediately preceding the Board's vote of the Party's intention to withdraw its
membership in the Authority should the amendment be approved by the Board.
As described in Section 7.3, a Party that withdraws its membership in the
Authority in accordance with the above-described procedure may be subject to
continuing liabilities incurred prior to the Party's withdrawal. In the event that
the Authority decides to not implement the CCA Program, the minimum
percentage vote of 67% shall be conducted in accordance with Section 4.10 rather
than Section 4.9.1.
8.5 Assignment. Except as otherwise expressly provided in this Agreement, the
rights and duties of the Parties may not be assigned or delegated without the
advance written consent of all of the other Parties, and any attempt to assign or
delegate such rights or duties in contravention of this Section 8.5 shall be null and
void. This Agreement shall inure to the benefit of, and be binding upon, the
successors and assigns of the Parties. This Section 8.5 does not prohibit a Party
from entering into an independent agreement with another agency, person, or
entity regarding the financing of that Party's contributions to the Authority, or the
disposition of proceeds which that Party receives under this Agreement, so long
as such independent agreement does not affect, or purport to affect, the rights and
duties of the Authority or the Parties under this Agreement.
8.6 Severabilitv. If one or more clauses, sentences, paragraphs or provisions of this
Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby
agreed by the Parties, that the remainder of the Agreement shall not be affected
thereby. Such clauses, sentences, paragraphs or provision shall be deemed
reformed so as to be lawful, valid and enforced to the maximum extent possible.
8.7 Further Assurances. Each Party agrees to execute and deliver all further
instruments and documents, and take any further action that may be reasonably
necessary, to effectuate the purposes and intent of this Agreement.
8.8 Execution by Counterparts. This Agreement may be executed in any number of
counterparts, and upon execution by all Parties, each executed counterpart shall
have the same force and effect as an original instrument and as if all Parties had
signed the same instrument. Any signature page of this Agreement may be
detached from any counterpart of this Agreement without impairing the legal
effect of any signatures thereon, and may be attached to another counterpart of
this Agreement identical in form hereto but having attached to it one or more
signature pages.
8.9 Parties to be Served Notice. Any notice authorized or required to be given
pursuant to this Agreement shall be validly given if served in writing either
personally, by deposit in the United States mail, first class postage prepaid with
return receipt requested, or by a recognized courier service. Notices given (a)
personally or by courier service shall be conclusively deemed received at the time
of delivery and receipt and (b) by mail shall be conclusively deemed given 48
hours after the deposit thereof (excluding Saturdays, Sundays and holidays) if the
sender receives the return receipt. All notices shall be addressed to the office of
the clerk or secretary of the Authority or Party, as the case may be, or such other
person designated in writing by the Authority or Party. Notices given to one Party
shall be copied to all other Parties. Notices given to the Authority shall be copied
to all Parties.
ARTICLE 9
SIGNATURE
IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement
establishing the Marin Energy Authority.
By:
Name: Ly' r'
Title: Q
Date:
Party:
Exhibit `A'
Exhibit A
To the
Joint Powers Agreement
Marin Energy Authority
-Definitions-
"AB 117" means Assembly Bill 117 (Stat. 2002, ch. 838, codified at Public
Utilities Code Section 366.2), which created CCA.
"Act" means the Joint Exercise of Powers Act of the State of California
(Government Code Section 6500 et seq.)
"Administrative Services Agreement" means an agreement or agreements entered
into after the Effective Date by the Authority with an entity that will perform tasks
necessary for planning, implementing, operating and administering the CCA Program or
any other energy programs adopted by the Authority.
"Agreement" means this Joint Powers Agreement.
"Annual Energy Use" has the meaning given in Section 4.9.2.2.
"Authority" means the Marin Energy Authority.
"Authority Document(s)" means document(s) duly adopted by the Board by
resolution or motion implementing the powers, functions and activities of the Authority,
including but not limited to the Operating Rules and Regulations, the annual budget, and
plans and policies.
"Board" means the Board of Directors of the Authority.
"CCA" or "Community Choice Aggregation" means an electric service option
available to cities and counties pursuant to Public Utilities Code Section 366.2.
"CCA Program" means the Authority's program relating to CCA that is
principally described in Sections 2.4 and 5.1.
"Director" means a member of the Board of Directors representing a Party.
"Effective Date" means the date on which this Agreement shall become effective
and the Marin Energy Authority shall exist as a separate public agency, as further
described in Section 2.1.
"Implementation Plan" means the plan generally described in Section 5.1.2 of this
Agreement that is required under Public Utilities Code Section 366.2 to be filed with the
California Public Utilities Commission for the purpose of describing a proposed CCA
Program.
"Initial Costs" means all costs incurred by the Authority relating to the
establishment and initial operation of the Authority, such as the hiring of an Executive
Director and any administrative staff, any required accounting, administrative, technical
and legal services in support of the Authority's initial activities or in support of the
negotiation, preparation and approval of one or more Administrative Services Provider
Agreements and Program Agreement 1. Administrative and operational costs incurred
after the approval of Program Agreement 1 shall not be considered Initial Costs.
"Initial Participants" means, for the purpose of this Agreement,
"Operating Rules and Regulations" means the rules, regulations, policies, bylaws
and procedures governing the operation of the Authority.
"Parties" means, collectively, the signatories to this Agreement that have satisfied
the conditions in Sections 2.2 or 3.2 such that it is considered a member of the Authority.
"Party" means, singularly, a signatory to this Agreement that has satisfied the
conditions in Sections 2.2 or 3.2 such that it is considered a member of the Authority.
"Program Agreement 1" means the agreement that the Authority will enter into
with an energy service provider that will provide the electricity to be distributed to
customers participating in the CCA Program.
"Total Annual Energy" has the meaning given in Section 4.9.2.2.
Exhibit B
To the
Joint Powers Agreement
Marin Energy Authority
-List of the Parties-
Exhibit C
To the
Joint Powers Agreement
Marin Energy Authority
-Annual Energy Use -
This Exhibit C is effective as of October 8, 2008.
Party kWh (2005*
City of Belvedere
10,498,935
Town of Corte Madera
75,726,510
Town of Fairfax
23,594,966
City of Larkspur
63,659,700
City of Mill Valley
64,761,440
City of Novato
268,301,203
Town of Ross
13,329,878
Town of San Anselmo
47,874,957
City of San Rafael
332,588,277
City of Sausalito
52,373,525
Town of Tiburon
42,831,004
County of Marin
332,726,224
Authority Total Energy Use 1,328,266,620
*Data provided by PG&E
Exhibit D
To the
Joint Powers Agreement
Marin Energy Authority
- Voting Shares -
This Exhibit D is effective as of October 8, 2008.
Section
Section
Voting
Party
kWh (2005*)
4.9.2.1
4.9.2.2
Share
City of Belvedere
10,498,935
4.17%
0.40%
4.56%
Town of Corte Madera
75,726,510
4.17%
2.85%
7.02%
Town of Fairfax
23,594,966
4.17%
0.89%
5.05%
City of Larkspur
63,659,700
4.17%
2.40%
6.56%
City of Mill Valley
64,761,440
4.17%
2.44%
6.60%
City of Novato
268,301,203
4.17%
10.10%
14.27%
Town of Ross
13,329,878
4.17%
0.50%
4.67%
Town of San Anselmo
47,874,957
4.17%
1.80%
5.97%
City of San Rafael
332,588,277
4.17%
12.52%
16.69%
City of Sausalito
52,373,525
4.17%
1.97%
6.14%
Town of Tiburon
42,831,004
4.17%
1.61%
5.78%
County of Marin
332,726,224
4.17%
12.52%
16.69%
1,328,266,620
50.00%
50.00%
100.00%
*Data provided by PG&E
Exhibit V
FINAL REPORT
MARIN - CALIFORNIA
COMMUNITY CHOICE
April 2008
For copies of this report contact the Marin County Community Development Agency
in San Rafael, California or visit wv.vw.tizatiitclealzeiiergy.info
Page 41 of 204
Page 42 01704
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OR
Wm�A
Acknowledgements.................................................................................................................................................... i
ExecutiveSummary....................................................................................................................................................1
LGovernanceand Organization......................................................................................................................... 4
2.Phased Customer Enrollment.......................................................................................................................... 5
3.Electric Resources.............................................................................................................................................. 6
4.Rates.................................................................................................................................................................... 7
5.Financial Plan..................................................................................................................................................... 9
6.Financings........................................................................................................................................................... 9
7.Implementation Schedule...............................................................................................................................10
CHAPTER1- Introduction.....................................................................................................................................11
Backgroundon CCA..........................................................................................................................................13
CCA Program Components (Implementation Plan Requirements)............................................................15
ProgramImplementation..................................................................................................................................16
CHAPTER 2 - Organizational Plan ........................................................................................................................18
OrganizationalOverview..................................................................................................................................18
34
Governance..........................................................................................................................................................
20
Officers.................................................................................................................................................................
22
Committees..........................................................................................................................................................
22
Addition/Termination of Participation............................................................................................................
22
Termination of Marin Clean Energy................................................................................................................
23
AgreementsOverview.......................................................................................................................................
23
JointPowers Agreement....................................................................................................................................
23
ProgramAgreement No. 1.................................................................................................................................
24
AgencyOperations.............................................................................................................................................24
40
ResourcePlanning..............................................................................................................................................
24
PortfolioOperations...........................................................................................................................................25
EnergyEfficiency................................................................................................................................................
26
RateSetting..............................................................................................................•---........................................26
Financial Management/Accounting.................................................................................................................
26
CustomerServices.............................................................................................................................................. 27
Legal and Regulatory Representation...........................................................................:.................................. 27
Rolesand Functions...........................................................................................................................................28
Staffing...........................................................................29
..................................................................... ..................
CHAPTER 3 - Load Forecast and Resource Plan.................................................................................................34
Introduction.........................................................................................................................................................
34
ProgramPhase-In...............................................................................................................................................
35
Phase1 - Participant Accounts.........................................................................................................................
35
Phase2 - Large Accounts...............................................................................................................................
35
Phase3 - All Accounts.......................................................................................................................................
36
ResourcePlan Overview....................................................................................................................................
36
SupplyRequirements ...... :..................................................................................................................................
38
Customer Participation Rates............................................................................................................................
39
CustomerForecast..............................................................................................................................................
39
SalesForecast.......................................................................................................................................................
40
............................................................... ..........................
Capacity Requirements .............. ... P..age.43.:C1f..2.041
Renewable Portfolio Standards Energy Requirements.................................................................................
43
BasicRPS Requirements..........................................................................................................................43
Revenues from CCA Program Operations......................................................................................................
RPSCompliance Rules.............................................................................................................................
43
Marin Clean Energy's Renewable Portfolio Standards Requirement...............................................44
Marin Clean Energy's Renewable Energy Goals.................................................................................
44
Resources.............................................................................................................................................................
44
PurchasedPower................................................................................................................................................
46
RenewableResources.........................................................................................................................................
47
NearTerm Renewable Potential.............................................................................................................
48
Medium and Long -Term. Renewable Potential....................................................................................
49
Planned Renewable Generation Resources.....................................................................................:.....
52
EnergyEfficiency................................................................................................................................................52
Utility Implementation and Transaction Charges..........................................................................................
Baseline Energy Efficiency Potential Estimates....................................................................................
54
CCAProgram Energy Efficiency Goals.................................................................................................54
FinancingPlan.....................................................................................................................................................
DemandResponse............................:.......................................................................................................55
WorkingCapitaI..................................................................................................................................................
DistributedGeneration......................................................................................................................................56
ProForma............................................................................................................................................................
Impact of Resource Plan on Greenhouse Gas Emissions..............................................................................
58
CHAPTER4 -Financial Plan..................................................................................................................................60
Descriptionof Cash Flow Analysis.................................................................................................................. 60
Costof CCA Program Operations.................................................................................................................... 60
Revenues from CCA Program Operations......................................................................................................
61
CashFlow Analysis Results..............................................................................................................................
63
CCA Program Implementation Feasibility Analysis.....................................................................................
64
CapitalRequirements.........................................................................................................................................66
StartupActivities and Costs.................................................................................................................:............67
StartupCost Summary ........................................................................................................................................
67
EstimatedStaffing Costs....................................................................................................................................68
EstimatedInfrastructure Costs.........................................................................................................................
68
Utility Implementation and Transaction Charges..........................................................................................
69
Estimates of Third Party Contractor Costs......................................................................................................
69
FinancingPlan.....................................................................................................................................................
70
WorkingCapitaI..................................................................................................................................................
70
ProForma............................................................................................................................................................
70
MarinClean Energy Financings.......................................................................................................................
70
CCA Program Start-up and Working Capital (Phases 1 and 2)...................................................................
71
CCA Program Working Capital (Phase 3).......................................................................................................
71
Renewable Resource Project Financing...........................................................................................................
71
Sensitivitiesand Uncertainties..........................................................................................................................
73
Other Risks and Uncertainties................................................................................................................
75
CHAPTER 5 - Ratesetting and Program Terms and Conditions........................................................................77
Introduction......................................................................................_................................................................. 77
RatePolicies .............................. :.......................................................................................................................... 77
RateCompetitiveness......................................................................................................................................... 77
RateStability ........................................................................................................................................................ 78
Equityamong Customer Classes...................................................................................................................... 78
CustomerUnderstanding.................................................................................................................................. 78
RevenueSufficiency........................................................................................................................................... 79
100 percent Renewable Energy Delivery - "100 percent Green Tariff" ...................................................... 79
RateDesign...................................................:::...................................................................................................79
NetEnergy Metering............................................................................................................Page-+,4-of-2()481
RateImpacts........................................................................................................................................................
81
Disclosure and Due Process in Setting Rates and Allocating Costs among Participants .........................
82
Customer Rights and Responsibilities.............................................................................................................83
CustomerNotices...............................................................................................................................................
83
TerminationFee..................................................................................................................................................
84
CustomerConfidentiality .......................................................................................................... ..................
86
Responsibilityfor Payment...............................................................................................................................
86
CustomerDeposits.............................................................................................................................................
86
CHAPTER6 -Marketing Plan................................................................................................................................87
..............
Customer Services........................................................................................................................ ........
87
Partneringwith Large Customers....................................................................................................................
87
CHAPTER7 - Procurement Process.......................................................................................................................89
Introduction............................................................................................................................. ......................
89
ProcurementMethods........................................................................................................................................
89
Procurementat Startup......................................................................................................................................
89
KeyContracts......................................................................................................................................................
90
ElectricSupply Contract.......................................................................................................................... 90
DataManagement Contract.................................................................................................................... 91
Chapter8 - Program Termination.......................................................................................................... ...92
Introduction......................................................................................................................................................... 92
Terminationby Marin Clean Energy............................................................................................................... 92
Terminationby Members.................................................................................................... ........... ....... 93
CHAPTER9 — Appendices......................................................................................................................................94
AppendixA — Pro Forma 2014-2025................................................................................................................. 95
Appendix B - Energy Efficiency Potential in the Marin Communities....................................................... 96
Appendix C — List of Acronyms and Definitions.........................................................................................111
Page 45 of 204
Page 46 of 204
�:{: - :Y.e%',fir,-�w�.+... _ .iC,l. •!:i y:i' •w.��rirr�. >::-
;� �nD� Y ._ •:v �y;s. `� -;tix::;1 r y c,, ~ n3•- Vii. •;. i', y5� ,y.
.�S:-i:.
The following individuals are members of the Local Government Task Force, which has
contributed to the development and review of this Final Business Plan to support the Marin
Communities' CCA initiative.
Belvedere
Sausalito
Barbara Morrison
Councilmember
Mike Kelly
Mayor
ohn Telischak
Councilmember
Jonathan Leone
Councilmember
George Rodericks
City Manager
Herb Weiner
Councilmember
Pierce MacDonald
Planning Manager
Adam Politzer
City Manager
Corte Madera
Paul Kermayae
Former Community Development Director
Melissa Gill'
Former Mayor
Kevin Bryant'
Former Assistant to City Manager
Caria Condon
Councilmeinber
Tiburon
'
David Brad=
Town Manager & Engineer
Leff Slavitz
Mayor
Bob Pendoley
Director of Planning
Paul Smith*
Former Mayor
tory Gokaffski
Senior Engineer
Miles Berger
Councilmember
Fairfax
'hichmd Collins
Councilmember
(Larry Bmgman
Councilmember
Peggy Curran
Town Manager
Lew Tremame
Councilmember
Heidi Bigall
Director of Administrative Services
Mike Rock
Town Manager
Nick Nguyen
Director of Public Works/Town Engineer
(Linda Kelly'
Former Town Manager
MMWD
Larkspur
Cynthia Kohler
Board President
Dan Hillmer
Vice Mayor
David Behar
Board Member
Lary Chu
Councilmember
Paul Helliker
General Manager
lean Bonarder
City Manager
NMWD
Mill Valley
lack Baker
Board Member
Marshall
Mayor
Dennis Rodont
Board Member
Ch
Chris Raker'
Former Mayor
Chris DeGabriel
General Manager
Anne Montgomery
City Manager
Robert Clark
Facilities Superintendent
Eric Ericson
Director of Finance & Human Resources
Cornthf ofAfarfn
f 1Vovato
Hal Brawn
Supervisor
Jim Leland
Mayor Pro Tempore
Charles McGfashan
Supervisor
Carole Dillon -Knutson
Councilmember
Joshua Townsend*
Former State Assembly Member Rep
Madeline Kellner
Councilmember
Leslie Alden
Aide to Supervisor McCiashan
Dan Keen
City Manager
Cynthia Connolly
Aide to Supervisor Brown
lennifer Goldfmger
Assistant to City Manager
Matthew Hymel
County Administrator
Ross
Alm McIntyre
Former Assistant County Administrator
Scot Hunter
Mayor
Eric Engelbart
Administrative Analyst
Bill Cahill
Mayor ProTempore
Mike Lowrie
Administrative Analyst
Richard Strauss
Councilmember
Alex Hinds
Community Development Agency Director
Gary Broad
Town Manager
Dawn Weisz
Principal Planner
Elise Semonian
Senior Planner
Omar Pena
Sustainability Planning Aide
Sar Anscluto
Jamie Turkey
Sustainability Intern
Peter Breen
Via Mayor
Technical Advisory Conmdttee
Barbara Thornton
Councilmember
Sean Casey
Former SFPUC
Debble Slutsman
Town Manager
Ray Ducker
Center for Resource Solutions
San Rafael
Peter L.uchetti
CFP Advisors
Paul Cohen'
Former Vice Mayor
Wally McOuat
HMH Energy Resources, Inc.
Cyr Miller
Councilmember
Gwen Rose
VoteSalar
Damon Connolly
Councilmember
Consultants
Ken Nordhoff
City Manager
John Dalessi
NavigantConsulting, Inc.
Linda Jackson
Principal Planner
kirby Dusel
Navigant Consulting, Inc
Judy London
Jody London Consulting
'
Bill Manus
JBS Energy, Inc
Tim Rosenfeld
HMW International
Greg Slepanicich
Attorney, MIRA JPA
Page 47 of 204
*Former Task Force Member - i -
Page 48 of 204
Beginning in 2004, the County of Marin and the eleven cities within the county ("Marin
Commuiuties" or "Marin") initiated a process to investigate offering retail electric services to
customers located within the Marin Communities through a program known as Community
Choice Aggregation (CCA)? Marin's primary long-term goal in offering CCA service is to
achieve 100 percent renewable energy supply within the Marin Communities, affecting
significant reductions in Greenhouse Gas Emissions (GHG) consistent with Marin's voluntary
International Council for Local Environmental Initiatives (ICLEI) targets (a 15 percent reduction
in total GHG below 1990 levels by 2020, countywide). The Marin Communities have been
compelled to evaluate CCA as an energy service alternative to determine the feasibility of
achieving this long-term goal in light of the. incumbent electric utility's slow progress toward
California's mandated Renewables Portfolio Standard (RPS) and in consideration of the utility's
existing resource supply portfolio (which produces more than 70% of electric power deliveries
from nuclear and natural gas-fired generating sources). The extensive, evaluative process
completed by the Marin Communities has provided a strong indication that formation of a CCA
program could reasonably achieve expeditious progress in achieving the Marin Communities'
goal (over 80% renewable energy supply for the Marin Communities in 2014; alternatively, the
incumbent utility provides approximately 12-14% of its energy from qualified renewable
sources) by providing local residents and businesses with an elective energy service alternative
that directly responds to expressed local interests (a highly renewable energy supply that will
promote significant GHG reductions).
The CCA prograin was established by the legislature in 2002 (AB 117) to give cities and counties
the authority to procure electricity in bulk for resale to customers within their jurisdictional
boundaries. Under this CCA program, PG&E would deliver the electricity to end use
customers and PG&E would continue to read the electric meters and issue monthly bills to
customers enrolled in the CCA program. Unlike traditional utility service, the source of the
electric supply (generation) and the price paid by customers for the generation services
procured by the CCA program would be determined by the CCA. Customers would have the
choice of being automatically enrolled in the program following a notification process or
remaining with the incumbent utility by following the opt -out process described in the
customer notices.
Marin conducted feasibility studies during 2004-2005 to identify the benefits and risks of
forming CCA programs. The feasibility studies, which were subject to peer review by a team of
independent, expert consultants, generally found that Marin could significantly increase its use
of renewable energy while providing electric rate stability and potentially reduced electric rates
over the long-term relative to PG&E. The CCA's ability to finance generation projects at low
cost was identified as a key factor in being able to achieve these objectives. Following
consideration of the feasibility study findings, the Marin Communities decided to jointly
develop a comprehensive business plan that would address issues not included within the
feasibility study scope and to confirm the study's findings in certain key respects.
The eleven cities located with the County of Marin include: Belvedere, Corte Madera, Fairfax, Toa1ur, oI yalI
Novato, San Anselmo, San Rafael, Sausalito, Tiburon and Ross. g 9 o 12WO
1 April 2008
This business plan presents a proposal for Marin to form a regional CCA program serving the
unincorporated areas of the county as well as eleven cities located within the county's
geographic boundary. The plan sets forth proposals for how a Marin CCA program would be
organized, funded and operated. Highlights of the plan include:
D The County of Marin and eleven participating cities would form a new Joint Powers
Agency during early 2009 (potentially earlier, depending on various requisite approvals
by the county and cities), tentatively named the Marin Clean Energy Joint Powers
Authority ("Marin Clean Energy" or "MCE") for purposes of offering CCA services to
customers beginning in 2010 (subject to further refinement of this plan).
➢ MCE would negotiate contracts with third party electric suppliers to provide electricity
to customers and provide other technical Services required for the program under a
public/private partnership model;
MCE would offer two distinct renewable energy supply options to program customers,
reflecting differing preferences within the Marin Comintmities:
• 100 percent renewable energy supply from resources such as wind, solar,
geothermal and biomass, at a specified price premium reflective of renewable
energy and related program operating costs; or
• A graduated renewable supply option with rates equivalent to those of the
incumbent utility — under tlus option, Marin Clean Energy would initially supply
25 percent renewable power, increasing this supply to more than 50 percent by
2014.
➢ MCE would continue to increase its renewable energy procurement/deliveries within
the graduated renewable supply option to achieve the long-term goal of 100 percent
renewable energy supply .for the entire program subject to economic and operational
constraints;
➢ MCE would develop or otherwise obtain entitlements to up to 200 .MW of new
renewable generation by 2014, financed with tax-exempt revenue bonds;
➢ MCE would leverage existing state and federal incentives to achieve a targeted
deployment of at least 13 MW of distributed solar (photovoltaic) systems within its
boundaries by 2019;
➢ MCE would promote additional energy efficiency efforts and ultimately seek to
administer all energy efficiency programs within its jurisdiction, as envisioned by
AB 117; and
➢ Through implementation of the proposed CCA Program, the Cities would cause a
reduction in greenhouse gas emissions of between 302,330 and 534,369 metric tons per
year by 2019, as the renewable resources procured and developed by MCE would
displace production from natural gas fueled power plants.
The financial plan and customer rate impacts presented in Chapter 4 should be considered
illustrative pending incorporation of prices that will be provided by the market in a Request for
Bid that will be issued around January 2009, subject to various requisite approvals by the
county and cities. For the time being, information contained in the Financing Plan is based on
energy prices received by other CCA programs, such as the aspiring East P ge 50 of 2CJram
2 April 2008
and the San Joaquin Valley Power Authority (SJVPA), from the market. While this plan
provides guidelines related to many key areas of CCA operation, certain plan components will
also require input from the county's and cities' legal and financial professionals, as indicated in
this plan. Once the business plan is finalized and reviewed by the Marin Communities (March
2008), the county and cities will need to decide whether to proceed with formation of the JPA,
which would adopt the Implementation Plan for submission to the California Public Utilities
Commission as required by AB 117.
The key planning elements that are statutorily required in an Implementation Plan are
addressed in this business plan. The Public Utilities Code specifies that a CCA Implementation
Plan must include the following components:
➢ Organizational structure of the program, its operations, and funding;
➢ Rate setting and other costs to participants;
➢ Disclosure and due process in setting rates and allocating costs among participants;
➢ Methods for entering and terminating agreements with other entities;
➢ The rights and responsibilities of program participants, including, but not limited to,
consumer protection procedures, credit issues, and shutoff procedures;
➢ Termination of the Program; and
➢ A description of the third parties that will be supplying electricity under the
program, including, but not limited to, information about financial, technical, and
operational capabilities.
California's CCA program is relatively new, and, to date, only one CCA has registered with the
California Public Utilities Commission. California's lone CCA, the SJVPA is comprised of a
consortium of cities and counties in the central San Joaquin Valley. The SJVPA submitted its
CCA Implementation Plan on January 29, 2007? On April 30, 2007, the California Public
Utilities Commission provided notice to the SJVPA certifying that its Implementation Plan
contained sufficient data, as required by California Public Utilities Code Section 366.2. In
addition to the SJVPA, there are several other CCA development efforts under way in San
Francisco, the City of Victorville, the East Bay, West Los Angeles, and Chula Vista.
2 Revisions to SJVPA's Implementation Plan were subsequently submitted on April 27,2007; additional revisions
were filed with the CPUC on August 27, 2007. Page 51 of 204
3 April 2008
The major elements of the business plan are summarized as follows: .
1. Governance and Organization
The program would be implemented by a new JPA whose Board of Directors, comprised of one
elected official from each of the participating communities, would have primary responsibility
for managing all aspects of the CCA program. The JPA would adopt the Implementation Plan
required by the CCA legislation (AB 117) and register with the California Public Utilities
Commission as a Commimity Choice Aggregator.
Decisions by Marin Clean Energy would take place in public meetings under voting procedures
defined in the Joint Powers Agreement. As currently envisioned, all votes on a particular
matter will be subject to a two-tier approval process: first, any decision must be approved by a
simple majority of the Directors at the Governing Board meeting; second, assuming the first
requirement is reached, those Directors voting in the affirmative must constitute over 50 percent
of a weighted voting percentage comprised of equal treatment of each Member's electricity
requirements (expressed as a ratio of each Member's electricity requirements divided by total
energy requirements of the Program) and a pro rata percentage of total membership. An
alternative two-tier approval process, which weights voting based on customer accounts rather
than electricity requirements, has also been included in this Business Plan.
Marin Clean Energy would be established under the terms of a Joint Powers Agreement, which
would institute MCE with a broad set of powers to study, promote, develop and conduct
electricity related projects and programs. The JPA agreement would specify the governance
provisions of Marin Clean Energy. Proposed principles for a JPA Agreement are discussed in
Chapter 2.
The CCA program would most likely be established pursuant to a separate project agreement
(Program Agreement No. 1 or PA -1) executed by and among MCE and the members (eleven
cities and Marin County). The PA -1 would transfer the members' authority under AB 117 to
MCE and authorize the initiation of CCA service to customers within the member's jurisdiction,
subject to specified withdrawal rights.
Operations of the program would be the responsibility of an Executive Director, appointed by
MCE's Board of Directors. The Executive Director would manage staff, contractors and third
party electric providers, in accordance with the general policies established by the Board.
Because MCE expects to commence Program operations under a full -requirements supply
contract with an experienced, third -party energy supplier, the Executive Director will manage
this contractual relationship to ensure performance under the contract's specified terms and
conditions.3
After the Program has established itself, has identified internal staff/management to assume
responsibility for necessary administrative and operational responsibilities, and has properly
trained appropriate individuals to carry out their respective duties, MCE may transition many
responsibilities to internally staffed positions. Most operational responsibilities, particularly
technical functions associated with managing and scheduling electric supplies and those related
3 Asa public entity, any business relationship between Marin Clean Energy and a third-party�gnngaec O . d
to result from a competitive solicitation/selection process. F� T
4 April 2008
to retail customer settlements would be performed by a third -party contractor, likely the
supplier providing service under MCE's initial full -requirements contract.
In the event that MCE transitions administrative and operational responsibilities to internally
staffed positions, it would likely have a full time staff of approximately twenty employees to
perform its responsibilities, primarily related to program and contract management, legal and
regulatory, finance and accounting, energy efficiency, marketing and customer service. As
previously noted, technical functions associated with managing and scheduling electric
supplies and those related to retail customer settlements would be performed by an
experienced third party(ies). In the longer term, these technical functions may be performed by
internal staff or continue to be provided by third parties.
Staffing and contractor costs related to program startup activities are estimated at
approximately $3.4 million. It is estimated that MCE would need working capital (likely in the
form of a letter of credit) in the range of $6.4 million to initiate the Program and provide the
working capital needed for service to customers in Phases J and 2. Credit requirements may
increase to as much as $15.8 million dollars for Phase 3. These figures include working capital
related to power purchases that may ultimately be carried by the Program's electric supplier,
subject to negotiations during the supplier selection process.
2. Phased Customer Enrollment
Service would be offered to customers in three phases, beginning with the service accounts
affiliated with the members of Marin Clean Energy (municipal accounts). The second phase
would include the medium to large commercial and industrial customers, and the third phase
would include all remaining customers. The proposed schedule for customer enrollments is
shown below:
Customer Phase -In Schedule
Phase
Start
Eligibility
Customer Accounts4
Phase 1
January 2010
Municipal Accounts
565
Phase 2
May 2010
Commercial and Industrial
1,192
Accounts
Phase 3
January 2011
All Others
109,344
The phasing schedule enables MCE and third party electricity suppliers to make any
adjustments that may be necessary to ensure the program is operating effectively. It would also
allow for any potential billing, settlement or cash flow problems to be addressed while the
actual number of accounts and revenue requirements are small relative to full scale operations.
MCE's Board of Directors would have final authority for initiating service to Phase 1 customers
and to approve transitioning from one phase to the next.
At full implementation in 2011, the Program is projected to serve over 111,000 retail customers
and have annual electricity sales of over 1,300 GWh. Annual revenues are projected to be
4 Customer account totals represent estimates based on an escalation of 2005 account data provided by PG&E. An
annual escalation rate of 0.5 percent was applied to this PG&E data with an assumption that 100 percent of Phase 1
customers and 90 percent of Phase 2 and 3 customers 5 were retained (10 percent opt -out per clasq. . 204
F'
approximately $128 million. The break down of projected sales by major customer class is
shown in the following figure.
17% —.
Projected Customer Mix In 2011
Marin Clean Energy
Customer Mix by Load
1%
® Residential ® Small Commercial 11 Medium Commercial
El Large Commercial ® Industrial . Ll Street Light
® Agriculture
3. Electric Resources
Beginning with the commencement of service to Phase 1 customers in 2010 through 2013, MCE
would contract with a third party electric supplier under a "full requirements" contract, which
places the responsibility for arranging for power to be delivered to program customers with the
supplier. MCE would establish specific renewable standards that the supplier must meet. The
proposed renewable standard begins at 56 percent in 2010 (based on a weighted average of
program customers participating in a 100 percent renewable supply tariff as well as the 25
percent renewable supply provided to cost -sensitive program customers — these two distinct
tariff options are discussed in additional detail below). Beyond 2013, the Program intends to
promote additional renewable energy utilization to the level of 80 percent (based on a weighted
average of program customers participating in the 100 percent renewable, supply tariff as well
as the 51 percent renewable supply provided to cost -sensitive program customers,, a planned
increase from the 25 percent introductory renewable supply level that occurs in 2014) or greater;
achievement of this ambitious goal will likely depend on MCE's investment in the development
of new renewable generation capacity..
To meet this goal, MCE would develop and potentially finance 200 MW of renewable
generating capacity, scheduled to be online in 2014. Resource development and financing
would likely be conducted with another public agency or agencies with experience in electric
resource development. Additional renewable energy purchases would supplement MCE's
generation to sustain or exceed the 80 percent renewable energy target. In addition, MCE
6 P pnYbIg 204
would promote expanded customer side energy efficiency and demand response programs and
target deployment of approximately 13 MW of distributed solar within its service area by 2019.
The clean electric supply portfolio developed by Marin Clean Energy is expected to result in net
reductions in greenhouse gas emissions of between 302,330 to 534,369 tons per year by 2019 due
to displacement of natural gas generation that would otherwise be used. GHG reductions of
this magnitude represent between. 10 percent and 17 percent of the Marin Communities' current
emissions total (from all sectors).
4. Rates
The ability to meet these goals will be confirmed during the program's supplier solicitation
process. The Program's preliminary goals are based on the development of two distinct rate
tariffs between which program customers may choose: 1) 100 percent renewable, or "Green,"
energy supply; and 2) a graduated renewable energy supply option, or "Light Green." The
100 percent Green Tariff will provide program customers with 100 percent renewable energy
supply at a rate premium of approximately 1.9 cents/kWh. This premium will be directly
related to the incremental cost incurred by the program to procure necessary renewable energy
supplies as well as administrative costs, including increased reserve requirements, related
' thereto. The Light Green Tariff is designed with cost -sensitive customers in mind, providing
these residents and businesses with a relatively high level of renewable energy supply
(25 percent in 2010, increasing to 51 percent in 2014) at a generation rate equivalent to the
incumbent utility, PG&E. 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. Projected program rates for each of the program's two tariffs are
shown in the following table. The following rates are illustrative and subject to change
pending the pricing information that will be requested from potential suppliers.5
5 Based on initial supplier responses received by the SJVPA and the East Bay communities as well as the Program's
expressed interest in achieving a highly renewable resource mix when operations commence, the Program will likely
set rates that are equivalent to those of the incumbent utility, PG&E.
7 PRnli0gf 204
Marin Clean Energy Estimated 2011 Program Rates
Customer Class
Program Rates —100
Program Rates —
PG&E Generation
percent Green
Light Green
Rate
(25/51%)
(Cents Per kWh)
(Cents Per kWh)
(Cents Per kWh)
Residential
11.3
9.4
9.4
Small Commercial
11.5
9.6
9.6.
Medium
11.1
9.3
9.3
Commercial
Medium Industrial
10.2
8.5
8.5.
Large Industrial
9.7
8.1
8.1
Agricultural
9.5
7.9
7.9
Street and Area
9.7
8.1
8.1
Lighting
PG&E rates are based on those contained in Advice Letter No. 3115 -E-A (Effective January 11 2008), escalated at 3.5
percent per year to 2011.
MCE would establish its rates on an annual basis, as it adopts its budget for thecoming year.
Program custorners would be provided with notices of rate changes and be given the
opportunity to comment on proposed rate changes before they are made effective by MCE's
Board of Directors at a duly noticed public meeting.
Customers would be provided with four notices and opportunities to opt -out of the program
without penalty of any kind, twice within 60 days prior to enrollment and twice within the first
two months of service. Following the free opt -out period, customers would be allowed to
discontinue service, subject to payment of a nominal Termination Fee.. The proposed
Termination Fee includes an Administrative Fee (proposed at $5 for residential customers) and,
if necessary, .a Cost Recovery Charge to prevent shifting of costs to remaining Program
customers. MCE's Board would establish the Cost Recovery Charge as part of its ratesetting
responsibilities in the case where the costs of the program's electric supply commitments exceed
the prevailing market price for electricity. The Cost Recovery Charge would'provide a financial
backstop to be used as partial security for financing of MCE's power supply commitments and .
as credit'support for the electric supply agreement. Additional refinement of the Termination
Fee would require input from the Cities' financial advisors, investment bankers, bond counsel
and customers for inclusion in the Program's Implementation Plan. MCE's Board of Directors
would also have the authority to implement entry fees for customers that initially opt out of the
Program, but later decide to participate. Entry fees would help prevent potential gaming,
particularly by large customers, and aid in resource planning by providing additional control
over the Program's customer base. Entry fees would not be practical to administer, nor would
they be necessary, for residential and other small customers.
8 P io@A 204
5. Financial Plan
It is estimated that MCE would need to procure full requirements power supply for the four-
year Implementation Period at an average cost of 8.8 cents per kWh (for power supply
corresponding with the conventional/renewable mix provided in the Light Green Tariff) to be
able to offer rates equal to those of PG&E. A pro forma for the implementation period,
including generation rates equivalent to PG&E, is shown in the following table, based on a full
requirements contract price of 8.8 cents per kWh. Costs and revenues presented in the table
' below are illustrative and subject to change based on responses to the County's and Cities'
request for information and proposals from third party electric suppliers.
-;
Marin
Clean Energy
Summary of CCA
Program
Implementation
(January 2009 through December 2013)
,
CATEGORY
2009
2010
2011
2012
2013
TOTAL
L REVENUES FROM OPERATIONS ($):
(A) ELECTRICITY SALES:
i RESIDENTIAL
$0
$271
$68,459,083
$71,209,427
$74,070,266
$213,739,048
GENERAL SERVICE (A-1)
$0
$332,029
$16,246,125
$16,911,607
$17,591,030
$51,080,791
s SMALL TIME -0E -USE (A-6)
$0
$277,770
$5,769,373
$6,067,692
$6,311,462
$18,426,297
ALTERN. RATE FOR MEDIUM USE (A-10)
$0
$15,499,512
$21734,676
$22,664,751
$233,575,307
$83,474,246
500 - 900kW DEMAND (E-19)
$0
$6597,654
$9,049,315
$9,375,412
$9,752,069
$34,774,451
1000+kW DEMAND (E-20)
$0
$3,904,820
$5,405,411
$5,633,713
$5,860,048
$20,803,993
STREET LIGHTING & TRAFFIC CONTROL
$0
$534,302
$755,054
$785,389
$816,942
$2,891,687
AGRICULTURAL PUMPING
$0
$275
$549,460
$548,644
$570,686
$1,669,065
TOTAL REVENUES
$0
$27,146,633
$127,968,499
$133,196,635
$138,547,810
$426,859,577
IL COST OF OPERATIONS ($):
(A) ADMINISTRATIVE & GENERAL (A& -q:
STAFFING
$451,067
$2,661,067
$3,092,725
$3,185,507
$3,281,072
$I2,671,437
INFRASTRUCTURE
$139500
$192,000
$157,500
$162 225
$167,092
$818,317
CONTRACTOR COSTS
$434,833
$1607,417
$2,608,875
$2,635,255
$2,714,313
$10,000,693
IOU FEES (INLCUDING BILLING)
$200,023
$187,286
$1,128,200
$1,024,786
$1,055,529
$3,595,825
CONTRACT STAFF
$0 •
. $0
$D
$0
$0
$0
SUBTOTAL -A&G
$1,225,423
$4,647,770
$6,987,300
$7,007,773
$7,218,006
$27,086,271
(B) CCA PROGRAM OPERATIONS:
ELECTRI=PROCUREMENT
$0
$22,781,412
$107,727,159
$110,974,279
$114,317,379
$355,800,229
RENEWABLE PORTFOLIO ADJUSTMENT
$0
$1,422,695
$9,284,041
$8,400,441
$7,507,772
$26,614,948
SUBTOTAL -CCA PROGRAM OPERATONS
$0
$24,204,106
$117,011,200
$119,374,720
$121,825,152
$382,415,177
TOTAL COST OF OPERATION
1
$1,225,423
$28,851,876
$123,998,499
$126,382,492
$129,D43,157
$409,501,448
CCA PROGRAM SURPLUS / (DEFICIT)
($1,225,423)
($1,705,243)
$3,969,999
$6,814,143
$9,504,653
$17,358,129
6. Financings
To achieve program commencement in January 2010, MCE would need to establish credit in
mid 2009 sufficient to obtain short term financing, likely a letter of credit, for approximately $6.4
million to cover program startup costs and working capital associated with Phases 1 and 2.
MCE's capital requirements would increase to approximately $15.8 million for Phase 3. These
amounts would be repaid over a five to seven year term.
Financing to support development of MCE's renewable generation capacity would require an
approximately $475 million issuance of revenue bonds. The bonds could be issued by MCE or
by another public agency which would sell the output to MCE. This financing would occur
once specific projects are completely sited and the CCA Program is fully up and running. The
anticipated financial dose for the renewable resource project would be winter 2011. The
financing would be in the range of a 20 to 30 year term.
9 PA-Pft Noef 204 -
Z Implementation Schedule
There are several major steps that would need to be accomplished prior to the initiation of the
CCA Program outlined in this business plan. Five of these steps represent decision points or
"off ramps" that allow for program participants to periodically evaluate the prospective CCA
program based on current market conditions, evolving community preferences and various
other considerations before proceeding with the implementation process.
Five natural decision points or "off ramps" are built into the business plan. The first occurs
once the business plan is finalized and the county and cities elect whether to continue with
development and filing of a formal Implementation Plan or to terminate their investigation of
CCA. The goal is for the county and cities to have sufficient information with respect to the
likelihood of the program meeting its renewable energy and rate objectives, assurance that the
risks are understood and manageable, and that the plan is financially sound for the county and
cities to make an informed decision whether to continue. The second decision point occurs after
the JPA Agreement and the Implementation Plan have been drafted and each participating
community has been given the opportunity to review and comment on the documents. At that
time, the county and cities will determine whether or not to continue with actual program
implementation in the form of unique ordinances, consistent with the statutory requirements of
AB 117. This second off -ramp provides an opportunity for leadership within each participating
community to consider community -specific feedback before deciding to participate in the JPA.
Following the passage of ordinances, participating Members will commence operation of Maru1
Clean Energy and will issue a Request for Bid to prospective energy suppliers.
The - third and fourth off -ramps require Marin Clean Energy's Board to approve both the
Implementation Plan and Program Agreement 1. Following approval of the Implementation
Plan, this document would be filed with the CPUC - for certification. The fifth, and final,
decision point occurs after the CPUC certifies the Implementation. Plan, and the county and
cities elect whether or not to continue with actual program implementation. This decision point
allows the JPA to deal with potential regulatory decisions that could materially change the
program as well as any developments in current market conditions that may preclude the
program from meeting its economic and/or renewable supply objectives.
10 - PW-floaa; 204
Following passage of Assembly Bill 117 in 2002, which created the legal authority for cities and
counties to provide electric service through Community Choice Aggregation, the County of
Marin, on behalf of the unincorporated areas of the county as well as the eleven cities within its
geographic boundaries, which include San Rafael, Novato, Corte Madera, Mill Valley, Larkspur,
Sausalito, San Anselmo, Tiburon, Fairfax, Ross -and Belvedere, initiated a feasibility study to
evaluate the costs and benefits of implementing CCA programs within its jurisdiction. Under
California law, CCA allows cities, counties, or joint power agencies OPA's) comprised of cities
and/or counties to implement programs that aggregate the electric loads of customers within
their jurisdictional boundaries for purposes of electricity procurement. This allows the
city/county/)PA (CCA Provider) to make wholesale purchases of electricity on behalf of its
constituents, providing an alternative to the incumbent utility, PG&E. -
The feasibility study found that it would be economically feasible for the county and the eleven
cities to jointly implement a CCA program and significantly increase the use of renewable
energy resources in fulfilling the electricity requirements of the communities. The studies
found that the county and cities could jointly provide electricity to program customers at costs
lower than the rates projected to be charged by PG&E due in large part to the ability of these
local governments to finance generation facilities using low cost, tax-exempt bonds. The
feasibility study found that additional cost savings could be achieved if the county and cities
joined together to procure electricity for the program and conduct certain common activities.
The feasibility studies also identified several risks and uncertainties that would need to be
addressed as the program is implemented and operated. Finally, the feasibility study identified
the steps that must be completed in the formation of a CCA program, including the
development of the legally required Implementation, Plan that identifies how the program
would be organized, funded and operated.
Marin County retained an independent consultant to perform a peer review of the feasibility
study. The peer review concluded that the feasibility study provided sufficient information to
proceed with the next phase of the project, which involves development of a program business
plan. The peer review also suggested changes in certain underlying analytical assumptions and
recommended additional sensitivity analyses that should be included in the next phase of
study.
A limited feasibility study update was subsequently performed, incorporating the
recommendations of the peer review team. The results of the updated feasibility study
generally fell within the range of sensitivities contained in the original feasibility study. The
updated analyses did not change the overall conclusions and recommendations contained -in the
original study.
The Marin Communities then decided to collaboratively develop a business plan for
implementing a joint CCA program. During this process, leadership within the Marin
r Communities expressed an interest in understanding the potential impacts of a CCA program
that would offer a 100 percent renewable energy supply to its customers. Specifically, the
11 %92 22N Of 204
Marin Communities wanted to determine the extent to which local climate impacts could be
mitigated through the implementation of a highly renewable energy supply portfolio. After
evaluating the economic and environmental implications of such a program (program rates
would likely exceed utility rates over the near term of 5-10 years; significant, sustained GHG
reductions could be achieved), the Marin Communities jointly decided to proceed with the
development of a CCA business plan that will offer customers 100 percent renewable energy
supply and will affect GHG .reductions up to 17 percent of current totals within the Marin
Communities. This business plan outlines a framework for how a CCA program serving Marin
County andthe eleven cities located therein could be .organized, governed, operated, and
financed. Many aspects included within this business plan are universally applicable to any
local governments) that may choose to pursue CCA. However, each CCA program will have
unique goals, objectives and demographic profiles as well as many other characteristics
impacting program development. The unique characteristics, specific to Marin's CCA Program,
have been identified herein and addressed in the program -specific analyses. underlying this
business plan. Details reflected in this business plan were developed in consideration of the
current legal and regulatory frameworks affecting CCA participants. This business plan
contains the following sections:
➢ Organizational Plan;
➢ Load Forecast and Resource Plan;
➢ Financial Plan;
➢ Ratesetting and Program Terms;
➢ Procurement Process; and
➢ Program Termination.
The business plan will be subject to much discussion and refinement among the county's and
cities' representatives, stakeholders, outside experts and the public before a decision to proceed
with developing a formal Implementation Plan can be made. Ultimately, the evaluation will
incorporate price offers from third party electric suppliers, which will provide the certainty
needed- to determine whether the program can offer the rates proposed herein, while meeting
the program's specified renewable energy targets, upon initiation. Information from potential
electric suppliers has not been requested at this time, but the Marin Communities have utilized
the information received by the SJVPA and the East Bay Communities in response to their non-
binding requests for information.
This document represents a comprehensive Business Plan for Marin Clean Energy. It presents
to the Marin Communities a compilation of proposed plans for organization and governance,
ratesetting policies and processes, staffing plans, roles and responsibilities, detailed startup.
Costs and financing, a phased customer enrollment plan, energy efficiency and distributed
generation plans, suggested renewable resource technologies and generally defined locations
for development, program terms and conditions, and a process for procuring the key third
party services needed for program implementation. Information included in this business plan
is based, in part, on input received from the Marin Communities as well as other interested
stakeholders and advisors. Several preliminary concepts are presented in this plan that will
require input from the county's and cities' financial advisors, bankers and attorneys: The ability
12 Pi6a 204
to offer competitive rates will be addressed in greater detail once the Marin Communities have
formed a joint powers agency and have issued a request for bid to potential suppliers (January
2009). At that time, the JPA's Governing Board will evaluate the responses received from
potential suppliers and will initiate a full analysis of financial sensitivities to ensure that the
program can meet its specified objectives. For the time being, many of the quantitative analyses
siipporting.this business plan utilize energy prices that were offered by private energy suppliers
to the East Bay Communities and the SJVPA.
Five natural decision points or "off ramps" are built into the business plan. The first occurs
once the business plan is finalized and the county and cities elect whether to continue with
development and filing of a formal Implementation Plan or to terminate their investigation of
CCA. The goal is for the county and cities to have sufficient information with respect to the
likelihood of the program meeting its renewable energy and rate objectives, assurance that the
risks are understood and manageable, -and that the plan is financially sound for the county and
cities to make an informed decision whether to continue. The second decision point occurs after
the JPA Agreement and the Implementation Plan have been drafted and each participating
community has been given the opportunity to review and comment on the documents. At that
time, the county and cities will determine whether or not to continue with actual program
implementation in the form of unique ordinances, consistent with the statutory requirements of
AB 117. This second off -ramp provides an opportunity for leadership within.each participating
community to consider community -specific feedback before deciding to participate in the JPA.
Following the passage of ordinances, participating Members will commence operation of Marin
Clean Energy and will issue a Request for Bid to prospective energy suppliers.
The third and fourth off -ramps require MCE's Board to approve both the Implementation Plan
and Program Agreement 1. Following approval of the Implementation Plan, this document
would be filed with the CPUC for certification. The fifth, and final, decision point occurs after
the CPUC certifies the Implementation Plan, and the county and cities elect whether or not to
! continue with actual program implementation. This decision point allows the JPA to deal with
potential regulatory decisions that could materially change the program as well as any
developments in current market conditions that may preclude the program from meeting its
economic and/or renewable supply objectives.
Following these predetermined off -ramps, CCA customers are given four additional
opportunities to opt -out of program service by responding to service notices included in their
utility bills. Each of these off -ramps, coupled with the customer notification requirement and
related opt -out provisions, will ensure that this CCA program is undertaken by well-informed
decision -makers and subscribed to by willing customers.
Background on CCA
AB 117 provides for the CCA Program to be an opt -out program, meaning that all customers are
included in the program unless they make a positive declaration that they do not wish to
participate.
The CCA Provider will only procure the electric energy commodity; the actual delivery of the
commodity remains the obligation of PG&E. PG&E willcontinue to provide all non -generation -
13 F;R ooRf 204
related services, including delivery, metering, billing, customer service, and traditional retail
customer services.. This is an important distinction of CCA compared to a municipal utility that
owns the transmission and distribution wires and distributes electricity. The following figure
illustrates the potential electricity delivery under a CCA Program.. .
In the current electric marketplace, PG&E no longer owns a substantial amount of generation,
with the exception of its hydroelectric and nuclear assets. However, PG&E has announced
plans to invest billions in new generation over the next several years and is poised to re-enter
the generation market that it exited during the restructuring period of the late 1990s. PG&E
purchases the rest of its electric needs from the wholesale marketplace and is the monopoly
provider of transmission and distribution services. Under CCA, the customer (i.e. the CCA
Provider) chooses the types and amount of generation that it purchases (or owns) for its
constituents. Customers are able to choose the generation services offered by the CCA or the
generation services offered by the incumbent utility. The wires (transmission and distribution)
continue to be provided by the local monopoly.
PG&E supported AB 117, but its responses to prospective CCA programs throughout the state .
have been consistently negative. When given the opportunity to comment on specific CCA
documents (such as business plans or ii nplementation plans) and/or various programmatic
objectives, PG&E has been reluctant to identify any specific aspects of these programs which it
supports without qualification or reservation. Furthermore, PG&E has offered limited
constructive feedback to prospective CCA 'programs since the passage of AB 117, choosing to
focus its efforts on downplaying and/or challenging the environmental and potential economic
benefits of such programs. Nevertheless, PG&E has provided all of the information that the
county and cities have requested to date and remains cooperative in the Marin Communities'
efforts to gather information necessary to evaluate CCA, which is consistent with the minimum
requirements imposed by AB .117. Based on PG&E's active opposition to the SJPVA CCA
program and public criticism of the proposed CCA program for the City and County of San
Francisco, Marin should expect PG&E to oppose its efforts going forward, including targeted
lobbying of large energy customers and political officials.
14 Pae %94204
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In the current electric marketplace, PG&E no longer owns a substantial amount of generation,
with the exception of its hydroelectric and nuclear assets. However, PG&E has announced
plans to invest billions in new generation over the next several years and is poised to re-enter
the generation market that it exited during the restructuring period of the late 1990s. PG&E
purchases the rest of its electric needs from the wholesale marketplace and is the monopoly
provider of transmission and distribution services. Under CCA, the customer (i.e. the CCA
Provider) chooses the types and amount of generation that it purchases (or owns) for its
constituents. Customers are able to choose the generation services offered by the CCA or the
generation services offered by the incumbent utility. The wires (transmission and distribution)
continue to be provided by the local monopoly.
PG&E supported AB 117, but its responses to prospective CCA programs throughout the state .
have been consistently negative. When given the opportunity to comment on specific CCA
documents (such as business plans or ii nplementation plans) and/or various programmatic
objectives, PG&E has been reluctant to identify any specific aspects of these programs which it
supports without qualification or reservation. Furthermore, PG&E has offered limited
constructive feedback to prospective CCA 'programs since the passage of AB 117, choosing to
focus its efforts on downplaying and/or challenging the environmental and potential economic
benefits of such programs. Nevertheless, PG&E has provided all of the information that the
county and cities have requested to date and remains cooperative in the Marin Communities'
efforts to gather information necessary to evaluate CCA, which is consistent with the minimum
requirements imposed by AB .117. Based on PG&E's active opposition to the SJPVA CCA
program and public criticism of the proposed CCA program for the City and County of San
Francisco, Marin should expect PG&E to oppose its efforts going forward, including targeted
lobbying of large energy customers and political officials.
14 Pae %94204
0 MOM. Y
thom
Mies t f1i Dim
In the current electric marketplace, PG&E no longer owns a substantial amount of generation,
with the exception of its hydroelectric and nuclear assets. However, PG&E has announced
plans to invest billions in new generation over the next several years and is poised to re-enter
the generation market that it exited during the restructuring period of the late 1990s. PG&E
purchases the rest of its electric needs from the wholesale marketplace and is the monopoly
provider of transmission and distribution services. Under CCA, the customer (i.e. the CCA
Provider) chooses the types and amount of generation that it purchases (or owns) for its
constituents. Customers are able to choose the generation services offered by the CCA or the
generation services offered by the incumbent utility. The wires (transmission and distribution)
continue to be provided by the local monopoly.
PG&E supported AB 117, but its responses to prospective CCA programs throughout the state .
have been consistently negative. When given the opportunity to comment on specific CCA
documents (such as business plans or ii nplementation plans) and/or various programmatic
objectives, PG&E has been reluctant to identify any specific aspects of these programs which it
supports without qualification or reservation. Furthermore, PG&E has offered limited
constructive feedback to prospective CCA 'programs since the passage of AB 117, choosing to
focus its efforts on downplaying and/or challenging the environmental and potential economic
benefits of such programs. Nevertheless, PG&E has provided all of the information that the
county and cities have requested to date and remains cooperative in the Marin Communities'
efforts to gather information necessary to evaluate CCA, which is consistent with the minimum
requirements imposed by AB .117. Based on PG&E's active opposition to the SJPVA CCA
program and public criticism of the proposed CCA program for the City and County of San
Francisco, Marin should expect PG&E to oppose its efforts going forward, including targeted
lobbying of large energy customers and political officials.
14 Pae %94204
CCA Program Components (Implementation Plan Requirements)
This section contains a broad overview of the major components of the CCA Program organized
under the requirements of AB 117, which state that all CCA Programs must, at a minimum,
address the following:
➢ Organizational structure of the program, its operations, and funding;
➢ Rate setting and other costs to participants;
➢ Disclosure and due process in setting rates and allocating costs among participants;
➢ Methods for entering and terminating agreements with other entities;
➢ The rights and responsibilities of program participants, including, but not limited to,
consumer protection procedures, credit issues, and shutoff procedures;
➢ Termination of the Program; and
➢ A description of the third parties that will be supplying electricity under the
program, including, but not limited to, information about financial, technical, and
operational capabilities.
Additionally, AB 117 added Section 366.2 (c)(3) to the California Public Utilities Code requiring
that an Implementation Plan provide for:
➢ Universal access;
Reliability;
➢ Equitable treatment of all classes of customers; and
➢ Any requirements established by state law or by the CPUC concerning aggregation
services.
There are several other cities or potential groups of cities and/or counties around California that
are also considering implementing a CCA program. To date there is only one CCA program
operating in California, the San Joaquin Valley Power Authority, scheduled to begin serving
customers in 2008 6 The first CCA Implementation Plan in California was submitted to the
California Public Utilities Commission by a new joint powers agency, the SJVPA, which
represents- municipalities in the greater Fresno area, on January 29, 2007. Subsequent to this
submittal, the SJVPA filed revisions with the CPUC on April 27, 2007 and again on August 27,
2007. On September 7, 2007, the California Public Utilities Commission provided notice to the
SJVPA certifying that its current Implementation Plan contained sufficient data, as required by
California Public Utilities Code Section 366.2. Much has been and will continue to be learned
from the experiences of the SJVPA as it proceeds with its formation and commencement of
operations during 2007. Other notable CCA efforts include the City and County of San
Francisco, the City 'of Victorville, the East Bay Communities, the City of Chula Vista, and the
Cities of Beverly Hills and West Hollywood. -
+ 6 Community aggregation programs also exist in other states including Massachusetts, Texas, and Ohio. The Ohio
program is very similar to the CCA programs proposed for California. Aa 6 U8 f 204
Program Implementation
There are several major steps that would need to be accomplished prior to the initiation of the
CCA program outlined in this business plan. Following completion of the final business plan,
creation of the necessary program agreements, and a decision to proceed with developing an
Implementation Plan, the first major step would be for the county and cities to approve a joint
powers agreement and to form the JPA. The county and each city would also need to pass
unique ordinances, as required by AB 117, declaring the county's and each city's intent to file a
CCA Implementation Plan through Marin- Cleann Energy.. Formation of the JPA will be a
significant milestone. Once formed, the JPA. can solicit offers for power supply and other
services, adopt an Implementation Plan, and file the Implementation Plan with the CPUC.
These' activities would take place before a final program evaluation is made, making formation
of MCE a critical step in the CCA evaluation process.
The planned sequence of events showing major steps prior to the CCA program beginning to
serve customers is shown in the following table. Approval of voters. is not legally required for
formation of a , CCA program, but the county and cities have allowed time in their
implementation schedule for individual communities to hold an election on this issue, if this
becomes necessary.? As proposed, the JPA would require at least three participants, including
the County of Marin, the City of San Rafael and the City of Novato, to execute the JPA
agreement to become effective.
The County of Marin has mentioned that the decision to proceed with CCA may require a ballot measure for the
county and certain participating cities in the event that a rate increase, relative to generation rates charged by PG&E,
is projected. Potential generation rates of the Program will become more certain after the Program receives responses
to its request for bids from energy suppliers in January 2009.
16 P§,?&& ,# 204
Timeline for Implementation
ACTIVITY
TIMELINE
Complete Business Plan
March 2008
Task Force Review of Business Plan Complete
March 2008
Begin Developing Draft JPA Agreement
March 2008
Begin Developing Draft Implementation Plan
March 2008
Public Workshops and Community Outreach
March 2008 —
November 2008
City and County Ordinances
April 2008 —
November 2008
Approve and Execute JPA Agreement
December 2008
Issue Supplier Request for Bids and Select Seller
+30 Days
Approve Implementation Plan
+120 Days
Approve Program Agreement 1
+120 Days
File Implementation Plan with CPUC
-x-120 Days
Final Evaluation upon CPUC Certification of filed
+180 Days
Implementation Plan
Final Go/No Go Decision by Marin Clean Energy
+200 Days
File Registration Package with CPUC
+230 Days
Resolve Outstanding Issues
+240 Days
Execute Supplier/Vendor Contracts
+260 Days
Staffing and Startup Activities
+270 Days
Finalize Initial Rates
+270 Days
60 Day Notice
+270 Days
Go live phase 1
+330 Days
Page 65 of 204
17 April 2008
,F , — rgazuz 1011a�n
This section outlines a proposed organizational plan for Marin's CCA program, including
proposed governance principles for a new joint powers agency that would administer the
program. This section defines the necessary agreements and describes how the program would
be governed, managed, and staffed.
Organizational Overview
Pursuant to AB 117, a CCA may be a city, a county, a city and county, or a combination of cities
and counties that have elected to jointly implement a CCA program through formation of a joint
powers agency ('IPA"). The geographic boundaries of participating cities and/or counties need
not be contiguous. The proposed governance structure for the program is formation of a new
JPA whose Board of Directors would have primary responsibility for managing all aspects of a
common CCA program for the County of Marin, California (County) as well as the eleven cities
within the geographic boundaries of the County. According to the implementation timeline
presented in Chapter 1, a deadline of December 31, 2008 has been imposed for the County of
Marin as well as each of the eleven cities to vote on joining the JPA (and pass a related
ordinance in accordance with state law). For purposes of this business plan, the new JPA will
be referred to as the Marin Clean Energy Joint Powers Authority or simply "Marin Clean
Energy" or "MCE".
As proposed, the Program would be governed by MCE's Board of Directors (Board), appointed
by the Members. MCE would be a joint exercise of powers agency formed under California
law. The County of Marin and each city that has elected to offer the Program to its constituents
would become a Member of MCE. Marin Clean Energy would be the CCA entity that would
register with the CPUC, and it would be responsible for implementing and managing the
program pursuant to the Joint Powers Agreement. The Program would be operated under the
direction of an Executive Director appointed by the Board of Directors. The Executive Director
would report to MCE's Board of Directors comprised of one representative from each
participating Member of MCE. Those who will be 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 Councils
(one representative will be selected from each of the eleven City Councils) of the eleven member
cities. Representatives serving on the Board may be provided with a periodic stipend ($100 per
representative per month, for example) as part of their participation in this governing body.
The Board may adjust or discontinue the payment of such stipends at its discretion.
The Board of Director's primary duties would be to establish program policies, set rates and
provide policy direction to the Executive Director, 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 within MCE.
Page 66 of 204
7.8 April 2008
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 Executive Director could be an employee of MCE, an individual under contract with MCE,
a corporation, or any other person so designated by the Board. The Board would be responsible
for evaluating the Executive Director's performance and is ultimately responsible for hiring and
terminating the Executive Director.
The Board would also establish a Chairman and other officers from among its membership and
may establish an Executive Committee and other committees and sub -committees as needed to
address issues that require greater expertise in particular areas (e.g., finance or contracts). MCE
will establish an "Energy Commission" formed of Board -selected designees. The Energy
Commission will have responsibility for evaluating various issues that may affect MCE and its
customers, including rate setting, and will provide analytical support and recommendations to
the Board in these regards. The following chapter contains proposed elements of a JPA
agreement. Once the principles are agreed to by representatives of the county and cities, a JPA
agreement that defines the terms and conditions by which MCE will be governed would be
developed by qualified legal counsel.
The Executive Director would • have responsibilities over the functional areas of Finance,
Regulatory Affairs, and Operations. It is recommended that operations would be conducted
utilizing 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, should be performed initially by experienced third -party
contractors. The Program organizational chart showing relationships among the Board of
Directors, the Executive Director and the functional areas is shown in the following figure.
19 PAprrii 62oosf 204
P
rrogram Organization
r I Board of Directors
I Energy Commission �' l I !! Legal
111 ` Executive Director
1
I Finance Regulatory I Operations
Credit I
Financial Planning
--i Controller J
1 Resource Planning
--{ Portfolio Operations I
Rates
Account Services I
Energy Efficiency
Governance
Marin Clean Energy would have a Board of Directors consisting of one representative from each
of the Members. As previously noted, those who will be eligible to serve as representatives on
the Board will be elected officials from the then -current County Board of Supervisors and the
City Councils of the eleven member cities. The Board would meet at regular intervals to
provide the overall management and guidance for MCE. All Board meetings would be public
and held in accordance with the Ralph M. Brown Act.
Decisions by MCE would take place under voting procedures defined in the JPA Agreement.
All votes on a particular matter are subject to a two-tier approval process: first, any decision
must be approved by a simple majority of the Directors at, the Governing Board meeting;
second, assuming the first requirement is reached, those Directors voting in the affirmative
must constitute over 50- percent of a weighted voting percentage comprised of equal treatment
of each Member's electricity requirements (expressed as a ratio of each Member's electricity
requirements divided by total energy requirements of the Program) and a pro rata percentage
of total membership. That is, one-half of the combined vote is based upon the total number of
Members (i.e., 12 Members .each receive 4.17 percent [501/o/12]) and one-half of the combined
vote is based upon annual electric usage. The following table is illustrative of the proposed
voting percentages for the second tier vote.
20 P Agril 2008 204
P
Voting Percentages for the Second Tier Vote
An alternative second tier voting structure would emphasize number of customer accounts as
opposed to electricity requirements. In this case, the first tier vote, which must achieve simple
majority approval, does not change. However, ui the alternative second tier voting structure,
those Directors voting in the affirmative must constitute over 50 percent of a weighted voting
percentage comprised of equal treatment of each Member's customer account total (expressed
as a ratio of each Member's customer account total divided by the total number of customer
accounts within the Program) and a pro rata percentage of total membership. That is, one-half
of the combined vote is based upon the total number of Members (i.e., 12 Members each receive
4.17 percent [50%/12]) and one-half of the combined vote is based upon number of customer
accounts. The following table illustrates the proposed alternative voting percentages for the
second tier vote.
zx Page 69 of 204
April
Estimated Percent
Load Voting
Pro Rata
Total Voting
of Total Program
Percentage
Percentage
Percentage
Member
Load
(50%)
(50%)
(Tier 2)
Belvedere
0.79%
0.40%
4.17%
4.57%
Corte Madera
5.70%
2.85%
4.17%
7.02%
Fairfax
1.78%
0.89%
4.17%
5.06%
Larkspur
4.79%
2.40%
4.17%
6.57%
Marin County
25.05%
12.52%
4.17%
16.69%
M&ll Valley
4.88%
2.44%
4.17%
6.61%
Novato
20.20%
10.10%
4.17%
14.27%
Ross
1.00%
0.50%
4.17%
4.67%
San Anselmo
3.60%
1.80%
4.17%
5.97%
San Rafael
25.04%
12.52%
4.17%
16.69%
Sausalito
3.94%
1.97%
4.17%
6.14%
Tiburon
3.22%
1.61%
4.17%
5.78%
100%
50.0%
50.0%
100.00%
An alternative second tier voting structure would emphasize number of customer accounts as
opposed to electricity requirements. In this case, the first tier vote, which must achieve simple
majority approval, does not change. However, ui the alternative second tier voting structure,
those Directors voting in the affirmative must constitute over 50 percent of a weighted voting
percentage comprised of equal treatment of each Member's customer account total (expressed
as a ratio of each Member's customer account total divided by the total number of customer
accounts within the Program) and a pro rata percentage of total membership. That is, one-half
of the combined vote is based upon the total number of Members (i.e., 12 Members each receive
4.17 percent [50%/12]) and one-half of the combined vote is based upon number of customer
accounts. The following table illustrates the proposed alternative voting percentages for the
second tier vote.
zx Page 69 of 204
April
Alternative Voting Percentages for the Second Tier Vote
Estimated Percent
of Total Program
Member
Accounts
Belvedere
0.95%
Corte Madera
3.87%
Fairfax
3.07%
Larkspur
5.48%
Marin County
24.96%
Mill Valley
5.60%
Novato
19.20%
Ross
0.80%
San Anselmo
4.94%
San Rafael
22.93%
Sausalito
4.35%
Tiburon
3.86%
6.97%
100%
Account -Based
Pro Rata
Total Voting
Voting Percentage
Percentage
Percentage
(50%)
(50%)
(Tier 2)
0.47%
4.17%
4.64%
1.94%,
4.17%
6.11%
1.53%
4.17%
5.70%
2.74%
4.17%
6.91%
12.48%
4.17%
16.65%
2.80%
4.17%
6.97%
9.60%
4.17%
13.77%
0.40%
4.170/6
4.57%
2.47%
4.17%
6.64%
11.46%
4.17%
15.63%
2.17%
4.17%
6.34%
1.93%
4.17%
6.10%
50.0%
50.0%
100.00%
Officers
MCE would have 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, MCE would have a
Board Clerk and Auditor; neither of which will be members of the Board of Directors. The JPA
Agreement will provide further details on each of these positions.
Committees
MCE may elect to have additional committees or working groups to address various topics.
Potential committees include: Resource Committee, Fm* ance/Budget/Audit Committee,
Legal/Regulatory Committee, and Risk Management Committee. In addition to these potential
committees, MCE would form an appointed Energy Commission, which will be comprised of
Board designees from the Member communities. Appointments will be made based on various
skill sets and expertise that will be useful in evaluating matters affecting MCE and its
customers, specifically issues related to rate setting and other technical matters. The Energy
Commission will provide the Board with recommendations *and related analysis to support
policy -level decisions of the Board. Any additional committees and their functions would be
determined by the Board of Directors at the time each committee is created.
Addition/Termination of Participation
The proposed principles for a JPA Agreement provide for the addition of new participants
subject to the affirmative vote of MCE's Board of Directors pursuant to the voting structure
described above. The Board would determine the specific terms and conditions under which a
new Member could be admitted; for example, a new Member might be subject to a buy -down
fee for costs incurred by the original Members in establishing the Program.
22 PIrrii 2008 204
A JPA Member would be able to withdraw itself from the JPA subject to the specific terms and
conditions ultimately contained in the JPA Agreement. As proposed, withdrawal of individual
Members may occur upon 60 days written notice prior to the expiration of each fiscal year
(July 1). The Members withdrawal would then become effective one full fiscal year later, an
effective 14 -month notice requirement. The withdrawing party would also be subject to all
reasonable ongoing costs incurred by MCE on behalf of that entity. In this case, a vote of the
Board would not be required to affect Member withdrawal. Furthermore, the municipal load of
a Member withdrawing from the JPA would no longer be served by MCE, however, the non -
municipal accounts (such as residential, commercial and industrial accounts) would remain
customers of MCE and would continue to receive electricity procured by MCE on their behalf.
Because these non -municipal accounts would remain customers of MCE, the withdrawing
Member would continue to provide a Board representative from among its elected officials to
ensure that the interests of its constituents are represented during policy-making decisions of
the Board.
Conversely, if a Member desired to remove its future non -municipal accounts from MCE
service while retaining service for its municipal accounts, Board approval based on either of the
aforementioned two-tiered voting structures would be required. In this instance, any existing
non -municipal accounts would continue to receive electric service from MCE; only future non -
municipal accounts would be affected. Only in the event that the JPA agrees to disband would
the requirement of Board representation by all Members cease.
Termination of Marin Clean Energy
The proposed principles for a JPA Agreement include provisions addressing termination of
Marin Clean Energy. As proposed, termination of MCE would only occur after a majority of the
Member's governing bodies (County Board of Supervisors and/or City Councils) adopt a
termination ordinance or resolution and provide adequate notice to MCE (such as 90 days).
Following such notice, MCE would vote on its termination subject to a two-tiered vote, as
previously described. 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. In
recognition of this possibility, all contracts executed by the Board will include terms and
conditions addressing the resolution of any remaining contractual obligations of the Board
(such as contract buyouts, termination payments, contractual assignments, etc.). Termination of
MCE is also addressed in Chapter 8, Program Termination.
Agreements Overview
There are two principal agreements that would govern MCE and 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 would create MCE and delineate a broad set of powers related to the study,
promotion, development, and conduct of electricity -related projects and programs. It is
23 PAaP RA" 204
anticipated that MCE would have broad authorities and powers, but a very limited role without
implementing agreements ("program agreements") to carryout specific programs. This
structure is intended to provide flexibility for MCE to undertake other programs in the future
that may be unrelated to CCA on behalf of all or a subset of MCE's Members. However, 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 effected Member. In these instances, 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 each of the
Member's governing bodies (County Board of Supervisors and/or City Councils). Following
such approval, MCE would vote on prospective amendments subject to a two-tiered vote, as
previously described.
The first program agreement or PA -1, discussed in greater detail below, would provide for the
development, implementation and operation of a. CCA Program. At MCE's Members'
discretion, future program agreements could provide for other energy related programs. The
JPA Agreement specifies the governance provisions of MCE, which is discussed in greater detail
below.
Program Agreement No.1
PA -1 would outline the framework for the CCA Program, and transfer the participating
Members' authority under AB 117 to MCE. Approval of PA -1 by a participant would authorize
the initiation of the CCA Program for its jurisdiction, subject to a commencement notice to be
made by the JPA Board. It is anticipated that the county and cities would consider approval of
PA -1 after proposals have been received in response to MCE's supplier selection process and
the economics of the Program have been confirmed.
Agency Operations
Marin Clean Energy would conduct program operations through its own internal staff and
through contracting for services with third parties. MCE would have its own General Counsel
to manage its legal affairs. MCE's Executive Director will have responsibility for day-to-day
operations of the Program. To assist the Executive Director, MCE will hire a full-time
Administrative Assistant, who will also serve as Board Clerk, as well as a full-time Policy
Analyst to provide analytical support and regulatory review.
Major MCE functions that will be performed and managed by the Executive Director are
summarized below.
Resource Planning
Marin Clean Energy would be charged with developing both short (one and two-year) and
long-term resource plans for the program. The Executive Director would manage staff and
contractors to develop the resource plan under the guidance provided by the Board and in
24 PqAgeJZ20pJ 204
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. MCE'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. A preliminary long-term resource plan is contained in Chapter 3. It is
anticipated that such plans would 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.
Sclieduling Coordination — scheduling and settling electric supply transactions with the
CAISO.
MCE will initially contract with an experienced and financially sound third party to perform
most of the portfolio operation requirements for the CCA Program. This will include the
procurement of energy and ancillary services, scheduling coordinator services, and day -ahead
and real-time trading. A description of the planned selection process for the third parties that
will be supplying electricity under the program is contained in Chapter 6.
As MCE-gains experience and begins internalizing more of the functions initially provided by
third parties, it will be important for MCE to approve and adopt a set of Program Controls that
would serve as the risk management tools for the Executive Director 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 risks, pursuant to the terms and conditions of the electric supply
agreement.
25
Page 738 2 08of 204
Energy Efficiency
A key focus of the CCA Program will be the development and implementation of an energy
efficiency program for MCE's Members. The Executive Director will be responsible for further
development of this Program. To assist the Executive Director in this regard, MCE will hire a
full-time Energy Efficiency Program Manager and three full-time Energy Efficiency Project
Managers to administer the energy efficiency program, 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, MCE will
continue enhancing its Energy Efficiency program to achieve desired goals and objectives of the
program. Energy efficiency program potential is discussed in Chapter 3.
MCE would administer energy efficiency, demand response programs, and distributed (solar)
generation that can be used as cost-effective alternatives to procurement of supply-side
resources. MCE would 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, potentially through 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 MCE's customers.
Rate Setting
The Board of Directors would have the ultimate responsibility for setting the electric generation
rates for the Program's customers. The Executive Director in cooperation with Marin Clean
Energy's Energy Commission would be responsible for developing proposed rates and options
for the Board to consider before the finalization of the actual rates, subject to the notice
requirements and process described in Chapter 5 ("Ratesetting and Program Terms and
Conditions"). The final approved rates must, at a minimum, meet the annual revenue
requirement developed by the Executive Director, including any reserves or coverage
requirements set fords 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 Executive Director will be responsible for managing the financial affairs of MCE, including
the development of an annual budget and revenue requirement; managing and maintaining
cash flow requirements; potential bridge loans and other financial tools; and a large volume of
billing settlements. The Executive Director 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
26 P� r i172U0 204
be provided for in the electric supply agreement. The Finance function establishes credit
policies that the program must follow.
It is planned that the retail settlements (customer billing) would be contracted out to an
organization with the necessary infrastructure and capability to handle approximately 111,000
accounts during Phase 3 implementation in January 2011. 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 Executive Director will be responsible for the Customer Services function.
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. MCE would initially contract
with a third party, which has demonstrated the necessary experience and administers
appropriate computer systems (customer information system), to perform the customer account
and billing services functions.
MCE would conduct the general 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 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 MCE and its Members. MCE 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 Executive Director's Policy Analyst.
27 PApni 2UU8 204
MCE would retain legal services, as necessary, to administer MCE, review contracts, and
provide overall legal support to the activities of MCE.
Roles and Functions
Marin Clean Energy Board would perform the functions inherent in its policy-making,
management and planning roles. MCE would also be the public face of the program and have a
direct role in marketing, communications and customer service. As previously noted, other
highly specialized functions, such as energy supply and account management, would be
contracted out to third parties with sufficient experience, technical and financial capabilities.
The functions that would initially be performed by MCE's Board of Directors, the Executive
Director and third parties are specified below:
Organization
Roles/Functions/Activities
MCE Board of Directors
Executive/Policy/Legal
Executive Director
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
- Supply-side/Demand side portfolio planning
Contract Management — RFP/RFQ
Customer Service
- Account representatives
- Energy efficiency program management
Energy Supplier
Supply Operations
- Procurement
- Scheduling coordination
- Settlements (ISO/Wholesale)
- Short-term load forecasting
Customer Accbunt Services ProviderlData
Account Management (Customer Information System)
Manager
- Customer switching
- New customer processing
- Data exchange (EDI)
- Payment processing (AR/AP)
- Billing and retail settlements
- Call center
MCH would enter into two key contracts with third parties- to provide the day-to-day
operational functions necessaiy to procure electricity and manage customer account data. The
28 P - H 204
first of these contracts is with the Program's energy supplier to perform the Supply Operations.
The second key contract is with a data management provider to perform the Account
Management functions. MCE would select the contractors for these key roles through a
competitive solicitation. Information on the recommended solicitation process to select
qualified potential service providers is contained in Chapter 6.
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 Executive Director would have discretion
whether to internally staff these required functions or to contract for these services.
The following table illustrates the expectations for start-up, near-term (two to five years), and
long-term anticipated staffing roles.
29 PRM jJ09f 204
Function
Program Governance
Program Management
Outreach
Customer Service
Key Account Management
Regulatory
Legal
Finance
Rates: Approve
Develop
Resource Planning
Energy Efficiency
Resource Development
Portfolio Operations
Scheduling Coordinator
Data Management
Expectations for Staffing Roles
Start -Up
MCE Board
MCE ED
MCE ED
MCE ED
MCE ED
Thud Party
(MCE ED and
Regulatory Analyst
support)
MCE ED
MCE ED
MCE Board
MCE ED (third Party
support)
Third Party
(MCE ED support)
Thud Party
MCE ED (thud party
support)
Third Party
Third Party
Third Party
Near -Term
(2 to 5 Years)
MCE Board
MCE ED
_^MCE ED
MCE ED
MCE ED
MCE ED
(Regulatory Analyst
support)
MCE ED
MCE ED
MCE Board
MCE ED (third Party
support)
MCE ED (third party
support)
Third Party
(MCE ED and
Program Energy
Efficiency Staff
support)
MCE ED (third party
support)
Third Party
(MCE ED support)
Third Party
Thud Party
Long -Term
MCE Board
MCE ED
MCE ED
MCE ED
MCE ED
MCE ED
(Regulatory Analyst
support)
MCE ED
MCE ED
MCE Board
MCE ED
MCE ED
MCE ED (Program.
Energy Efficiency
Staff)
MCE ED
MCE ED
Thud Party
(potentially MCE ED)
Third Party
(potentially MCE ED)
Staff would 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 pre -startup period, minimal staffing requirements would include
an Executive Director, an Assistant to the Executive Director, a Policy Analyst and a Sales and
Marketing Manager (4 full time equivalent positions). MCE anticipates hiring the Executive
Director, Assistant to the Executive Director, Policy Analyst and Marketing Manager as its
direct staff but may choose to fill all other necessary positions with staff and/or contractors at
the discretion of the Executive Director and MCE's Board. Following these initial staffing
efforts, additional staff and/or contractors would 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 customers are enrolled.
Phase 2 contains the key commercial and industrial customer segments, the largest of which
would have assigned customer account representatives.
30 PaqpxjT§C@A 204
The following table provides an estimate of the appropriate staff additions (internal staff or
equivalent contracted functions) that MCE would require for 2009-2010 to implement and
operate the CCA Program. Actual staff will be dependent upon several factors, including the
ability to recruit and hire qualified staff and personnel policies ultimately established by the
Executive Director and the Board of Directors.
31 PAan J6O�f 204
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The following table shows the staffing plan for Marin Clean Energy at initial full-scale
operational levels (Phase 3). Customer service for the mass market residential and small
commercial customers will be provided by the Program's third party customer account services
provider.
Staffing Plan for Marin Clean Energy
Community Choice Aggregation Program
Position
Management
Executive Director
Policy Analyst
Administrative Assistant
Finance and Rates
Manager
Rates Analyst
Accounting/Billing Analyst
Sales and Marketing
Manager
Account Representative
Communications Specialist
Administrative Assistant
Energy Efficiency
Manager
Project Manager
Regulatory
Manager
Regulatory Analyst
Information Technology
IT Specialist
Human Resources
HR Specialist
Total Staffing
33
Staff (Full Time
Equivalents)
1.0
1.0
1.0
1.0
1.0
1.0
1.0
4.0
1.0
1.0
1.0
3.0
1.0
1.0
1.0
0.5
20.5
Page 81 of 204
Aprn12008
aiWI I II li I I I 0) I i i°' �Y i I� I I I''
+ ri
Introduction
This Chapter describes MCE's proposed ten-year 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 .(2014), this significant commitment to renewable
resources is projected to result u1 MCE meeting over 80 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 will 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 deployment of approximately 13 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 will be supplied from efficient, low emission
conventional generating resources.
➢ Increase the renewable content of the Light Green Tariff to over 50 percent and the
average renewable energy supplies of the program to over 80 percent by 2014, based on
projected levels of participation in MCE's two available generation tariffs.
➢ Continue increasing renewable energy supplies beyond 2014 based on resource
availability and economic goals of the program. -
➢ Develop partiership(s)' with experienced public power developer(s) to facilitate
development of Program-owned/controlled renewable generating capacity.
➢ Invest in 200 MW of new renewable generating capacity to be online by 2014.
➢ Achieve .incremental reductions in greenhouse gas emissions ranging from 302,330 to
534,369 tons per year, as much as 17 percent of the Marin Communities' total GHG
emissions.
MCE would be responsible to comply with regulatory rules applicable to California load.
serving entities. MCE would arrange for the scheduling of sufficient electric supplies to meet
the hour -by -hour demands of its customers. MCE would also need to adhere to capacity
reserve requirements established by the CPUC and the CAISO designed to address uncertainty
in load forecasts and potential supply disruptions caused by generator outages and/or
transmission contingencies. These rules also ensure that physical generation capacitV is in lace'
34 P rj&jsf 204
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, MCE would be responsible for ensuring
that its resource mix contains sufficient production from renewable energy resources needed to
comply with the statewide renewable portfolio standards (20 percent renewable energy supply
by 2010). The resource plan would meet or exceed all of the applicable regulatory requirements
related to resource adequacy and the renewable portfolio standard.
Program Phase -In
Marin Clean Energy would -phase-in its CCA Program over the course of three stages:
1. Participant (Municipal) Accounts;
2. Commercial and Industrial Accounts; and
3. All Remaining Accounts.
This approach provides MCE 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 111,000 plus customer base. This approach also provides for MCE
and its primary contractors to address all system requirements (billing, collections, payments)
under a phase-in approach to minimize potential exposure to uncertainty and financial risk by
introducing the Program on a small, highly manageable scale prior to expanding the Program in
deliberate, incremental stages.
Phase I —Participant Accounts
Phase 1 of the Program would be targeted to begin on January 1, 2010; subject to the following
conditions being met. CPUC approval of MCE's Implementation Plan; final approval of the
Program by the Parties (via the JPA Agreement and approval of Program Agreement No. 1);
completion of all necessary implementing agreements including those with suppliers, the
investor-owned utilities, and potentially others; and execution of MCE's start-up staffing plan.
Phase 1 will consist solely of the direct electric accounts of the Program Participants' (Member
cines and Marin County) loads. Under this approach it is expected that the opt -out rate for
accounts (and load) for the Marin Communities will be zero percent. Of the participating
accounts, it is assumed that all accounts will participate in MCE's 100 percent Green Tariff. This
would result in approximately 600 accounts representing a load of 21 GWh annually, all of
which would be served with 100 percent renewable energy supplies. Energy supply for Phase 1
would be met via agreements entered into by MCE with third -party energy service providers.
Phase 2 — Large Accounts
Phase 2 of the Program is targeted to begin approximately five months after Phase 1; however,
MCE's Board of Directors would have the authority to potentially adjust this starting date
depending upon the performance of the Program under Phase 1. The intent is to ensure that.the
Program is operating properly, including ' proper procurement and delivery of electricity, as
well as billing and receivables from the Member Participants' own loads prior to rolling the
Program out to commercial customers.
35 Page 83 gof 204
A
Pn
Phase 2 of the Program is focused on medium and large electric users; those accounts that
typically have demands in excess of 50 kW, in addition to the customers already included in
Phase 18 For modeling purposes it is assumed that 100 percent of direct access customers and
10 percent of bundled service customers will opt -out of the CCA Program entirely and that the
following tariff -specific participation rates will apply to remaining customers included in Phase
2, subject to marketing efforts of the program: .
➢ Medium Commercial: 70 ' percerit participation in 100 percent Green; 30 percent
participation in Light Green Tariff;
➢ Large Commercial: 5 percent participation in 100 percent Green; 95 percent participation
in Light Green Tariff;
➢ Industrial: 5 percent participation in 100 percent Green; 95 percent participation in Light
Green Tariff; and
➢ Agricultural: 20 percent participation in 100 percent Green; 80 percent participation in
Light Green Tariff.
This provides for an estimate incremental Phase 2 customer class of approximately 1,200, with
an annual load of 364 GWh.
Phase 3 —All Accounts
The final Phase (Phase 3) provides for all electric customers within the service territory of
MCE's Participating Members to have the option of participating in the CCA Program. Within
Phase 3, it is expected that all direct access customers and 10 percent of eligible bundled service
customers will opt out of the CCA program. Of the 90 percent of Phase 3 customers that remain
with the program, it is expected that 70 percent will elect to participate in the 100 percent Green
Tariff. The remaining 30 percent of participating Phase 3 customers are assumed to participate
in the Light Green Tariff due to cost sensitivity. This represents a significant increase in the
number of customers and the overall energy requirements for the program as the incremental
growth for Phase 3 is approximately 109,000 customers and 837 annual GWh.
The assumed start date for Phase 3 of the Program is eight months after the commencement of
Phase 2, again subject to the final review and approval of MCE's Board of Directors.
Resource Platt Overview
The criteria used to guide development of the proposed resource plan includes the following.
➢ Environmental responsibility and commitment to renewable resources
➢ Price/Rate Stability
➢ Reliability and maintenance of adequate reserves
➢ Cost effectiveness
To meet these objectives and the applicable regulatory requirements, MCE's resource plan
should include a diverse miz of 'generation, power purchases, renewable energy, new energy
efficiency programs, demand response, and distributed generation. A diversified resource plan
8 Phase 2 would include the A-10, E-19 and E-20 cust36 er classes. PRgeti8 0008 204
P
minimizes risk and volatility that can occur from over -reliance on a single resource type or fuel
source. 'The ultimate goal of Marin Clean Energy's resource plan is to maximize use of
renewable resources subject to economic and operational constraints. The result is a resource
plan that would source over 80 percent of the resource mix from renewable resources by 2014.
The planned resource mix is initially comprised of power purchases from third party electric
suppliers and, in the longer-term, also includes renewable generation assets owned and/or
controlled by MCE.
MCE's renewable generation, which would be directly owned by MCE or controlled under
long4erm power purchase agreement with a proven public power developer, would provide a
portion of MCE'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. As discussed in Chapter 4, the amount of
generation proposed to be financed by MCE will be a influenced by security requirements
necessary for issuance of revenue bonds needed to finance the project. Once the Program
demonstrates it can operate successfully for a number of years, additional generation
investments would be expected. Additional refinement of security requirements in consultation
with the Marin Communities' financial advisors, investment bankers, attorneys, and potentially
with customer input may increase the assumed debt carrying capacity of the Program and
enable greater investment than shown in this plan.
As an alternative to direct investment, MCE may partner 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 within Marin County or at an
alternative location within the Greater Bay. Area. Such an arrangement could be structured to
virtually eliminate 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 MCE as it works to achieve increasing levels of
renewable energy supply to its customers.
MCE'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, MCE would 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 13 MW of distributed solar by 2019.
Beguiling on January 1, 2007, all owners of distributed solar capacity that applied for state-
sponsored rebates were obligated to participate in their respective utility's time -of -use rate
tariff. The significantly higher rates in these tariffs have discouraged distributed solar
installations in the first quarter of 2007 relative to the same time period in 2006. In fact, on May
8, 2007 the Los Angeles Times reported a 78 percent reduction.in solar rebate requests during
this three month period, year -over -year, which has been substantially attributed to the time -of -
use rate mandate. Public Utilities Code, Section 2851(a)(4) specifies that time -of -use rate
structures must create "the maximum incentive for ratepayers to install solar energy systems."
37 ,,V3 gOf 204
On May 16, 2007, President Peevey of the CPUC issued a Proposed Decision in Rulemaking 06-
03-004 staying the time -of -use rate mandate until such time that the Commission is able to
develop anew time -of -use rate tariff that meets the expressed requirement of Section -2851.
Unlike customers of the investor-owned.utilities who own distributed solar capacity, customers
of MCE will not be constrained by PG&E's time -of -use rate structures, as MCE may design rates
at the discretion of its Board of Directors. MCE would be free to maximize solar installations
without a for-profit entity's concern that reducing customer net energy consumption would
detract from shareholder profits. With this in mind, MCE may develop unique rate schedules
that create specific. incentives for owners of distributed renewable capacity, ensurblg that
distributed renewable capacity additions continue to occur throughout its jurisdiction. Through
the creative development of rate structures that encourage the installation of distributed
renewable resources and support ongoing operation of these systems, the Program can ensure
high levels of distributed renewable installation as a form of energy efficiency. Over time, MCE
will be able to modify these rate structures, based on customer behavior, to achieve desired
levels of distributed renewable capacity.
MCE's proposed resource plan for the years 2010 through 2019 is summarized in the following
table:
Marin Clean Energy
Energy Balance
(GWM
2010 to 2019
Supply Requirements
The starting point for Marin Clean Energy'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 program's "load profile". As a basis for the customer forecast, .the Marin
Communities requested historic- load data for each of their respective jurisdictions. This data
was organized and analyzed, becoming the starting point from which an annual load forecast
was developed. An annual growth rate of 0.5 percent, consistent with Marin's population
-growth rate, was applied .to this data, resulting in a long-term annual load forecast for the
38 P A�rii_;g8 204
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Marin Demand (GWh)
Retail Demand
-267
-1,234
-1,240
-1,246
-11252
-1,259
-1,265
-1,271
-1,278
-1,284
Distributed Generation
6
8
10
12
13
15
17
18
19
19
Energy EEfidenry
0
4
lI
15
15
15
IS
15
15
16
Losses and UFE
-18
-86
-85
-85
-86
-86
-86
-87
-87
-87
Total Demand
-280
-1,308
-1,304
-1,305
-1,309
-1,314
-1,319
-1,325
-1,330
-1,337
Marin Supply (GW
Renewable Resourm
Generation
0
0
0
0
794
794
794
794
794
794
Power Purchase Contracts
145
858
855
856
191
195
198
203
206
212
Total Renewable Resources
145
858
855
856
985
989
992
997
1,001
1,006
Conventional Resnurcesi
Generation
0
0
0
0
0
0
0
D
0
0
Power Purchase Contracts
135
450
449
449
324
325
326
328
329
331
Total Conventional Resources
135
450
449
449
324
325
326
328
329
331
Total Supply
280
1,308
1,304
1,305
1,309
1,314
1,319
1,325
1,330
1,3V-
,337-Energy
EnergyOpen Position (G Wh)
0
0
0
0
D
0
0
D
0
0
Supply Requirements
The starting point for Marin Clean Energy'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 program's "load profile". As a basis for the customer forecast, .the Marin
Communities requested historic- load data for each of their respective jurisdictions. This data
was organized and analyzed, becoming the starting point from which an annual load forecast
was developed. An annual growth rate of 0.5 percent, consistent with Marin's population
-growth rate, was applied .to this data, resulting in a long-term annual load forecast for the
38 P A�rii_;g8 204
county and cities. From the annual load forecast, hourly demands were calculated based on
historic usage profiles for the county and cities. The electric sales forecast and load profile will
be affected by MCE'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 MCE's contracted energy supplier will bear risks associated with
deviations from the electric sales forecast during the initial operating period (through 2013). It
will be the obligation of this energy supplier to appropriately reflect these risks in the full
requirements energy price. MCE'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.
MCE anticipates an overall customer participation rate of 100 percent during Phase 1, when
service is being offered to the service accounts that are affiliated with MCE's participating
members (municipal accounts). It is assumed that each of these service accounts will participate
in MCE's 100 percent Green Tariff. Participation rates are expected to be 90 percent of bundled
service customers and 0 percent of direct access customers during Phases 2 through 3 based on
experience with similar opt -out style municipal aggregation programs developed in other
states; these have ranged from 5 percent in Massachusetts to 10 percent in Ohio. The
participation rate is not expected to vary significantly among customer classes, in part due to
the fact that MCE 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 should also
be supported by MCE'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 MCE's public outreach efforts continue to
develop and experience is gained by other California CCA programs.
Customer Forecast
Once customers enroll in each implementation phase, they will be switched over to service by
MCE on their regularly scheduled meter read date over an approximately thirty day period.
Approximately 19 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 double to about
40 accounts per day. However, during Phase 3, MCE's customer account systems must be
capable of processing customer enrollments of over 3,600 accounts per day. The number of
accounts served by MCE at the end of each phase is shown in the table below.
39 F� , MOV 204
Marin Clean Energy
Enrolled Retail Service Accounts
Phase -In Period (End of Month)
Jan -10 May -10 Jan -11
Marin Customers
2010
2011
2012
Residential
2
2
97,443
Small Commercial
341
339
11,704
Medium Commercial
32
1,062
1,067
Large Commercial
3
156
157
Industrial.
-
11
11
Street Lighting & Traffic
186
186
542
Ag & Pump.
1
1
177
Total
565
1,757
111,101
Customer Additions
565
1,192
109,344
The forecast of service accounts (customers) served by MCE for each of the next ten years is
shown in the following table:
12,120
12,180
Medium Commercial
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 280 GWh in 2010 to just over 1,300 GWh at full roll-out in 2011- Annual energy
requirements are shown below.
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Marin Customers
(GW13)
Residential
2
97,443
97,930
98,420
98,912
99,406
99,903
100,403
100,905
101,409
Small Commercial
341
11,704
11,762
11,821
11,880
11,940
11,999
12,059
12,120
12,180
Medium Commercial
1,062
1,067
1,D73
1,078
1,083
1,089
1,094
1,100
1,105
1,111
Large Commercial
156
157
158
159
159
'160
161
162
163
164
Industrial
11
11
11
11
11
11
11
11
12
12
Street Lighting k Traffic
186
542
545
548
550
553
556
559
561
564
Ag k Pump.
1
177
178
179
180
181
182
183
183
184
Total
1,759
111,107
711,657
112,215
112,776
113,340
113,907
114,476
115,049
115,624
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 280 GWh in 2010 to just over 1,300 GWh at full roll-out in 2011- Annual energy
requirements are shown below.
Marin Clean Energy
Energy Requirements
(GW13)
2010 to 2019
2010
2011
2012 2013 2014
2015
2016
2017 2018 2019
Marin Demand (GWh)
Retail Demand
267
1,234
1,240 1,246 1,252.
1,259
1,265
1271 1,278 1,284
Distributed Generation
-6
-8
-10 -12 -13
-15
-17
-18 -19 -19
Energy Efficiency
0
-4
-11 -15 -15
-15
-15
-15 -15 -16
Losses and OFF
18
86
85 85 86
86
86
87 87 87
Total Load Requirement
280
1,308
1,304 1,305 1,309
1,314
1,319
1,325 1,330 1,337
40
I -pg�� f 204
Capacity Requirements
The CPUC's resource adequacy standards applicable to MCE require a demonstration one year
in advance that MCE 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, MCE must demonstrate 100 percent of the peak load plus a minimum
15 percent reserve margin.
A portion of MCE's capacity requirements must be procured locally, from the Greater Bay area
as defined by the CAISO and antother portion must be procured from outside the Greater Bay
Area. MCE 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 MCE's forecasted peak
load. The formula is as follows:
MCE Local Capacity Requirement = [MCE Capacity Requirement/Total PG&E Service Area
Capacity Requirement]*Total Local Capacity Requirement in PG&E's Service Area
MCE must demonstrate compliance or request a waiver from the CPUC requirement as
provided for in cases where local capacity is not available. If necessary, MCE would be able to
request relief from the local procurement obligation with a demonstration that it has made
every commercially reasonable effort to contract for local capacity resources. A waiver request
would have to demonstrate that MCE actively sought products and either received bids with
prices in excess of an administratively determined local attribute price ($40 to $73 per kW -year)
or received no bids.
The waiver applies to Commission -imposed penalties only. If deficient, MCE would be
responsible for any applicable backstop procurement costs even if it received a waiver from
penalties. The CAISO would procure local capacity as a backstop and would charge a fee based
on its costs of procuring the capacity. For 2007, the backstop cost was approximately $73 per
kW -year.
MCE's first resource adequacy filing could take place as early as October 2009, according to the
schedule established by the CEC for evaluating statewide resource adequacy based on resource
plans filed by all load serving entities in the state. The forward resource adequacy
requirements for 2010 through 2012 are shown in the following tables:
41 P�a�l �6ogf 204
Marin Clean Energy Marin Clean Energy
Summer Peak Loads Forward Capacity and Reserve Requirements
(Mw) (Mw)
2010 to 2012 2010 to 2012
Month
2010
2011
2012
Month
2010
2011
2012
January
3
222
220
January
4
256
253
February
4
237
236
February
4
273
271
March
3
193
191
March
4
222
219
April
3
188
186
April
4
216
213
May
66
174
172
May
76
200
197
June
68
200
198
June
79
230
228
July
64
195
193
July
74
224
222
August
66
221
219
August
75
254
251
September
73
205
203
September
84
236
234
October
69
205
203
October
79
235
233
November
67
227
225
November
77
261
259
December
61
222
220
December
70
255
253
MCE's plan would ensure sufficient reserves are procured to meet its peak load at all times.
MCE'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 Marin Clean Energy's projected peak demand. MCE would need to work with the CPUC's
Energy Division and potentially staff at the California Energy Commission to obtain the data
necessary to calculate MCE's monthly local capacity requirement. A preliminary estimate of
MCE's annual local capacity requirement for the ten year planning period ranges from
approximately 32 to 102 MW as shown in the following table:
PG&C Planning Area System Peak (MAO
Total Capacity Requirement (1154.)
Authority Peak (MW)
Authority Share of Planning Area
Local Capacity Requirement -Greater Bay Area
Local Capacity Requirement -Other PG&E
Authority Local Capacity Requiremutt Greater Bay
Authority Local Capacity Requirement Other PG&E
Marin Clean Energy
2016
Marin Clean Energy
2018
2019
(MW)
23,921
24,232
24,547
2010 to 2019
25,189
2010
Capacity Requirements
2012
2013
22,425
2.;717
23,012
23,311
25,789
26,124
26,464
(Mw)
73
237
236
235
0.3%
D9%
0.9'X.
0.9%
4,896
2010 l0 2019
5,024
5,089
6,232
6,313
6,395
6,478
14
2010
2011
2012 2013
2014
2015
2016
7017
2018
2019
Demand (MW)
...----
---
57
Retail Demand
72
228
229 290
231
232
234
235
236
237
Distributed Gene-, tion
(4)
(5)
(6) (8)
(9)
(10)
(12)
(12)
(13)
(13)
Energy Efficiency
-
(1)
(2) (3)
(3)
(3)
(3)
(3)
(3)
(3)
Losses and LIFE
5
16
15 15
15
15
15
15
15
1s
Tota( Net Peak Demand
73
237
236 235
734
234
234
235
235
236
Reserve Requirement (%)
15%
15%
15% 15%
15%
15%
15%
15'X.
15%
15%
Capacity Reserve Requirement
1I
36
35 35
35
35
35
35
35
35
Capacity Requirement Induding Reserve
84
273
271 270
270
269
269
270
270
272
Local capacity requirements are a function of the PG&E area resource adequacy requirements
and Marin Clean Energy's projected peak demand. MCE would need to work with the CPUC's
Energy Division and potentially staff at the California Energy Commission to obtain the data
necessary to calculate MCE's monthly local capacity requirement. A preliminary estimate of
MCE's annual local capacity requirement for the ten year planning period ranges from
approximately 32 to 102 MW as shown in the following table:
PG&C Planning Area System Peak (MAO
Total Capacity Requirement (1154.)
Authority Peak (MW)
Authority Share of Planning Area
Local Capacity Requirement -Greater Bay Area
Local Capacity Requirement -Other PG&E
Authority Local Capacity Requiremutt Greater Bay
Authority Local Capacity Requirement Other PG&E
2014
Marin Clean Energy
2016
Local Capacity Requirements
2018
2019
(MW)
23,921
24,232
24,547
2010 to 2019
25,189
2010
2011
2012
2013
22,425
2.;717
23,012
23,311
25,789
26,124
26,464
26,808
73
237
236
235
0.3%
D9%
0.9'X.
0.9%
4,896
4,959
5,024
5,089
6,232
6,313
6,395
6,478
14
45
45
45
18
57
57
57
2014
2015
2016
2017
2018
2019
23,614
23,921
24,232
24,547
24,866
25,189
27,156
27509
27,867
78,229
28,596
28,966
234
234
274
235
235
236
0.9%
0.9%
0.8%
08%
0.8%
0.8%
5,155
5171
5,290
5,359
5,429
5,499
6,501
6,648
6,734
6,=
6,910
7,000
45
44
44
45
45
45
57
57
57
57
57
57
42
Pa
Ag ril 2008f 204
P
Renewable Portfolio Standards Energy Requirements
Basic RPS Requirements
As a CCA, Marin Clean Energy would be 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, MCE 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 MCE's renewable energy requirements, the
same standards for RPS compliance that are applicable to the distribution utilities are assumed
.to apply to MCE.
The Commission has so far 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.
Additional specifics of how CCAs, unregulated energy service providers and multi -
jurisdictional utilities are to comply with the RPS and how their compliance may be different in
some respects than the rules that are applicable to the distribution utilities are being addressed
in the ongoing CPUC proceeding, R.06-02-012. The rules ultimately adopted for CCAs may
provide greater flexibility than assumed in this plan, for instance, by allowing use of short-term
contracting or unbundled renewable energy certificates for RPS compliance. Future resource
plans should incorporate any changes in these assumptions that result from the Commission's
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
baseline, representing renewable generation needed to continue to satisfy obligations under the
RPS targets of previous utilities years, and the "Incremental Procurement Target" (IM), which
is at least 1 percent of the previous utilities 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 1PT 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. Flexible compliance does not currently extend the
20 percent by 2010 requirement. Noncompliance will result in penalties of 5 cents per kWh,
capped at $25 million per year.
Page
2008 f 204
43
Pr�
Marin Clean Energy's Renewable Portfolio Standards Requirement
Because Marin Clean Energy 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, the expected second year of the program, MCE must meet the
full 20 percent renewable standard (based on -2010 retail sales). MCE's annual RPS
requirements are shown in the table below.
Marin Clean Energy
RPS Requirements
(MVIH)
2010 to 2019
Marin Clean Energy's Renewable Energy Goals
Marin Clean Energy would target a 56 percent renewable energy percentage during the first
two phases of program operations, based on projected participation in the program's 100
percent Green and Light Green Tariffs, and would then further exceed the RPS as it builds
towards more than 80 percent by 2014. Beyond 2014, MCE intends to increase its procurement
of renewable energy supplies subject to economic and operational constraints. It is the long-
term goal of Marin Clean Energy to procure 100 percent of its energy supplies from renewable
sources: MCE would therefore significantly exceed the minimum RPS requirements as shown
below; provided that the competitive wholesale market provides qualified responses to MCE's
resource solicitations.
2010 2011
2012
2013
2014
2015
2016
2017
2018
2019
Retail Sales
261,264 1,222,384
1,719,080
1,219,581
1,2M,812
1,220,073
1,232,365
1,738,339
1,242,859
1,249,170
Baseline
- -
52,253
244,477
243,816
243,916
244,762
245,615
246,473
247,668
Incremental Procurement Target
- 52,753
192,224
(661)
100
846
$52
858
1,195
904
Annual Procurement Target
52,253
244,477
243,816
243,916
244,762
245,615
246,473
247,668
248,572
% of Current Year Retail Sales
4%
20%
20%
20%
20%
20%
20%
20%
20%
Marin Clean Energy's Renewable Energy Goals
Marin Clean Energy would target a 56 percent renewable energy percentage during the first
two phases of program operations, based on projected participation in the program's 100
percent Green and Light Green Tariffs, and would then further exceed the RPS as it builds
towards more than 80 percent by 2014. Beyond 2014, MCE intends to increase its procurement
of renewable energy supplies subject to economic and operational constraints. It is the long-
term goal of Marin Clean Energy to procure 100 percent of its energy supplies from renewable
sources: MCE would therefore significantly exceed the minimum RPS requirements as shown
below; provided that the competitive wholesale market provides qualified responses to MCE's
resource solicitations.
Resources
MCE would seek to maximize use of its own cost -based renewable generation resources in its
resource plan, subject to MCE's ability to finance or otherwise obtain an entitlement to such
projects. The ability to procure output from or invest capital in _generation resources financed
with tax-exempt debt is an important factor 'in MCE's ability to increase use of renewable
energy while offering rates that are competitive with PG&E. Power purchases from renewable
44 F April 20008 204
P
Marin Clean Energy
RPS Requirements and Program Renewable Energy Targets
(MWH)
2010 to 2019
2010
2011
2012 2013'
2014
2815
2016
2017
2016
2019
Retail Sales (MWh)
261,264
1,272.384
1,219,080 1,219,581 3,223,612
1,228,073
1,232,365
1,238339
1,242,859
1,249,170
Annual RPS Target (Minimum MWh)
-
52,753
244,477 243,816
243,916
244,762
245,61$
246,473
247,668
248,572
Program Target (%of Retail Sales)
56%
70%
70% 70%
81%
81%
81%
81%
8I%
81%
Program Renewable Target (MWW
145,048
857,657
055,339 855,691
985,243
988,676
994131
996,940
1,OOD,Sl9
1,0115,660
Surplus In Excess of RPS (MWh)
145,048
805,404
61D,862 611,875
741,529
743,914
746,517
750,467
754911
737,088
Annual Increase (MWh)
145,048
712,609
(7,318) 352
129,555
3,431
3,456
4,809
3,639
S,Om
Resources
MCE would seek to maximize use of its own cost -based renewable generation resources in its
resource plan, subject to MCE's ability to finance or otherwise obtain an entitlement to such
projects. The ability to procure output from or invest capital in _generation resources financed
with tax-exempt debt is an important factor 'in MCE's ability to increase use of renewable
energy while offering rates that are competitive with PG&E. Power purchases from renewable
44 F April 20008 204
P
and the cleanest non-renewable (natural gas-fired) resources would supply the remaining
majority of the resource mix. MCE's electric portfolio would be managed by a third party
electric supplier, at least during the initial implementation period. Tluough a power services
agreement, MCE would obtain full requirements electric service for MCE's retail customers,
including providing for all electric and ancillary services and the scheduling arrangements
necessary to provide delivered electricity to the retail customers' end use meters through 2013.
A subsequent power services agreement would provide for integration of MCE's renewable
generation or power purchase contracts; or alternatively, MCE may gain the expertise by that
time to manage the portfolio with internal staff.
Marin Clean Energy's resource plan anticipates the development of a diverse renewable
resource portfolio, which includes contributions from four commercially viable generating
sources with aggregated production characteristics that are consistent with the Marin load
profile:
➢ Wind — 30 percent (of renewable supply portfolio);
➢ Solar — 25 percent; and
➢ Biomass and/or Geothermal — 45 percent.
As part of its renewable resource portfolio, MCE plans to develop both a wind and biomass
generation resource within the PG&E service area planned to be online by 2014. The plan calls
for initial development of 200 MW of these resources to meet approximately 62 percent of
MCE's annual electricity requirements. It is likely that additional investment would be made
after several years of successful operating experience. Wind and biomass technologies were
selected for this plan due to the maturity of the respective technologies and the fact that wind
and biomass are generally the lowest cost renewable resources currently available. However,
other technologies such as solar and geothermal should also be investigated as the Program
moves forward. Approximately 18 percent of the total resource mix is anticipated to come from
power purchases from third party renewable energy developers. Non-renewable baseload,
peaking and shoulder load requirements would generally be met with power purchase
contracts for the balance of this planning horizon.
The planned resource mix for 2011 and 2017 are shown in the figures on the following page. It
is important to note that the portions of MCE's supply portfolio from renewable energy sources
should be considered "carbon free" for the purpose of comparison to a utility supply portfolio.
Page 93 of 204
45 April 2008
31
62°/
Marin Clean Energy 2011 Resource Mix
4
®Renewable Market Purchases
® Conventional Purchases
Marin Clean Energy 2017 Resource Mix
18%
Purchased Power
19%
M Renewable Market Purchases
® Conventional Purchases
❑ Renewable Generation (At Cost)
Power purchased from utilities, power marketers, public agencies, and/or generators will be the
exclusive source of supply from 2010 to 2013 and will remain a significant source of power
supply after MCE's initial renewable generation begins producing electricity, anticipated to be
46 PApn19 00of 8 204
2014. During the period from 2009 — 2013, MCE would 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.
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 Program's electric supplier will be established as the contract is
negotiated with the selected electric supplier. It is anticipated that 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 that prices would be predominantly fixed for the contract term.
Renewable Resources
To meet its aggressive renewable energy goals, MCE would initially secure power purchase
contracts for qualified renewable energy resources at an amount equal to 56 percent of retail
demand, which equates to approximately 145,000 MWh in 2010, increasing to nearly 858,000
MWh (70% of total supply) by 2011. To 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.
Renewable technologies that are predominant 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
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.Harnrin, R. Dracker, J. Martin, R. Wiser, K. P4 - �, D. Clonent, M. Bolinger; November 2000 ge
95 8 f 204
P
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 MVV).
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 Term 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
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, 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)
Pesource Type
PG&E Area SCE Area
SDG&E Area'O
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 De►uonstratiml Project; Renerooble Resource
Development Roadmap; Navigant Consulting Inc., June 2006.
Ideally, MCE 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 transitions from the current zonal congestion pricing model to a nodal
model as it implements its Market Redesign and Technology Update (MRTU).11 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
10 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 Powerlink in 2010. Wind resources in Eastern San Diego
County are planned to be connected via tap lines to the Sunrise Powerlink
11 Under the current zonal model, there are potential congestion costs for transferring electricity between any of the
three zones within California (NP15, ZP26 and SP15). The nodal model will expand the number of congestion
pricing points, creating thousands of locational pri 8 g nodes. Page 96 8 f 204
P
850 MW of renewable resource potential within the County, capable of producing
approximately 1,300 GWh per year 12 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. MCE 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.13
For planning purposes, MCE 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)14 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 have applied for transmission
interconnections with the CAISO.15 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 1b These four projects are projected to come on-line between 2008
12 Increasing Renewable Energy Resources in the County of Marin, Jody London. Consulting, November 11, 2007.
73 The cost of potential congestion charges has been included in the risk analysis presented in Chapter 4.
74 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.
15 2008 CAISO Transmission Plan: A Long -Term Assessment of the California ISO's Controlled Grid (2008-2018),
California Independent System Operator, January 2008.
16 PG&E 2006 Electric Grid Expansion Plan, December 29, 2006. Page 97 of 204
49 April 2008
and 2010, pending CAISO approval, at a total estimated cost ranging between $171 and
$455 million. These four renewable -focused transmission projects are identified in the following
table:
Project Title
Vaca Dixon —
Contra Costa
230kV
Reinforcement
PG&E Transmission Expansion Plan Summary
Purpose County Project Scope CAISO
and Approval
Benefit Status
Access Solano Reconductor 230 Not Yet
Resource kV Lines
Bogue Junction Access Sutter
Reconfiguration Resource
Midway —
Gregg 500kV
Line
Vaca Dixon -
Sobrante --
Moraga 230kV
Reinforcement
Access
Fresno,
Resource
Kings &
W
Kern
Access
Solano
Resource
and
Contra
Costa
Reconfigure 115
W lines at Bogue
Junction
Increase
Transmission
Capacity to
Access Resources
Increase
Transmission
Capacity to
Access Resources
Not Yet
Expected
Capacity
Increase
(MW)
Approx. 300
MW when
completed
w/other
projects
Not
Published
Cost
Targeted
Range
In -Service
W
Date
20-50M
May 2008
1-5M May 2004
Not Yet Approx. 100- 2010
1,250 MW 200M
Not Yet
Approx. 300 50-200M May 2010
MW when
completed
w/other
projects
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
4,000 MW of wind generation from the Tehachapi Region. Based on CPUC Decision 04-06-010,
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). A preferred alternative has been identified (new Tesla -Gregg
500 kV line and new Gregg -Midway 500 kV line, which was previously noted) and is still in
PG&E's planning/study phases.
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
Page 98 of 204
50 April 2008
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, MCE would have the same access as PG&E to this transmission once the
projects are completed. For mid and long term planning purposes, MCE should anticipate
procurement from the following types of large scale renewable resourcesl7:
➢ 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 MCE's 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 MCE'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 MCE'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, MCE would 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 will be utilized. Actual procurement of renewable resources
can be conducted through a competitive solicitation, either directly by MCE or in conjunction
with another public agency. Once formed, MCE can explore opportunities to partner with other
public 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 MCE will be in competition for renewable resources with the three
investor owned utilities, wluch 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 MCE. Marin Clean Energy, working with
third party electric suppliers, will need to be aggressive in pursuing the renewable resources
that are currently available to ensure that PG&E and the other utilities do not lock up the most
" In the long term, new technologies such as wave or tidal energy may become economically fe pibW 2()4
51 ApHl 2008
economic resources for their own portfolio needs during the early years of the Program.'B In
contrast to PG&E, which is motivated by regulatory compliance with the Renewable Portfolio
Standards, MCE would elevate procurement and 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
The resource plan includes the anticipated development by MCE of wind and biomass
resources located within the PG&E service territory. These resources are planned to become
operational in 2014. It should be understood that the specific resource types, locations and
timing will be the result of a competitive solicitation process and may differ from those
presented here. Possible locations for new wind development include wind resource areas in
Solano County, the Altamont wind resource area in Alameda County and potentially the
Tehachapi area. The latter location is within the SCE service territory, and would become a
feasible location to site generation for MCE once PG&E expands its import capabilities from that
area as discussed above. Resources located in the Pacific Northwest may also be feasible if MCE
can partner with. an entity such as SMUD or another California publicly owned utility that has
transmission rights from Oregon into California (e.g., the California Oregon Transmission
Project) or if PG&E follows through with plans to expand its transmission system northward.
The generation projects anticipated in this resource plan is summarized in the following table:
Marin Clean Energy Wind/Biomass Project Summary
Generation Type
Location
Year On Line
Capacity
Production
Total Initial Cost
Average Production Cost
Generation Type
Location
Year On Line
Capacity
Production
Total Initial Cost
Average Production Cost
Wind
Greater Bay Area (e.g. Solano County)
2014
150 MW
450,702 MWh Per Year
Approx. $350 Million
$85 to $105 Per MWh
Biomass
Marin County or the California Central Valley
2014
50 MW
343,392 MWh Per Year
Approx. $125 Million
Approx. $65 to $80 Per MM
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
'B It should be noted, however, that none of the respondents to the Cities' request for information identified
availability of renewable resources as one of the challenges to meeting the Program's stated objective of over 80
percent renewable energy by 2014. Page 100 of 204
52 April 2008
customers' energy service needs.19 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 options20
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 Public Goods Charge (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 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 are approximately $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 MCE's integrated
resource plan. As described below there are opportunities for significant cost effective energy
efficiency programs within the region, and MCE would 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 MCE'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.
19 CPUC Rulemaking R.01-08-028, ATTACHMENT 3 ENERGY EFFICIENCY POLICY MANUAL FOR POST -2005
PROGRAMS, Page 2, Rule H.I.
'0 Ibid., Page 3, Rule 11.3. Page 101 of 204
53 April 2008
Baseline Energy Efficiency Potential Estimates
Conservative estimates indicate cost effective ("economic') energy efficiency potential exists in
the Program's territory 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. Table E-1
summarizes these findings below:
Table E-1 Forecast Annualized Energy Efficiency Potential and Program Budgets
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."21 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 22
Forecast achievable energy efficiency equal to 1.1 percent of the CCA's forecast energy sales as
indicated in Table E-1 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.
CCA Program Energy Efficiency Goals
The Program's energy efficiency goals will 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 would be 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. MCE programs
would 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 23
n National Action Plan for Energy Efficiency, July 2006, Section 6: Energy Efficiency Program Best Practices (pages 5-
6)
22 Energy Efficiency Resource Standards: Experience and Recommendations, Steve Nadel, March 2006, ACEEE
Report E063 (pages 28 - 30).
23 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. Page 102 of 204
54 April 2008
Achievable
Achievable
Technical
Economic
Program
Program
Sector Use
Potential
Potential
Potential
Potential
Program
kWh
kWh
kWh
kWh
kW
Costs
Residential
732,840,248
217,934,292
107,356,272
7,459,777 im/.
2,774
$1,889,983
Commercial
576,235,343
78,085,059
59,356,212
7,380,674 1.30
1,334
$874,346
Industrial
107,454,070
15,924,110
14,539,192
255,323 &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
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."21 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 22
Forecast achievable energy efficiency equal to 1.1 percent of the CCA's forecast energy sales as
indicated in Table E-1 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.
CCA Program Energy Efficiency Goals
The Program's energy efficiency goals will 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 would be 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. MCE programs
would 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 23
n National Action Plan for Energy Efficiency, July 2006, Section 6: Energy Efficiency Program Best Practices (pages 5-
6)
22 Energy Efficiency Resource Standards: Experience and Recommendations, Steve Nadel, March 2006, ACEEE
Report E063 (pages 28 - 30).
23 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. Page 102 of 204
54 April 2008
Energy Efficiency Market Potential
EXISTING RESIDENTIAL
53.0%
Existing Commercial
18.0%
Existing Industrial
14.0%
Residential New Construction
1.0%
Commercial New Construction
5.0%
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.
A near-term objective of MCE is to hire Program staff that would develop specific energy
efficiency programs that would seek to obtain these energy savings. MCE may also seek
requisite program funding from the CPUC to administer the energy efficiency programs.
Additional details of MCE's energy efficiency plan would be developed once the CCA Program
is staffed and has begun operations.
Demand Response
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
capacity requirements. The CPUC found that it may not be possible to count dispatchable
demand response resources until 2008. This plan assumes 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 MCE intends to recruit
those customers that have shown a willingness to participate in utility programs into MCE's
demand response programs 24 The goal for this resource plan is to meet 5 percent of the
Program's total capacity requirements through dispatchable demand response programs that
qualify to meet local resource adequacy requirements. This goal translates into approximately
14 MW of peak demand enrolled in MCE's demand response programs. Achievement of this
24 These 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). Page 103 of 204
55 April 2008
goal would displace approximately 30 percent of MCE's local capacity requirement within the
Greater Bay Area.
Marin Clean Energy
Demand Response Goals
(MW)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Total Capacity Requirement (MM 84 273 271 270 270 269 269 270 270 272
Demand Response Target - 14 14 13 13 13 13 14 14 14
Percentage of Loral Capacity Requinnent 0% 30% 30% 30% 30% 307 31M 30% 39% 30%
Marin Clean Energy would 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 71
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
MCE'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. MCE would likely utilize
experienced third party contractors to design, implement and administer its demand response
programs.
Dishibuted Generation
Consistent with MCE's environmental policies and the state's Energy Action Plan, clean
distributed generation is a significant component of the integrated resource plan. MCE would
work with state agencies and PG&E to promote deployment of photovoltaic (PV) systems
within MCE's jurisdiction, with the goal of maximizing use of the available incentives that are
funded through current utility distribution rates and public goods surcharges. PV systems are
relatively expensive sources of electricity, even after considering the available buy -downs, tax
incentives and benefits of net energy metering. Average production costs are in the 30 to 40
cents per kWh range as shown below. For reference, the highest priced "Tier 5" rate charged by
PG&E is currently 37 cents per kWh.
25 For example, the annual customer incentive in PG&E's Capacity Bidding Program is fixed at $43.35 per kW -year in
2007-2008. Page 104 of 204
56 Page
2008
Residential Photovoltaic Costs
Size (KW)
7,�Z
1
�
2
Capacity Factor
2�3
17%
2914
17%
Production (KWh/Year)
BIZ
1,489
IOU Territory Target (MW)
2,978
Installed Cost
$
10,000
$
20,000
CEC Incentive
$
(2,600)
$
(5,200)
Federal Tax Credit
$
(2,000)
$
(2,000)
Net Cost
$
5,400
$
12,800
Loan Term
5
30
0
30
Rate
140
8.5%
105
8.5%
Monthly Payment
70
$41.52
70
$98.42
Average Cost ($/KWh)
$
0.33
$
0.40
Although distributed PV is not cost competitive with other sources of renewable supply
available to MCE (e.g., large scale wind, biomass, and geothermal), 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. MCE
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, MCE could 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
MCE. A proposed net metering rate is discussed in Chapter S.
MCE's CCA customers would contribute funds to the California Solar Initiative (CSI) through
the public goods charge collected by PG&E, and would be eligible for the incentives provided
under that program for installation of PV systems. The California Solar Initiative provides $2.2
billion of funding to target installation of 1,940 MW of solar systems within the investor owned
utility service areas by 2017. All electric customers of PG&E, SCE, and SDG&E are eligible to
apply for incentives. Approximately 44 percent of program funding is allocated to the PG&E
service territory. Assuming solar deployment would be proportionate to funding, the program
is intended to yield approximately 775 MW of solar within the PG&E service area. A minimum
of 13 MW should be deployed within the jurisdictional boundaries of MCE.
California Solar Initiative Deployment
Page 105 of 204
57 April 2008
7,�Z
3J)fl
�
Z91S1
�L
2�3
3411
2914
ZQl�
741
BIZ
3�
IOU Territory Target (MW)
176
353
529
705
882
1,058
1,235
I,411
1,587
1,764
1,940
1,940
Total Funding ($Millions)
320
320
320
240
240
240
160
160
160
5
0
0
PG&E Funding ($Millions)
140
140
140
105
105
105
70
70
70
2
0
0
PG&E Incentives Share
44%
44%
44%
44%
44%
44%
44%
44%
44%
40%
4D%
40%
PG&E Area Deployment (MW)
77
154
231
309
386
463
540
617
694
705
776
776
Marin Share of PG&E Load
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
1.7%
Marin Solar Deployment (MW)
1
3
4
5
6
8
9
10
12
12
13
13
Page 105 of 204
57 April 2008
Marin Clean Energy could work to ensure that customers within its jurisdiction take full
advantage of the solar incentives, with the goal of exceeding the deployment targets shown
above. Additional solar programs developed by MCE could .also increase use of solar in the
Marin Communities.
Impact of Resource Plan on Greenhouse Gas Emissions
Reductions in greenhouse gas emissions as a result of the Program' resource plan are estimated
to range from 302,330 to 534,369 tons per year by 2019, an amount approximating as much as 17
percent of total GHG emissions (from all sectors, including transportation) within the Marin
Communities. The basis for the estimate is an increase to more than 80 percent (beginning in
2014) in the contribution of renewable resources to the resource mix used to serve electric
customers in the Marin Communities, The baseline for comparison is the resource mix used by
PG&E versus the resource mix that would be utilized by the CCA Program. This comparison is
likely conservative in that it assumes PG&E would meet the 20 percent RPS target even though
PG&E has remained at between 12 percent' and 14 percent in the six years since the RPS
legislation was enacted. The actual impact would be greater if PG&E misses the RPS target and
less if PG&E exceeds the target, either voluntarily or by future mandate.
The precise impact on greenhouse gas emissions will depend upon the resources that would be
displaced by the CCA's renewable resources. New resources will generally displace the least
efficient, highest cost resources in the system as resources are dispatched on the basis of
variable operating costs. The baseload nuclear, coal and hydro resources currently in the
system resource mix will likely not be displaced because of their low operating costs. The low
end of the estimate assumes that new renewables compete with new, efficient natural gas fired
resources, while the higher estimate assumes displacement of the less efficient existing fleet of
gas-fired resources. The CO2 conversion factors for avoided air emissions used in these
estimates were obtained from figures reported by the California Energy Commission (400 tons
per GWh vs. new gas-fired resources, and 707 tons per GWh vs. existing resources) 26
Marin Clean Energy
Greenhouse Gas impact
2010 to 2019
The estimated impacts do not count renewable resources that are simply transferred from the
PG&E portfolio to the CCA portfolio, unless the transferred resources are replaced with new
renewable resources. For example, if PG&E is unable to meet the 20 percent RPS standard
because MCE contracted with existing Qualifying Facilities formerly under contract to PG&E,
there would be no net increase in renewable energy production. However, if PG&E contracted
with new renewable resources to replace the renewable energy supply "lost" to MCE as it
surpassed the RPS, there would be a net increase in renewable energy and the greenhouse gas
impact would appropriately be characterized -as a benefit of the Program.
26 California Renewable Technology Market and Benefits Assessment, November 2001. Page 106 of 204
58 Apri12008
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Marin Clean Energy Renewables (Mwh)
145,048
857,657
855,339
85 5,691
985,245
988,676
992,131
996,940
1,000,579
R5
1,0,660
Renewables per RPS (MWh)
44,415
244,477
243,816
243,916
244,762
245,615
246,473
247,668
24072
249,834
Program Renewable rmpact(MWh)
100,633
613,180
611,23
611,774
740,40
743,061
745,658
749,273
752,007
7551826
CO2 Reduction - Cow (tonnes per year)
40,53
245?71
244,609
244,710
296,193
297,23
298,263
299,709
300,80.1
302,330
CO2 Reduction - High (tonnes per year)
71,148
433,518
432,347
432,524
523,521
55,344
527,180
529,736
531,669
534,369
The estimated impacts do not count renewable resources that are simply transferred from the
PG&E portfolio to the CCA portfolio, unless the transferred resources are replaced with new
renewable resources. For example, if PG&E is unable to meet the 20 percent RPS standard
because MCE contracted with existing Qualifying Facilities formerly under contract to PG&E,
there would be no net increase in renewable energy production. However, if PG&E contracted
with new renewable resources to replace the renewable energy supply "lost" to MCE as it
surpassed the RPS, there would be a net increase in renewable energy and the greenhouse gas
impact would appropriately be characterized -as a benefit of the Program.
26 California Renewable Technology Market and Benefits Assessment, November 2001. Page 106 of 204
58 Apri12008
Considering the challenges faced by PG&E in achieving the 20 percent RPS minimum by 2010
described in its renewable resource plans filed with the CPUC, it is unlikely that PG&E would
voluntarily seek to exceed this level in the foreseeable future. However, some state policy
makers, including the Governor, are advocating a 33 percent renewable portfolio standard by
2020, and a CPUC study that found such a goal could be achieved. The greenhouse gas
reduction mandate of Assembly Bill 32 may also add momentum to a 33 percent renewable
portfolio standard, although the compliance rules will not be known for several years. Under
the assumption that the statewide standard is increased to 33 percent and PG&E complies, the
greenhouse gas benefits of the CCA program would be reduced to a range of 237,374 to 419,558
per year.
Page 107 of 204
59 April 2008
—
...z
• <. .>'` �. ..; ..4i)>s ::,i' .._. :.. �... _i_i a.a..: ..>::Sc.-=','iir.�.i�i::`�_<;:; >. JixY.� Y'ti.S�)�`TS:.._ �..
::1 at. : h• ::: - . _ n�• -_b%.:6rb>r� - a'5vi;M,;:;,._
This Chapter examines the monthly cash flows expected during the implementation period of
the CCA Program and identifies the anticipated financing requirements for the overall CCA
Program by MCE. It includes estimates of program startup costs, including the necessary
staffing and capital outlays which would commence once the CPUC accepts the Implementation
Plan submitted by MCE. It also describes the requirements for working capital and long term
financing for the investment in renewable generation, consistent with the resource plan
contained in Chapter 3.
The cash flow analysis is indicative of program financials assuming MCE could procure full
requirements electric supply for approximately 8.8 cents per kWh. The analysis should be
updated with the pricing data provided in response to a future request for information/request
for proposals process.
Description of Cash Flow Analysis
This cash flow analysis estimates the level of working capital that would be required until full
implementation of the CCA program is achieved. For the purposes of this analysis, it is
assumed that the implementation period Begins in January 2010 and continues through
December 2013. 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 implementation period, and
specifically account for the transition or "Phase -In" of CCA Customers from PG&E's service
territory described in Chapter 3.
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;
D Contractor Costs;
Infrastructure Requirements;
➢ Billing Costs;
➢ Scheduling Coordination;
Grid Management Charges; and
➢ Franchise Fees.
Page 108 of 204
60 April 2008
A key element of the cash flow analysis is the assumption that electricity will be procured
exclusively under a power purchase arrangement until the proposed renewable resource would
be operational. After that time, supply cost reductions are expected as MCE's resource
displaces power purchases. The focus of this cash flow analysis is during the implementation
period when opportunities for supply cost savings are more limited.
The assumed cost of third party electric supply used in this analysis, excluding the cost of
MCE's operations and contractor costs, is 8.8 cents per KWh. This price represents the price
needed for a full requirements electricity contract during the implementation period to allow
the rates and program revenue surpluses presented below. As mentioned previously, the cash
flow analysis will be updated following receipt of pricing offers from potential third party
electric suppliers.
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 MCE's CCA 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. Based on this assumed rate structure, the following tables provide a
comparison of the projected distribution utility rate and MCE's electric rates (in each of the two
proposed tariffs: 100 percent Green and Light Green) over the CCA program implementation
period.
Page 109 of 204
61 April 2008
Marin Clean Energy
Comparison of Electric Rates - MCE versus distribution utility
CATEGORY
2010
2011
2012
2013
MCE's Electric Rate ($/MWh)-100% Renewable
$112.34
$110.81
$114.75
$118.77
IOU Electric Rate ($/MWh)
$93.61
$92.34
$95.63
$98.97
Variance ($AVM)
($18.72)
($18.47)
($19.13)
($19.79)
Variance in Generation Rate (°/6)
-20.0%
-20.0%
-20.0%
-20.0%
Impact to Monthly Residential Customer Bill (°/6)
-10.3`/6
-10.2%
-10.4%
-10.5%
CATEGORY
2010 2011 2012 2013
MCE's Electric Rate ($/MWh)-25/51°6 Renewable
$93.61
$92.34
$95.63
$98.97
IOU Electric Rate ($/MWh)
$93.61
$92.34
$95.63
$98.97
Variance ($/MWh)
$0.00
$0.00
$0.00
$0.00
Variance in Generation Rate (%)
0.0%
0.0%
0.0%
0.0%
Impact to Monthly Residential Customer Bill (%)
0.0%
0.0%
0.0%
0.0%
As previously noted, MCE would develop or otherwise obtain entitlements to up to 200 MW of
new renewable generation by 2014. T'he power produced by this new renewable generating
capacity would be delivered to MCE at production costs, wluch are significantly lower than
retail prices charged by energy suppliers participating in the market. 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 over 80 percent of
MCE's power supply (beginning in 2014) will be from renewable energy sources, upward price
pressures on its power supply should be significantly reduced over long-term operations. The
following chart depicts the projected trend in average monthly price premiums paid by an
average customer of MCE .27
n An "average" customer was determined based on participation levels in both the 100 percent Green Tariff and
Light Green Tariff for all customer classes. The projected impacts to monthly bills of an average customer reflect
these participation levels and represent the net effects of Light Green Tariff participants, who will pay no premium,
and customers participating in the 100 percent Green Tariff, who will pay a higher premium than that which is
displayed in the chart. Page 110 of 204
62 April 2008
MARIN CLEAN ENERGY
AVERAGE PROGRAM PREMIUM (MONTHLY)
CUSTOMER USING 500KWh/MONTH
$8.00
$6.00
$4.00
$2.00
p $0.00 — ITH
:� ($2.00)
($4.00)
($8.00)
O ($10.00)
A ($1200)
($14.00)
($16.00)
YEAR OF OPERATION
These long-term cost savings, which can be identified in the chart as negative premiums, could
be passed on to program customers in the form of lower generation rates or could be applied to
the procurement of additional renewable energy supplies (moving the program's 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 MCE.
Ultimately, MCE would have flexibility when making these decisions and could 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 MCE to move through the CCA implementation 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 MCE,
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 regard
to the assumptions related to payments streams, the cash flow analysis assumes that customers
will make payments within 60 days of the service month, and that MCE will make payments to
suppliers within 30 days of the service month. This likely overstates the net payment lag to
some extent because customer payments begin to come in soon after the bill is issued, and most
are received before the due date. At the same time, some customer payments are received well
after the due date. The 30 day net lag is a conservative assumption for cash flow purposes.
With the assumptions regarding payment streams, the cash flow analysis itself identifies
funding requirements while recognizing the potential lag between paynp%t jeFTiyoWid
63 April 2008
payments made during the implementation period. The estimated financing requirements for
the implementation period (2010 — 2013), including working capital, based on the phase-in of
customers as described above is approximately $15.8 million. Working capital requirements
reach this peak immediately after enrollment of the Phase 3 customers.
CCA Program Implementation Feasibility Analysis
In addition to developing a cash flow analysis which estimates the level of working capital
required to get MCE through full CCA implementation, a summary analysis that evaluates the
feasibility of the CCA program during the implementation 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.
The results of the feasibility analysis, based on the power supply cost figure discussed above,
are shown in the following table. Under these assumptions, over the entire implementation
period the CCA program is projected to accrue a reserve account balance of approximately
$18 million. Power supply costs below approximately 8.8 cents per kWh for the four-year
startup period would enable the program to at least match PG&E's rates for customers
subscribing to the Light Green Tariff. Conversely, power supply costs above this figure would
jeopardize the program's potential to offer Light Green Tariff rates that are equivalent to PG&E
during this time period, because CCA rates would be higher than those charged by PG&E.
Page 112 of 204
64 April 2008
Marin Clean Energy
Summary of CCA Program Implementation
(January 2009 through December 2013)
CATEGORY
L REVENUES FROM OPERATIONS (4
(A) ELECTRICITY SALES:
RESIDENTIAL
GENERAL SERVICE (A-1)
SMALL TIME -OF -USE (A-6)
ALTERN. RATE FOR MEDIUM USE (A-10)
500 - 900kW DEMAND (E-19)
1000+ kW DEMAND (E-20)
STREET LIGHTING k TRAFFIC CONTROL
AGRICULTURAL PUMPING
TOTALREVENUES
II. COST OF OPERATIONS ($):
(A) ADMINISTRATIVE k GENERAL (A&G):
STAFFING
INFRASTRUCTURE
CONTRACTOR COSTS
IOU FEES (INLCUDING BH -LING)
CONTRACT STAFF
SUBTOTAL -A&G
(B) CCA PROGRAM OPERATIONS:
ELECTRICITY PROCUREMENT
RENEWABLE PORTFOLIO ADJUSTMENT
SUBTOTAL - CCA PROGRAM OPERATONS
TOTAL COST OF OPERATION
CCA PROGRAM SURPLUS / (DEFICIT)
2009
2010
2011
2012
2013
TOTAL
$0
$271
$68,459,083
$71,209,427
$74,070,266
$213,739,048
$0
$332,029
$16,246,125
$16,911,607
$17,591,030
$51,080,791
$0
$277,770
$5,769,373
$6,067,692
$6,311,462
$18,426,297
$0
$15,499,512
$21,734,676
$22,664,751
$23,575,307
$83,474,246
$0
$6,597,654
$9,049,315
$9,375,412
$9,752,069
$34,774,451
$0
$3,904,820
$5,405,411
$5,633,713
$5,860,048
$20,803,993
$0
$534,302
$755,054
$785,389
$816,942
$2,891,687
$0
$275
3549,460
$548,644
$570,686
$1,669,065
$0
$27,146,633
$127,968,499
$133,196,635
$138,547,810
$426,859,577
$451,067
$2,661,067
$3,092,775
$3,185,507
$3,281,072
$12,671,437
$139,500
$192,000
$157,500
$162,225
$167,092
$818,317
$434,833
$1,607,417
$2,608,875
$2,635,255
$"-)714,313
$10,000,693
$200,023
$187,286
$1,128,200
$1,024,786
$1,055,529
$3,595,825
$0
$0
$0
$0
$0
$0
$1,225,423
$4,647,770
$6,907,300
$7,007,773
$7,218,006
$27,086,271
$0
$22,781,412
$107,727,159
$110,974,279
$114,317,379
$355,800,229
$0
$1,422,695
$9,284,041
$8,400,441
37,507,772
$26,614,948
$0
$24,204,106
$117,011,200
$119,374,710
$121,825,152
$382,415,177
$1,2.75,423
$28,851,876
$123,998,499
$126,382,492
$129,043,157
$409,501,448
($1,225,423)
($1,705,243)
$3,969,999
$6,814,143
$9,504,653
$17,358,129
The surpluses achieved during the implementation period serve as operating reserves for Marin
Clean Energy in the event that operating costs (such as power purchase costs) exceed collected
revenues for short periods of time. The following table provides an annual summary of the
incremental costs incurred by program customers participating in the 100 percent Green Tariff
during the implementation period. The incremental revenues would be used for paying the
additional costs associated with the 100 percent renewable energy product. The premiums are
projected to decline once the benefits of MCE's renewable resources begin to be realized and as
costs for fossil fuels increase.
Pae 113 of 204
65 Xpril 2008
MARIN CLEAN ENERGY
COMMUNITY CHOICE AGGREGATION PROGRAM IMPLEMENTATION
SUMMARY OF COSTS INCURRED FOR 100° GREEN ENERGY PREMIUM
(2010 THROUGH 2013)
CUSTOMER CLASS
2010
2011
2012
2013
TOTAL
RESIDENTIAL
$33
$8,407,256
$8,745,017
$9,096,348
$26,248,655
GENERAL SERVICE (A-1)
$40,775
$1,995,138
$2,076,864
$2,160,302
$6,273,080
SMALL TIME -OF -USE (A-6)
$34,112
$708,520
$745,155
$775,092
$2,262,879
ALTERN. RATE FOR MEDIUM USE (A-10)
$1,903,449
$2,669,171
$2,783,390
$2,895,213
$10,251,223
500 - 900kW DEMAND (E-19)
$65,323
$89,597
$92,826
$96,555
$344,301
1000 +kW DEMAND (E-20)
$38,662
$53,519
$55,779
$58,020
$205,980
STREET LIGHTING & TRAFFIC CONTROL
$65,616
$92,726
$96,451
$100,326
$355,119
AGRICULTURAL PUMPING
$11
$21,133
$21,102
$21,949
$64,195
TOTAL
$2,147,981
$14,037,059
$14,616,585
$15,203,806
$46,005,432
Capital Requirements
The start-up of the CCA Program will require a significant amount of capital for three major
functions: (1) staffing and contractor costs; (2) program initiation; and (3) working capital. Each
of these anticipated requirements is discussed below.
Staffing costs for the initial twelve-month startup period (June 2009 through May 2010) are
estimated to be approximately $1.4 million. Actual costs may vary depending on the ability of
MCE to recruit qualified staff to fill the roles illustrated above. Contractor costs for the same
time period are estimated to be approximately $1.3 million. These costs include:
advertising/communications, consulting, legal, and data management.
Program initiation costs include the infiastructure that NICE will require (office space, utilities,
computers) as well as the distribution utility fees for initiating the CCA Program. Infrastructure
costs are estimated to be approximately $240,000 and the distribution utility fees are estimated
to be approximately $368,000.
Therefore, the total staffing, contractor and program initiation costs are expected to be
approximately $3.4 million. These are costs that ultimately will be collected through CCA
Program rates; however, most of these costs will be incurred prior to MCE selling its first kWh
of electricity. In addition, it is anticipated that additional working capital will be required to
purchase electricity � for Program customers prior to revenue being collected from those
customers: During the start-up period (Phases 1 and 2), the total financing requirement is
estimated to be approximately $6.4 million, increasing to approximately $15.8 million following
enrollment of Phase 3 customers. MCE's plans for financing these capital requirements are
discussed later in this chapter.
Page 114 of 204
66 April 2008
Startup Activities and Costs
The initial startup funding estimate of $3.4 million is budgeted to fund the following activities
and costs:
➢ Define and execute communications plan:
• Media campaign
• Informational materials and customer notices
0 Customer call center
➢ Hire/contract for Executive Director, Sales and Marketing representatives, and Finance
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; and
➢ 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, which are
estimated at approximately $3.4 million, include expenditures for program staff/contract staff,
associated infrastructure, 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 that will be accrued before
significant revenues from program operations commence. These costs have been characterized
as startup costs for purposes of the financing plan.
Page 115 of 204
67 April 2008
Estimated Staffing Costs
The following table provides the estimated staffing budgets for the startup period, reflecting the
staffing plan described in Chapter 2. Staffing budgets. include direct salaries and benefits
loading. As previously noted, the staffing roles would not necessarily be conducted internally.
At a minimum, Marin Clean Energy would have four staff positions as described in Chapter 2.
The other staffing estimates are used for budgetary purposes.
PreStariup
Cutoverl Phase
Notificalionand Cutoverl
Enrollment] -Pilot
Phase Notification and
Start-up Costs
Operations
Enrollment Period
Pre- startup
Jun -09
Pre -Startup
Phase Cutoverl Operations Enrollment Period Culm;zr2
Staffing
Pilot Phase
Ju2t-09
Jul -09 Au09
Sep -09
od-09
Nov -09 Dee -09
Jan -10
Feb -20 Mar -10 Apr -10 May -10
FTEs
Rb -10
4
4 4
4
4
5 9
9
145 185 205 205
Cost
S
53,196 S
53,196 $ 53,196 $
53,196 $
53,196 $
70,338 $ 114,750 S
114,750 $
1842(10 $ 218,379 $ 238,638 $ 238,638
Infrastructure
$
21,250 S 21,250 S
21,250 S
21,250 $
21,250 f
21,750 f
21.150 S
21,150 S
Cost
$
12,000 $
- $ - $
73,125 $
13,125 $
16,125 $ 25,125 S
13,325 $
29,625 $ 25.125 $ 19,125 $ 13,125
Contractor Costs
10,129 f
10,129 S
10,129 S
10,129 S
14129 S
14129 $
14129
Adminbtmfiv An6bn1
Adverfising/Comm.
f
- $
- $ - $
- $
- $
20,000 S 20,0000 S
10,000 $
201000 $ 501000 $ 50,000 $ 14000
Consulting
S
35,417 S
35,417 $ 35,417 S
35,417 $
35,417 f
35,417 $ 35,417 S
35,417 $
35,417 $ 35,4171$ 35,417 $ 35,417
Irgal
f
16,000 S
16,000 $ 16OOD $
16,000 S
16,000 $
16,667 $ 16,667 $
16,667 $
16,667 $ 16,667 f 16,667 $ 16,667
Data Management
S
- $
- $ - $
- $
- $
16,792 $ 1602 S
25,188 $
25,188 $ 142,729 $ 142729 $ 142,729
Subtotal Contractor Costs
f
51,417 S
51,417 $ 51,417 f
51,417 $
51,417 $
88,875 $ 8$875 S
87,271 S
97,271 S 244,813 $ 244,813 $ 204,813
JOU Fors (Including Billing)
. S
S
. S
14129 S
14129
AScoonR.dffilling Mdyst
S
S f
Cost
f
- $
- S - f
98,390 S
98,390 S
1,633 f 1,610 S
6,598 $
4,421 $ 55,373 $ 49,189 $ 52,860
Grand Total
$
116,613 $
109,613 $ 104,613 $
276,128 S
216,128 $
176,971 11436 3
221,M $
M1,517 $ 543,689 $ 551,764 $ 509.435
Estimated Staffing Costs
The following table provides the estimated staffing budgets for the startup period, reflecting the
staffing plan described in Chapter 2. Staffing budgets. include direct salaries and benefits
loading. As previously noted, the staffing roles would not necessarily be conducted internally.
At a minimum, Marin Clean Energy would have four staff positions as described in Chapter 2.
The other staffing estimates are used for budgetary purposes.
Estimated Infrastructure Costs
Infrastructure or overhead needed to support the organization includes computers and
peripheral equipment, office furnishings, office space and utilities. These expenses are
estimated at $240,000 during program startup. Office space and utilities are ongoing monthly
expenses that will begin to accrue before revenues form program operations commence and are
therefore assumed to be financed along with other startup costs.
Infrastructure Costs(SJMonlh)
PreStariup
Cutoverl Phase
Notificalionand Cutoverl
Enrollment l-
P6ssel
Enrollment 1- Pilot Phase
Operations
Enrollment Period
Sbfling Pbn(FM,3
Jun -09
Pre -Startup
Sep -09 Oct -09 Nov -09
Dec -09
Pilot Phase
Cumvnl Op -11- Nntifirallonand E -11-t Period
Ortover2
Stiff
Jun•09 Ju609
Mg -09
Sep -09
Od-09
N-09 D-0 Jae -10
Rb -10
M-10
Apr]0
May -10
Managenanl
$ - $
. $ - S
Office Space
S - $
- $ -
S 10,938 $ 10,938 $ 14933 $
10,938 f
10,938 $ 10,938 $
14938 S 10,938 f 10,938
Utilities
$ - f
- f -
Eaecotiw Dirccw
$
21,250 S 21,250 S
21,250 S
21,250 $
21,250 f
21,750 f
21.150 S
21,150 S
21,150 $
21,250 S
31,25D $
21,150
Pulley Malys(
S
14129 S 10.179 f
14129 S
10,129 $
14129 S
10,129 f
10,129 S
10,129 S
10,129 S
14129 S
14129 $
14129
Adminbtmfiv An6bn1
S
7.792 S 7,792 S
7.792 S
7,792 $
7,792 S
7.792 f
7,792 S
7,792 f
7,792 S
7,792 S
7,792 $
7.792
Fi-.-..,l Ran
Mnruger
S
- $ $
S
S
- S
17,142 S
17,142 f
17,142 S
17,142 S
17,142 f
17,142 S
17,142
Rat-Anotyst
S
- S f
f
- S
S
- f
S
. S
S
. S
14129 S
14129
AScoonR.dffilling Mdyst
S
S f
f
- S
- S
S
14129 f
14129 f
HOW f
14129 S
10,129 $
10.129
A,Lnidalmlire Asshbnl-
Mes Ad Markding
ktwger
S
14,025 f 14,015 f
14,025 f
14025 S
14,025 S
14,025 S
14,025 S
14,025 f
14.015 f
14,025 S
14,025 S
14.025
Arcmmt Rrynesu,bovnc
$
- $ - f
f
- S
$
- S
- $
- S
. S
30'160 f
44517 f
44517
Commonira1ons5peda110
$
- f - $
. f
- $
- f
- $
- f
- S
10,129 S
10,129 S
10,129 f
10,129
Adminbtmfi.Aaabbnl
$
- S f
$
$
- S
- S
- S
- S
- $
7.192 S
7,792 S
7.792
Energy EJfidrnq
M-Scr
S
- S - f
- S
- f
- S
- f
- f
- S
14.025 f
14.075 $
14.025 S
14.025
P.I.d Manogcr
S
- f - S
- f
- $
- S
- S
- S
- S
36)31 $
36$.31 S
34231 S
36MI
R.&W.t.y
Manager
S
S - S
- $
- S
- S
- f
14,021 S
UMS S
14,075 S
14.025 S
34.425 S
14,005
Regulatory Analyst
S
S - f
- f
- S
- S
- $
14129 $
10,129 S
14129 $
10.129 f
14129 $
10,129
InfomutionTeslmology
Irspecb
S
- f - S
- S
- S
- S
- S
14129 S
14t29 S
10.129 S
10,129 S
14129 f
14129
flumanResmrna
HRSpmblist
$
- S - f
- S
- S
- S
- $
S
- S
5,065 S
5,065 S
5.465 f
SAM
JubbLd9ldn'%
S
53,196 f 53,196 S
+'7,196 S
50.196 $
51196 S
74700 S
114,750 S
114.756 S
104200 $
216,179 S
23$633 6
23(,6.38
Estimated Infrastructure Costs
Infrastructure or overhead needed to support the organization includes computers and
peripheral equipment, office furnishings, office space and utilities. These expenses are
estimated at $240,000 during program startup. Office space and utilities are ongoing monthly
expenses that will begin to accrue before revenues form program operations commence and are
therefore assumed to be financed along with other startup costs.
Infrastructure Costs(SJMonlh)
PreStariup
Cutoverl Phase
Notificalionand Cutoverl
Enrollment 1- Pilot Phase
Operations
Enrollment Period
Jun -09
Jul -09 Au09
Sep -09 Oct -09 Nov -09
Dec -09
Jan4o Feb -10
Mar -10 Apr -10 May -10
Computers
f 12,000 S
- $ -
S f - f 3,000 S
72,000 S
- $ 16,500 S
12,000 $ 6,000 S -
Furnishings
f - f
S
S 60,000 $ S - $
. $
$ - $
. $ - S
Office Space
S - $
- $ -
S 10,938 $ 10,938 $ 14933 $
10,938 f
10,938 $ 10,938 $
14938 S 10,938 f 10,938
Utilities
$ - f
- f -
f 2,188 $ 2,188 f 2,188 $
2,188 $
2.188 f 2,188 f
2,188 S 1-138 f 71168
Subtotal Infraslructum-
f 12,000 $
- $ -
f 73,125 S 13,125 f 16,125 $
5,125 S
13,725 f 29,67.5 $
5,125 S 19,125 f 13,125
Page 116 of 204
68
April 2008
Utility Implementation and Transaction Charges
The estimated costs payable to the distribution utilities for services related to the CCA program
startup period include costs associated with initiating service with the utility, processing of
customer opt -out notices, customer enrollment, post enrollment opt out processing, and billing
fees. Most of the distribution utilities fees are explicitly stated in the relevant CCA tariffs. One
unknown potential cost is any specialized service fee that may be imposed by the distribution
utilities to support the planned phase-in of customer enrollments or other specialized services
requested from PG&E. This potential cost is captured in the estimated service initiation fee.
Udlily Tranuction Fen (Urdts/Month)
Opt -Out Notifications
Per Account
Per Event
Post enrollment notification
Per Account
Service Initiation
Per Hour
Customer List
Per Event
Mess enrollment
Per Account
Per Event
Opt -Out Pecs
Per Opt Out
Customer Contact Fee
Per Minute
Billing Fee
Per Account
Utility Transaction Fees ($/Month)
Opt -Out Notifications
Per Account
Per Evdnt
Post enrollment rwlilication
Per Account
Service Initiation
Per Hour
Customer List
Per Event
Mass enrollment
Per Account
Per Event
Opt -Out Fees
Per Opt Out
Customer Contad Fee
Per Minute
Billing Fee
Per Account
Subtotal
Pr Startup Enrollment i -Pilot Phase Culoverl Phasel NollEation and Culover2
Operallons Enrollment Period
Jun -09 Jul -09 Aug -09 Sep -09 Od-09 Nov -09 Dec•09 Jan -I0 Febifl Mar -10 Apr -10 May -IO
562 562 562 562 122,208 122,208 1,180
1 1 1 1 1 1 1
562 1,188
Estimates of Third Party Contractor Costs
Contractor costs include outside assistance for advertising, 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. The table below
shows the estimated contractor costs during the startup period.
Page 117 of 204
69 April 2008
1,200 1,200
] 1
l
562
109,987
1
1
-
-
-
- 6,110
3,666 13
34
8
6
8 7,332
1,833 1,222
562
562 562
562 1,750
Pre -Startup
Eh llmentl-Pilot Phase CutoverI
PhaseI Notificationand Cutovrr2
Opeat(ons Enrollment
Period
Jun -09
Jul -09
Au09
Sep -09 Ort -D9
N-09
Dec -09
Jan -10
Feb -10 Mar -10
Apr -10 May -10
S -
S -
S -
S - 5 -
5 202 $
202 S
202 S
202 $ 43,995 S
43,995 $ 428
$ -
$ -
S -
5 - S -
S 1,4DD $
1,40D 5
1,400 S
1,400 S 1,400 S
1,400 S 1,400
$
$ -
S
S - 5 -
5 - S
- S
- S
5 - S
- $ -
$ -
5 -
S -
5 - 5 -
$ - S
- 5
225 S
- S S
S 475
S
S -
$
5 5
S 5
$
$
5 S
$
5 -
5 -
S -
S 96,000 5 96,0011
S - $
- $
- S
- 5 - $
S -
S
S
$
5- 5-$
S
$
$
S S
S
$ -
$ -
$ -
S 2,390 $ 2,390
S - 5
- S
- $
2,390 $ - S
S
$
$
$
S $
S S
S
$
5 S
$
$ -
$ -
$ -
$ - S -
S - S
- S
2S $
- $ - $
- S 43,995
$ -
$ -
S -
S - $
S - $
- S
4,120 $
- S $
- $ 4,120
$
$
$ -
S $
$ 5
s
$
$ S
S -
$ -
$ -
$ -
5 - S -
$ - $
- $
- $
- S 2,811 $
1,686 $ 6
$
S
$
$ S
S $
- $
S
5 - $
- $ -
S -
S -
$ -
$ - 5 -
$ 31 S
8 $
5 S
8 $ 6,746 $
1,686 S 1,124
$ -
$ -
$ -
$ - $ -
$ - S
- $
421 S
421 S 421 S
421 S 1,312
5 -
$ -
$ -
S W3911 $ 98,390
S 1,633 S
1,610 5
6,598 5
4,421 5 55,373 S
49,189 S 52,860
Estimates of Third Party Contractor Costs
Contractor costs include outside assistance for advertising, 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. The table below
shows the estimated contractor costs during the startup period.
Page 117 of 204
69 April 2008
Contractor Costs lS)Monlh)
Pre -Startup Fmilmee12-M.1phase Cutoval
Phase NOifieation and Culover2
Operations Enrolimml period
cnniracmrcosls
J-09 Jut -09 Aug -09 Sp -09 0e1-09
Nov -09
Dee -09
Jan -10 •
Feb -10 Mar -10 Apr -10
Mar10
General dveNsing
S - $ - $ - S i - S
20,000 $
20,000 $
10,000 $
2gODD $ 58000 f S%DOD S
10,0D0
Legal
$ 16,000 S 16,000 $ 164000 S 16.000 $ 16,0011 i
16,667 5
16,667 $
16,667 $
16,667 $ 16,667 S 16,667 i
14667
Resoum Planning
$ 12,500 $ 12,500 S 12,500 $ 12,500 $ 12-W $
17,500 $
IZ50D i
12,500 $
12,500 $ 12,500 S 12500 S
12,500
Implemcnta0on Support
i 2;917 S 22,917 $ 22,917 $ 22.917 $ 22917 $
22,917 S
22,917 S
22,917 $
22,917 $ 22,917 $ 72,917 $
22917
customer Enrollment
$ - $ - $ - S - $ - $
81396 $
8,396 S
8,396 $
8.396 S 33583 $ 33,563 $
33,583
cult-ercore(Ce11Center)
$ S - $ - S - $ - S
8,396 $
8396 $
81396 $
8,396 $ 100,750 $ 100,750 $
1OD,750
Amounts Recelwblc and VatRcation
S - S - S - S - S - S
- S
- S
8,396 S
8,396 S 8596 S 8,396 $
8,396
Tocol ComractorCosts
S 51,417 S 51.417 S 51.417 i 51,417 S 51,417 S
88.875 $
88,675 S
87,271 $
97,271 $ 244,813 $ 244,013 $
204.813
Financing Plan
The initial start-up funding would be provided by MCE via a short-term financing, likely a
letter of credit. MCE would recover the principal and interest costs associated with the start-up
funding via retail rates. It is anticipated that the start-up costs would be fully recovered within
the first two to three years of the Program operations through retail rates.
Working Capital
For purposes of determining working capital requirements related to power purchases, it is
assumed that operating revenues from sales of electricity will be remitted to MCE on
approximately day 47 of Program operations, based on PG&E's standard meter reading cycle of
30 days and PG&E's payment/collections cycle of 17 days. Either the electric supplier or MCE
will be responsible for providing the working capital needed to support electricity procurement,
subject to the outcome of negotiations with the selected electric supplier .211 If it is the electricity
provider, this cost will be reflected in its price for providing full requirements electric service to
the Program. Regardless, of this being provided by the third party supplier or MCE, Marin
Clean Energy will be obligated to meet working capital requirements related to Program
management, which will be included in the short term financing 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 four years of program operations are shown in this chapter. Pro forma
projections for the longer term are included in Appendix A.
Marin Clean Energy Financings
It is anticipated that at least three financings will be necessary in support of the CCA Program.
The anticipated financings are listed below and discussed in greater detail.
28 The cost of short term debt issued by Marin Clean Energy is likely to be lower than the costs a supplier would
charge to carry the float on MCE's power purchases. This assumption should be confirmed once MCE's financings
are arranged with its bank and a primary electric supplier has been selected. Page 118 of 204
70 April 2008
CCA Program Start-up and Working Capital (Phases 1 and 2)
As previously discussed, the anticipated start-up and working capital requirements for the CCA
Program through Phase 2 are $6.4 million. Depending upon the arrangements made between
MCE and the third party supplier, this amount could potentially be as low as $3.1 million
because $3.3 million of the estimated start-up and working capital requirements is for working
capital related to power purchases that may ultimately be carried by the Program's electric
supplier (rather than MCE). Once the CCA Program is up and running, these costs would be
recovered from the retail customers through retail rates. It is likely that these costs may need to
be carried until such time as MCE's generation resource begins operations 29 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 MCE's Board of Directors regarding
initial rates for Phase 1 and 2 customers.
It is assumed that this financing will be via a letter of credit (LOC), which would allow MCE to
draw cash as required and that the LOC could be sized (or increased) should it be needed for
working capital in Phase 3. This financing would need to commence in mid 2008.
CCA Program Working Capital (Phase 3)
The next potential financing would be working capital for Phase 3. 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 $15.8 million (or
more) in "float" for the start of Phase 3. This number would be refined as the CCA Program
was operational and bids were received and evaluated from power providers. The need for this
level of working capital can be greatly reduced if MCE can put the payment "float" to the third -
party energy supplier.
Renewable Resource Project Financing
MCE's CCA program acticipates large project financings for renewable resources (likely wind
and biomass), currently estimated to be in the $475 million range (combined). These financings
would occur once specific projects are completely sited and the CCA Program is up and
running. The anticipated date for financial close for the renewable resource projects is late 2010.
This financing would take out any short-term financing for the renewable resource project
development costs, and will be in the range of a 20- to 30 -year term.
The security for these bonds would be a hybrid of the revenue from sales to the retail customers
of MCE, including a Termination Fee (discussed in greater detail in Chapter 5) and the
renewable resource project itself.
PG&E is obligated to collect the CCA's charges for customers of the CCA pursuant to Rule 23,
and, for formerly CCA customers that return to PG&E bundled service, PG&E will collect the
charges specified by the CCA in the final CCA bill. The Termination Fee could be assessed as a
lump sum for inclusion in the final CCA bill for customers leaving the CCA Program. There is
uncertainty whether PG&E would collect the Termination Fee if it were spread out and
29 Interest expense is estimated at 6%. Pae 119 of 204
71 April 2008
collected on a continuing basis after customers leave the CCA Program. PG&E has indicated its
willingness to discuss a servicing agreement for ongoing collection of the Termination Fee from
customers returning to PG&E service, assuming its costs are covered by the CCA Program, but
additional discussions would be needed to negotiate the specifics of the agreement. Although
PG&E is under no explicit obligation to collect ongoing CCA charges after a customer returns to
PG&E bundled service, there would be little justification, if any, for PG&E to refuse to provide
such a service to MCE, as long as PG&E is reimbursed for its costs of providing the service.
This is particularly true in the context of the statutory requirement for PG&E to fully cooperate
with community choice aggregators. There is also a good precedent for such an arrangement in
the case of load that has departed PG&E service for service by a municipal utility. In these
cases, PG&E has proposed that the municipal utility collect PG&E's departing load Cost
Responsibility Surcharges, analogous to the Termination Fee proposed here, on behalf of PG&E.
It is likely that Marin Clean Energy would obtain additional financing capability after it has
been operating successfully for a number of years and after the capital markets gain experience
and comfort with the CCA business model. If actual experience shows that customer attrition is
minimal, MCE should be able to finance investments with Iess stringent security requirements
(i.e., without the need for a Termination Fee). Additional investment by MCE would create
greater ratepayer benefits because power purchases would be displaced by production from
lower cost community owned resources. MCE may also be able to purchase a portion of its
renewable supplies from other public agencies without incurring additional debt, and if these
purchases can be made at cost, additional financial benefits beyond those shown in this
business plan can be obtained. MCE should initiate discussions soon after its formation to
explore opportunities for purchasing renewable energy financed by existing public agencies
such as NCPA, SCPPA, SUM, etc.
All financial pro formas prepared for this business plan assume that the debt service costs
associated with the renewable resource project, as well as all fixed and variable costs will be
recovered in the retail rates charged to the CCA Program customers. In addition, the financial
pro forma includes a debt service -coverage ratio of at least 1.25. Actual debt service coverage
ratios will be determined during the financing phase of the renewable resource project;
however, an increase in the coverage requirements, or increase in the total costs of the
renewable resource project (within reason) should not have a material impact on the overall
CCA Program.
The following table summarizes the potential financings in support of the CCA Program:
Proposed Financing Estimated Total Estimated Term
Amount
1. Start -Up and Working
Capital (Phase 1 and 2) $6.4 million No longer than 7 years
2. Working Capital (Phase
3) $15.8 million No longer than 5 years
3. Renewable Resource $475 million
20-30 yearsProject Financings (aggregate)
72
Estimated Issuance
Mid 2009
Late 2010
Late 2011
Page 120 of 204
April 2008
Sensitivities and Uncertainties
The primary focus of tlus section is to address the uncertainties and risks that could jeopardize
the ability of the Program to offer competitive rates and services to its customers. Any risks to
the Marin Communities themselves should be addressed by outside legal counsel retained by
the county and cities. Qualified legal counsel will be required to draft the formal governance
and program agreements and must make the ultimate determination of whether there would be
any residual risk • taken on by the Marin Communities through their participation in the
Program. The financing plan will also require review and input by legal counsel and
potentially investment bankers selected by the county and cities to confirm the ability to obtain
financing for the proposed Program.
A quantitative risk analysis will be included in a future revision or supplement to this business
plan. The following discussion provides an overview of the risks and uncertainties inherent in
implementing the proposed CCA program.
According to the Implementation Timeline described in Chapter 1, certain currently unknown
factors that impact the overall economic feasibility of the Program would be resolved before the
time the Marin Communities make the final decision to proceed with CCA implementation,
while other unknowns would continue after the program begins providing service to
customers. Factors that will be known prior to the final decision to proceed with CCA
implementation include:
➢ Participation in MCE by each City;
➢ The CPUC's actions, if any, on the Implementation Plan submitted by MCE; and
➢ Initial costs through 2013 for electric supply and customer account services.
It is presumed that the Marin Communities would not authorize the Program to begin unless
the costs offered by electric providers to MCE are low enough to enable the Program to offer its
desired level of renewable energy while charging rates to customers consistent with the rate
projections presented in this plan. Timing of the initial supply contracts will be critical because
the wholesale market moves up or down daily and the price swings could be enough to impact
the ability to offer competitive rates through the Program. For instance, a 5 percent increase in
market prices would increase MCE's annual cost by nearly $6 million, enough to turn a
projected surplus for 2011 into a deficit. The outcome of these unknowns will be factored into
the final -evaluation to be made prior to the time MCE would submit its registration materials to
the CPUC. These factors are therefore not Program risks per se, but are uncertainties that may
adversely impact the ultimate feasibility of going forward with the Program.
Other factors, listed below, will continue as uncertainties after implementation of the Program.
These variables can impact the program's costs or its competitive position relative to services
and rates offered by PG&E.
➢ The level of PG&E rates in general and for customers served by the CCA program in
particular;
➢ The Cost Responsibility Surcharge and rates for utility services provided to the CCA;
Page 121 of 204
73 April 2008
Future wholesale electricity prices;
➢ The precise costs and timing of future resource investments by MCE; and
➢ Customer opt -outs and turnover.
Once Marin Clean Energy locks in the price of its initial supply contract, the primary risk is that
market prices subsequently decline and PG&E increases the CRS in future years. MCE's costs
and rates would be largely predictable due to execution of long term contracts and renewable
resources investments, but customer rate impacts can only be known with certainty one year in
advance because the CRS is determined one year at a time. Furthermore, PG&E generation
rates are volatile and unpredictable; PG&E has been unable to accurately forecast its own
generation rates even on a year ahead timeframe. The most significant market -related risk to
the program's viability would be a period of sustained low electricity prices beginning after
MCE makes long term power supply commitments to renewable resources or other fixed priced
electric supplies. MCE's power supply costs would be relatively stable, but reductions in the
market prices of wholesale electricity would tend to increase the CRS charged by PG&E to
Program customers. Such declines would also tend to reduce PG&E's rates to some extent. If
prices for conventional electricity were to drop for a sustained period of time, the Program's
rates could be consistently higher than those offered by PG&E. Customers would bear the risk
of being obligated to pay MCE's rates or pay the Termination Fee to leave the program. MCE's
strong commitment to renewable energy resources could be more costly than anticipated on a
relative basis if fossil fuel prices were to experience steep declines in the future. This risk will
be evaluated through a scenario analysis that examines the rate impact of shifts in fossil fuel
prices, rather than year-to-year price volatility.
Year-to-year fluctuations in market prices would be of less concern if Program customers
perceive the rate impacts to be temporary; there are practical restrictions on customers
switching back and forth between CCA and utility bundled service. Customers electing to
return to the utility would by charged the Termination Fee by MCE and would be obligated to
remain with the utility for a three-year commitment pursuant to the Bundled Portfolio Service
conditions for returning customers set forth in the utility's tariffs. A departing customer would
also need to consider whether it may be foregoing future benefits provided by the CCA.
The other primary uncertainty is the future level of PG&E's generation rates that would
otherwise be paid by program customers. Small differences in the escalation rate of PG&E"s
generation rates would have significant impacts on the ability of the CCA Program to provide
ratepayer benefits. PG&E rates are impacted by market factors such as power supply costs but
are also significantly impacted by regulatory policies, which make the task of accurately
forecasting PG&E's rates extremely difficult. The forecast underlying this business plan projects
an average increase of 3.5 percent per year in PG&E's generation rates, which is relatively low
by historical standards. The average annual increase in PG&E's electric rates has been 4.1
percent since 1980 and 5.2 percent since 2000. However, PG&E adjusts its rates at least
annually, and actual PG&E rates will only be known with the benefit of hindsight.
Faced with the fact that rate comparisons beyond one year are inherently uncertain, public
decision makers need to consider the range and likelihood of the potential outcomes if the
decision to offer a CCA program is made. Page 122 of 204
74 April 2008
Other Risks and Uncertainties
Other uncertainties impacting the overall business environment in which the program would
operate include two regulatory and legislative changes:
➢ The impact of AB32, the Greenhouse Gas Reduction law; and
➢ The impact of PG&E's advanced metering infrastructure program.
AB 32
AB 32 imposes a statewide requirement to reduce greenhouse gas emissions by 25 percent by
2020. The rules governing particular industries have yet to be determined, and it is not possible
at this time to predict AB 32's impact on PG&E or the CCA program. It is possible that AB 32
will further drive up demand for renewable energy resources and make early renewable energy
investments by MCE that much more attractive. PG&E rates may increase more than projected,
and MCE may be able to financially benefit (offer lower rates) by trading emissions reductions
achieved through the CCA. On the other hand, AB 32 may motivate PG&E to increase its
renewable energy procurement, and the increased demand for renewable resources could
reduce supplies available to MCE or leave only the least economic resources available. PG&E's
rates would be expected to increase as well. A subsequent analysis should be performed once
the implementing regulations have been established.
It is too soon to predict what the financial impacts of AB32 will be and what changes, if any,
will be made by PG&E in its future resource procurements. At this point in time, the impact of
AB32 should be considered primarily from a policy perspective; i.e., if the state is successful in
achieving the greenhouse gas reductions mandated by AB32, is there still a need for direct
action by the Marin Communities to promote renewable energy? How confident are the county
and cities that actions by the state will be effective? Are the benefits of local control and
reduced rates sufficient to outweigh the risks of implementing a CCA? These questions can
only be answered by leaders of the Marin. Communities and community members following a
thorough consideration of the CCA business plan.
Advanced Metering
The plan for PG&E to install advanced metering for all customers, including all 3.5 million
residences in PG&E's service territory, creates risks and opportunities for the CCA program.
From the risk perspective, advanced metering enables PG&E to offer additional rate options
such as critical peak pricing tariffs that may benefit customers located in the Marin
Communities. Such options could make it more difficult to for the CCA program to compete
with PG&E, unless the CCA offers similar rate options. Moreover, PG&E's critical peak pricing
tariffs could have the effect of subsidizing electric customers in the Marin Communities because
there is very little air conditioning use in the area, and Marin customers would likely benefit
from enrolling in the critical peak pricing rate without changing their consumption patterns
(free ridership). From the opportunity perspective, universal deployment of advanced meters
would make it possible for MCE to procure electricity based on the actual load profile of
customers enrolled in the program as opposed to the current system of using typical customer
class 'load profiles" estimated based on statistical samples. Using actual load profiles rather
than the PG&E class average load profiles should reduce MCE's peak capacity and energy
Page 123 of 204
75 April 2008
requirements and thus reduce overall electricity procurement costs. This is another area where
additional analysis maybe warranted as PG&E's plans are implemented.
Page 124 of 204
76 April 2008
-
•'n:
a in s na:rr�
Introduction
This Chapter describes the initial policies proposed for Marin Clean Energy in setting its rates
for electric aggregation services. These include policies regarding rate design, objectives, and
provision for due process in setting Program rates. This section also.presents a comparison of
preliminary program rates to the distribution utility rates projected to be in effect at Program
initiation. Final Program rates would be approved by the Board and included in the initial
customer opt -out notices.
MCE's Board of Directors would approve the rate policies and procedures set forth in MCE'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
MCE 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 MCE, 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 MCE would provide to
participating customers. For participants in MCE's Light Green Tariff, the goal would be for
MCE's rates to be equivalent to the generation rates offered by PG&E. For participants in
MCE's 100 percent Green Tariff, the goal would be to offer the lowest possible customer rates
with an incremental monthly cost increase of 10 percent or less.
Competitive rates will be critical to attracting and retaining key customers, especially the high
margin commercial and industrial customers enrolled during Phase 2 that would provide the
majority of the program's revenues. As discussed above, the principal long-term program goal
is to achieve 100 percent renewable energy supply subject to economic a o J2� g
77 April2008 U
constraints. As previously discussed, the program will significantly increase renewable energy
supply to program customers, relative to the incumbent utility, by offering two distinct rate
tariffs. The default tariff for program customers will be the 100 percent Green Tariff, which will
supply participating customers with 100 percent renewable energy supply at rates that reflect
the program's cost for procuring necessary energy supplies. MCE will also offer its customers a
Light Green Tariff, which will maximize renewable energy supply (25 percent in 2010,
increasing to 51 percent by 2014) while maintaining generation rates that are equivalent to
PG&E. 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
more than 80 percent in 2014. This estimate is based on informal discussions with potential
suppliers. The ability to meet this objective will be confirmed once firm bids are received from
third party suppliers.
For the post implementation period, beginning in 2014, it is anticipated MCE will begin
utilizing electricity produced by the proposed community wind and biomass projects, and this
will help to reduce the program's supply costs and customer rates.
Rate Stability
MCE would 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 MCE's rates would 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. MCE would have more
flexibility in procurement and ratesetting than PG&E to stabilize electricity costs for customers.
Equity among Customer Classes
MCE's policy would 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 MCE'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).
Page 126 of 204
78 April 2008
Revenue Sufficiency
MCE's rates must collect sufficient revenue from participating customers to fully fund MCE's
annual budget. Rates would be set to collect the adopted budget based on a forecast of electric
sales for the budget year. Rates would be adjusted as necessary to maintain the ability to fully
recover all of MCE's costs, subject to the disclosure and due process policies described later in
this chapter.
100 percent Renewable Energy Delivery — "100 percent Green Tariff'
Because the Marin Communities have expressed an interest in increasing the supply of
renewable energy as soon as practical, MCE proposes to create a Green Tariff, which would
allow interested customers to procure and receive 100 percent renewable energy supply. The
100 percent Green Tariff would be MCE's default tariff, unless a customer of the program elects
to participate in the Light Green Tariff option. As previously noted, 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. Achieving high levels of
participation in such a tariff require a well-developed marketing effort by MCE to promote this
opportunity. Due to the relatively high cost per kWh of renewable power under current market
conditions, a 100 percent Green Tariff of this sort would necessarily impose a per -kWh
premium for all energy delivered to participating customers. The premium would generally
range from 1.5 to 2.0 cents/kWh above the basic tiered tariff for each customer class. Such a
premium would result in an incremental monthly cost increase of $7.50 to $10.00 for a customer
using 500 kWh/month, but would supply each participating customer with 100 percent
renewable energy, approximately double the level of renewable energy supplied through
MCE's Light Green Tariff option and at least five times the renewable energy offered by PG&E.
The actual premium charged in relation to the 100 percent Green Tariff would be based on the
current cost of renewable energy supply incurred by MCE and may vary slightly from the
guideline noted above.
By developing a 100 percent Green Tariff alternative for program customers, it is estimated that
MCE's renewable energy supply, expressed as a percentage of total energy supply, would
increase to a level above 80 percent by 2014 (the fifth year of program operations). The extent to
which this percentage may be increased is ultimately dependent upon the marketing efforts of
MCE and the willingness of customers to incur an incremental cost increase for program
service. Based on responses to the Marin County 2007 Resident Satisfaction Survey and likely
increases in 100 percent Green Tariff participation resulting from effective marketing efforts of
the program, it appears that the program could achieve more than 80 percent renewable supply
by 2014. Additional market research should be conducted to refine the participation
assumptions.
Rate Design
Marin Clean Energy's rate designs would, at least initially, generally mirror the structure of
PG&E's generation rates so that similar rate impacts can be provided to MCE'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. MCE's rates would similarly follow a five -tier structure. Rates for other customer
Page 127 of 204
79 April 2008
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). MCE would
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 MCE's program. MCE may also introduce new rate options for
customers, such as rates designed to encourage economic expansion or business retention
within MCE's service area.
One proposed rate design approach would apply an equal percentage discount, if applicable, to
the otherwise applicable rate for all of the various rate schedules offered by PG&E. All
customers, including low use residential and customers receiving low income discounts would
receive the same rate benefit on a percentage basis. While simple in concept, this approach
implies a fairly complicated rate structure for MCE as it matches the rate structures used by
PG&E. PG&E's optional "rate ready" billing service, where PG&E calculates bills using MCE's
rates, could not be utilized because PG&E limits the complexity of the CCA rate structure it will
accommodate for this service 3o It would also tend to price services to some customers or
during certain time -of -use periods below MCE's actual cost of providing service. For example,
a low use residential customer that used only the minimal baseline usage in a month currently
pays less than five cents per kWh for generation services, which is below the cost of purchasing
the power from the wholesale market. If MCE discounted all rates equally, MCE's rate would
also be below its costs.
The proposed equal benefits rate design is recommended in order to facilitate easy rate
comparisons and provide for a smooth transition of customers from PG&E service to CCA
service. MCE would have discretion to modify its rate design policies, and it is likely that over
time MCE's rate design would become less tied to those offered by PG&E.
An alternative rate design approach would primarily consider cost of service in setting
customer rates and establish a cost based floor below which rates would not be set. MCE may
also simplify rate structures, for instance by eliminating demand charges or
reducing/eliminating the residential tier rate structure. Rate comparisons would then vary on a
customer -by -customer basis and some customers who MCE can not cost-effectively serve
would have the incentive to remain with PG&E. Such an approach would allow for greater rate
benefits for the customers that join the program because they would no longer be subsidizing
others. A simpler, more cost based, rate structure would be easier to administer as well. The
downside is that the Program would not provide equal benefits to all customers. The initial
customer communications effort would be complicated by the inability to provide rate
comparisons that would be meaningful and accurate for 'all customers. Rates for typical
customers of each class could be easily compared, but individual customer rate impacts would
vary. It should also be understood that a more cost based rate structure would generally favor
the commercial and industrial customer classes relative to residential and small commercial
customers, and the Program could be faulted for using rate design to exclude small users, even
30 Notwithstanding the fact that the proposed rate design approach would utilize the identical rate structures that
PG&E uses to bill its own customers. Page 128 of 204
80 April 2008
if that is not the intent.31 A fully cost -based rate design would not be consistent with a goal of
maximizing customer participation and providing benefits to all ratepayers. As previously
noted, the program anticipates an initial rate structure equivalent to that of PG&E. Over time,
MCE may elect to incorporate one of the previously described rate design proposals.
Net Energy Metering
Customers with on-site generation eligible for net metering from PG&E would be offered a net
energy metering rate from MCE. 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 MCE's net energy metering tariff would apply to the generation
component of the bill, and the PG&E net energy metering tariff would apply to the utility's
portion of the bill. To the extent that current CPUC regulations governing provision of net
energy metering to CCA customers are unclear, MCE would work with PG&E and the CPUC to
establish a net energy metering tariff that accomplishes this objective.
Rate Impacts
The projected rates shown below would require a price for full requirements electric supply of
approximately 8.8 cents per kWh. These rates are illustrative, and the ability to offer the
targeted rate discount must still be confirmed through the RFP process described in Chapter 6.
Marin Clean Energy Estimated 2011 Program Rates
Customer Class
Program Rates —
Program Rates --
PG&E Generation
Green
Light Green
Rate
(Cents Per kWh)
(Cents Per kWh)
(Cents Per kWh)
Residential
11.3
9.4
9.4
Small Commercial
11.5
9.6
9.6
Medium
11.1
9.3
9.3
Commercial
Medium Industrial
10.2
8.5
8.5
Large Industrial
9.7
8.1
8.1
Agricultural
9.5
7.9
7.9
Street and Area
9.7
8.1
8.1
!I Lighting
PG&E rates are based on those contained in Advice Letter No. 3115 -E-A (Effective January 1, 2008), escalated by
3.5% per year.
Individual customers within rate classes may pay higher or lower average rates than those
shown above depending on their electricity usage and load profile as is the case with PG&E.
MCE's rates shown include all costs expected to be incurred by MCE related to the aggregation
program, including power supply costs, operations and administration costs, reserves, and
31 MCE could offer rate discounts or other forms of assistance (e.g., energy efficiency programs) to certain customer
populations that might otherwise be disadvantaged by a more cost based rate structure. Page 129 of 204
81 April 2008
billing and metering fees charged by PG&E to MCE. For the sake of comparison, MCE's rates
are shown inclusive of the cost responsibility surcharges that MCE's customers will pay directly
to PG&E. Program rates for the Light Green Tariff are designed to provide participating
customers with rate equivalency to PG&E.
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 .Executive Director, with support of the Energy Commission described in
Chapter 2, would 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 would 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 would be able to provide
comment on the proposed rate changes.
MCE would initially adopt customer noticing requirements similar to those the CPUC requires
of PG&E and SCE. 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 MCE as are specified
in the notice, and shall state the locations of such offices.
Within forty-five days after the submitting an application to increase any rate, MCE 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 MCE 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.
Projected revenues from energy sales to the primary customer classes to be served by MCE are
shown in the following chart:
Page 130 of 204
82 April 2008
$21,734,676
Projected 2011 Revenues by Customer Class (Dollars)
$549,460
$68,459,083
® Residential 0small Commercial 11 Medium Commercial El Large Commercial
BIndustrial MStreet Lighting MAgrlcultunl
Customer Rights and Responsibilities
This section discusses customer rights, including the right to opt out of the Program, as well as
obligations customers undertake upon agreement to enroll in the aggregation Program. It
includes a preliminary methodology for determining fees that would apply to customers who
terminate service after the initial free opt -out period. All customers that do not opt out within
60 days of enrollment (after having received four opt -out notices) will have agreed to become
full status Program participants and must adhere to the customer obligations that would be set
forth in MCE's adopted Implementation Plan.
Customer Notices
At the initiation of the customer enrollment process, a total of four notices would 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. Marin
Clean Energy would 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, MCE 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. ane
83 P Aril NO 204
•
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 enrollment would result in customer transfer to utility service with no penalty.
Such customers will be obligated to pay MCE'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 MCE.
New customers who establish service within the Program service area would be automatically
enrolled in the Program and would have sixty days from the date of enrollment_to opt out of the
Program. Such customers would be provided with two opt -out notices within this sixty-day
post enrollment period. MCE's Board of Directors would have the authority to implement entry
fees for customers that initially opt out of the Program, but later decide to participate. Entry
fees would help prevent potential gaming, particularly by large customers, and aid in resource
planning by providing additional control over the Program's customer base. Entry fees would
not be practical to administer, nor would they be necessary, for residential and other small
customers.
Termination Fee
Customers that are automatically enrolled in the Program can elect to transfer back to the
incumbent utility without penalty wilhin the first two billing cycles of service. After this free
opt -out period, customers would be allowed to terminate their participation subject to payment
of a Termination Fee. The Termination Fee would 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 would apply.
Program customers that move out of the Program's service territory would not be subject to the
Program's Termination Fee.
The Termination Fee would 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 MCE is unable to recover the costs. of supply
commitments attributable to the customer that is terminating service. PG&E would collect the
Administrative Fee from returning customers as part of the final bill to the customer from the
CCA Program and would collect the Cost Responsibility Charge (CRC) as a lump sum or on a
monthly basis pursuant to a negotiated servicing agreement between MCE and PG&E.
The Administrative Fee would vary by customer class as set forth in the table below.
84
Papp 12008 204
Administrative Fee for Service Termination
Customer CIass
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 MCE'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 MCE's Governing Board as part of the annual ratemaking process.
The long-term financial projections contained in Appendix A indicate that MCE may be able to
offer rates that are generally below those charged by PG&E and that MCE's supply portfolio is
projected to be competitive in the marketplace because of the financing advantages that MCE
enjoys. Under those conditions, most customers would not be expected to terminate their
service with MCE to return to the utility. Furthermore, if customers do terminate service, MCE
should be able to re -market the excess supply and fully recover its costs. Although the Cost
Recovery Charge will likely not be needed for recovery of stranded costs, MCE'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 MCE 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 would likely need to post
cash collateral to match its credit exposure to the Program's electric supplier(s).
The circumstance that would trigger application of the CRC would be if PG&E rates
unexpectedly drop below those of MCE and customers wish to leave the Program to return to
PG&E. In that scenario, the CRC would reduce some of the customer benefits from switching
back to PG&E.
Once finalized, the Termination Fee should 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 MCE's Board of
Directors, subject to MCE'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
s5
Page i z 08 f 204
P
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
MCE would establish policies covering confidentiality of customer data. MCE's policies should
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 MCE's discretion or as required by
law or regulation.
Responsibility for Payment
Customers would be obligated to pay MCE charges for service provided through the date of
transfer including any applicable Termination Fees. Pursuant to current CPUC regulations,
MCE would not be able to direct that electricity service be shut off for failure to pay MCE'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 witlun 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
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 MCE's Board based
on experience or regulatory changes that would provide MCE 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 MCE'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
MCE'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.
86 Pa7!pril 008 204
-
.... ...........:....... ....: . ... .. ... . ... ....5 1.x.4 ......,....k
This Chapter presents the key elements of a proposed marketing plan for Marin Clean Energy,
including the promotion of its 100 percent Green Tariff to community businesses and residents
as well as necessary program staff to administer these activities.
Customer Services
As referenced in the Organizational Plan, Chapter 2, the Marin Clean Energy will have seven
full-time staff or contractors focused on Sales and Marketing functions at full program
implementation Qanuary 2011). These individuals will be responsible for organizing and
administering general program communications, customer service and representation for key
accounts. Sales and Marketing personnel will also be tasked with implementing a marketing
strategy to promote customer satisfaction with the CCA program and developing marketing
materials, including bill inserts and a program website for MCE.
A significant focus of this marketing strategy will be to secure and retain the participation of
large customers in the CCA program. It is assumed that most residential customers will be
compelled to participate in the CCA program based on MCE's significant commitment to
renewable energy delivery and carbon emissions reductions with a pricing option that offers
rate parity with the incumbent utility, PG&E. While these may also be compelling reasons for
some large energy users to participate in the CCA program, others may require additional
incentives to engage in this new business relationship. The following section describes potential
incentives that could be provided to these large customers to promote participation in the
program and, potentially, the Green Power Tariff.
Partnering wit11 Large Customers
Large energy customers, particularly businesses falling into the general rate classifications of
"Commercial" and "Industrial," comprise a significant portion of the electric load within the
Marin Communities (Commercial customers account for 42 percent of the Marin Communities'
electric load; Industrial customers account for 5 percent of total load). To ensure that these
accounts remain customers of MCE, it will be important to identify ways in which MCE can add
value to these businesses as an energy supplier. For many of these large customers, rate
stability and/or an increased commitment to renewable energy supply may be compelling
reasons to procure energy from MCE. For other large customers, additional incentives may be
necessary to encourage a new business relationship with MCE. In these instances, it will be
incumbent upon MCE to develop programs that provide adequate incentives for large energy
users to proceed as customers of the CCA.
Because most of these large energy users are producing, selling or distributing goods and/or
services, MCE may choose to focus on developing marketing materials, such as a logo or seal,
that could be displayed on product packaging, letterhead, buildings, corporate vehicles or in
other prominent areas, which would inform customers of each business' commitment to
renewable power supply and carbon emissions reductions as a customer of Marin Clean
Energy. While the specific graphics and/or verbiage displayed on this logo would need to be
87 Paed13(%pf 204
developed by MCE, such a logo would likely display the following general message: "Proud
Renewable Energy Partner of Marin Clean Energy." A logo or seal of this sort, used under a no -
cost licensing agreement with MCE, would differentiate certain businesses and their products
from those that did not share the same commitment to renewable power delivery and carbon
emissions reductions. This distinction may be viewed by businesses as an important marketing
mechanism within the Marin Communities.
In concert with this branding opportunity, MCE could also include a "Business Partners"
registry on its website to provide recognition for those businesses that have chosen to proceed
with CCA service and the commitment to renewable power delivery and carbon emissions
reduction. Business Partners of MCE, in addition to name recognition of MCE's website, might
also be given the option to have their contact information displayed to facilitate commerce
between residents and other businesses. Such a resource will become a reference point for
residents and other businesses within the Marin Communities as they attempt to identify
potential vendors that share their commitment to the environment.
Similarly, MCE could develop a second logo or seal for large energy customers who choose to
participate in its 100 percent Green Tariff (discussed in Chapter 5). As in the previous example,
use of this logo would be permitted under a no -cost licensing agreement for participants in
MCE's Green Power Tariff. Due to the increased cost incurred by participants in the 100
percent Green Tariff, MCE may choose to further distinguish this logo or seal by clearly
displaying verbiage such as, "Powered by 100 percent Green Energy -- Delivered from Marin
Clean Energy." Many businesses may find that the rate increase incurred as a result of
participating in MCE's 100 percent Green Tariff will be recoverable through nominal increases
in product or service pricing. In fact, it seems reasonable to assume that many residents and
businesses within the Marin Communities would actively seek out businesses that have made
this additional commitment to renewable power delivery and reduced environmental impact.
In fact, MCE may choose to provide these Business Partners with additional and prominent,
recognition for their participation in the 100 percent Green Tariff by displaying
corporate/business logos on the "Home Page" of MCE's website and/or on other marketing
materials, such as pamphlets and bill inserts.
Ultimately, the willingness of a large energy customer to receive electric generation service from
the CCA will be significantly improved by MCE offering a recognizable means by which these
Business Partners can differentiate themselves from other businesses that may elect to opt -out
of the program. As a result of the Marin Communities' progressive stance on carbon emissions
reduction and renewable power development/delivery, highlighting the commitment of
Business Partners to proactively addressing these issues should provide a competitive
advantage relative to other businesses within the Marin Communities. Such a competitive
advantage may likely increase demand for the products and services offered by these Business
Partners.
88 Page j ,% W 204
104
Introduction
Introduction
This Chapter describes Marin Clean Energy's initial procurement policies and the key third
party service agreements by which MCE would obtain operational. services for the CCA
Program. MCE's Board of Directors would approve its general procurement policies set forth in
an adopted Implementation Plan to be effective at Program initiation. The Board of Directors
would retain authority to modify program policies from time to time at its discretion.
Procurement Methods
MCE would enter into agreements for a variety of services needed to support program
development, operation and management. It is anticipated MCE would 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.
MCE would 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 MCE's Executive Director or Board of Directors.
The Executive Director would 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 would generally mirror the authority for entering into the
agreements.
Procurement at Startup
The operational services needed for the program will be competitively procured. To date, the
Marin Communities have utilized information received by the SJVPA and the East Bay
Communities in response to their non-binding requests for information. These responses
provided valuable information regarding seller qualifications as well as indicative cost
proposals for energy supply and certain customer service related functions. The indicative
pricing information provided by respondents to these requests for information has been
incorporated in this business plan. These responses have also provided useful information
about resource availability and costs, particularly for renewable energy resources.
Assuming MCE is formed, a binding request for bids would be issued some time in early 2009
to solicit bids for electric supply and customer account services needed for program operations.
Firm energy price bids will be solicited for at least the first four years of operations. The
selected supplier will be required to have extensive operational experience and must maintain
an investment grade credit rating to minimize risks of default. The supplierPjaillebT�spATle
89 pril 2008
for managing the electric supply portfolio on behalf of MCE and will be required to meet the
renewable portfolio requirements specified by MCE as well as other applicable regulatory
requirements such as those pertaining to resource adequacy. During this period, the bulk of the
risks will be borne by the third party supplier under a "full requirements" electric supply
contract.
As a result of the competitive solicitation, electric supply costs will be known for the first four
years of program operations based on the firm bids offered by the selected supplier. Bids for
customer services needed for the Program (Customer Account Services) will also be solicited.
Me evaluation of whether to proceed with implementation will therefore incorporate known
costs for approximately 95 percent of total program costs for the first four years, providing
relative certainty regarding the ability to provide competitive rates. Based on the firm bids, a
determination will be made regarding whether the program can achieve its desired renewable
energy targets while offering generation rates that are competitive with PG&E during the
implementation period. If the program cannot provide competitive rates, a determination
would be made whether to adjust the timing for implementation or terminate the program
altogether.
Key Contracts
Electric Supply Contract
For the initial four years of program operations (1/1/2010 through 12/31/2013), a third party
energy services provider would supply electricity to customers under a full requirements
contract. Under a full requirements contract, the supplier commits to serve the total electrical
loads of customers in the CCA Program. The supplier is responsible for ensuring that a
certified Scheduling Coordinator schedules the loads of all customers in the program and is also
responsible for obtaining meter data from PG&E to submit to the CAISO settlement process.
The supplier is wholly responsible for the portfolio operations functions and managing all
supply risks for the term of the contract. The supplier must meet the Program's renewable
energy goals and comply with all resource adequacy and other regulatory requirements
imposed by the CPUC or FERC. The contract may further provide for the integration of
resources that may be procured separately by the Program.
Risks related to customer opt -outs and changes in program loads during the term of the
agreement would be borne by the supplier unless alternative arrangements are agreed to during
negotiations. The supplier should be given the opportunity to charge different prices for sales
to the various customer classes to help mitigate opt -out risks related to uncertainty in the load
profile of the final customer mix.
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 the program's target of 56 percent
in 2010, increasing to 70 percent in 2013, adjusted as necessary for actual customer participation.
Page 138 of 204
90 April 2008
Data Management Contract
A data manager would provide the retail customer services of billing and other customer
account services (EDI with PG&E, billing, remittance processing, 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 would be selected to
perform all of the data management functions32
The data manager is responsible for the following services:
➢ Data exchange with PG&E;
➢ Technical testing;
➢ Customer information system;
A 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
MCE greater flexibility to change energy suppliers, if desired, without facing an expensive data
migration issue.
It is anticipated that MCE will issue a binding request for bids some time in early 2009 for data
management services. A short list of potential energy suppliers and data management
providers selected as a result of this process will reflect a highly qualified pool of suppliers for
further negotiations, which will be completed prior to registration of the CCA.
32 The contractor performing account services may be the same entity as the contractor supplying electricity for the
program. Page 139 of 204
91 April 2008
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Introduction
This Chapter describes the process to be followed in the case of Program termination. In the
unexpected event that MCE 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.
Termination by Marin Clean Energy
Marin Clean Energy would plan 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 Councils) decide to terminate MCE/program,
each governing body would be required to adopt a termination ordinance or resolution and
provide adequate notice to MCE (such as 90 days). Following such notice, MCE would vote on
its termination subject to a two-tiered vote, as previously described. 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. In recognition of this possibility, all contracts
executed by the Board will include terms and conditions addressing the resolution of any
.remaining contractual obligations of the Board (such as contract buyouts, termination
payments, contractual assignments, etc.).
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 MCE 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.
MCE would 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. The CPUC currently has established a maximum
interim CCA bond amount of $100,000 to cover potential reentry fees. The CPUC will be
evaluating the appropriate bonding requirements in a future rulemaking.
Page 140 of 204
92 April 2008
Termination by Members
The JPA Agreement will define the terms and conditions under which Members may terminate
their participation in the program. As described in the proposed governance principles
(Chapter 2), a JPA Member would be able to withdraw from the program upon 60 days written
notice prior to the expiration of each fiscal year (July 1). The Members withdrawal would then
become effective one full fiscal year later, an effective 14 -month notice requirement. The
withdrawing party would also be subject to all reasonable ongoing costs incurred by MCE on
behalf of that entity. In this case, a vote of the Board would not be required to affect Member
withdrawal. Furthermore, the municipal load of a Member withdrawing from the JPA would
no longer be served by MCE, however, the non -municipal accounts (such as residential,
commercial and industrial accounts) would remain customers of MCE and would continue to
receive electricity procured by MCE on their behalf. Because these non -municipal accounts
would remain customers of MCE, the withdrawing Member would continue to provide a Board
representative from among its elected officials to ensure that the interests of its constituents are
represented during policy-making decisions of the Board.
Conversely, if a Member desired to remove its future non -municipal accounts from Marin Clean
Energy service while retaining service for its municipal accounts, Board approval based on
either of the aforementioned two-tiered voting structures would be required. In t1 -is instance,
any existing non -municipal accounts would continue to receive electric service from MCE; only
future non -municipal accounts would be affected. Only in the event that the JPA agrees to
disband would the requirement of Board representation by all Members cease.
93
Pap HI 2008 f 204
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Appendix A: Pro Forma 2014 — 2025
Appendix B: Energy Efficiency Potential in the Marin Communities
Appendix C: List of Acronyms and Definitions
94 Pae 142 20ogf 204
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Appendix B — Energy Efficiency Potential in the Marin Communities
Section 1— Introduction
1.1 Overview
This report supports Marin's planning efforts to implement a Community Choice. Aggregation
(CCA) program within its proposed service territory. Demand-side resources form a part of the
CCA's resource portfolio, consistent with the treatment of energy -efficiency and demand-side
management alternatives within the resource portfolios of California's major investor-owned
electric utilities (IOU). This energy efficiency potential forecast serves as a means to estimate the
scope and types of energy efficiency programs Marin might include within its resource portfolio
within the following customer segments:
Residential — Low -Income and Multi -Family
Residential
Commercial/Small Commercial
Large Commercial/Industrial
Preliminary program planning is prepared based on the conduct of an energy efficiency forecast
that employs key assumptions and methodologies adopted by IOUs, tailored to Marin'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.
As related above, the forecast cites program achievable energy efficiency impacts within the
Marin customer base. How these impacts are achieved would be based upon how programs are
planned, implemented and verified by the serving distribution utility, PG&E, or by the CCA
Program, consistent with CCA enabling legislation.
1.2 Approach
The method used for estimating potential is a "bottom-up" approach in which energy efficiency
costs and savings are assessed at the customer segment and energy -efficiency measure level.
Cost-effective program savings potential is estimated as a function of measure economics, rebate
levels, and program marketing and education efforts.
1.3 Study Scope
This energy efficiency potential forecast prepared for Marin's service territory and assesses
electric energy efficiency potential in the residential, commercial and industrial sector existing
construction markets. This market includes both retrofit and replace -on -burn -out measures; it'
explicitly excludes new construction and major renovation markets. The study assesses
achievable potential savings over the near-term and is restricted to energy efficiency measures
and practices that are presently commercially available. In addition, this study is focused on
96 Page A 4°20084
P
measures that could be relatively easily substituted for or applied to existing technologies on a
retrofit basis. As a result, measures and savings that might be achieved through integrated
redesign of existing energy -using systems, as might be possible during major renovations or
remodeIs, are not included.
The scope of the forecast focuses on cost-effective programs that can be planned and
implemented to yield the maximum efficiency gains in the near-term. As shown in the following
table, 85 percent of energy efficiency potential resides in existing building retrofit programs for
residential, commercial and industrial customers 33
Table 1-3 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%
1.4 Report Organization
The remainder of this report is organized as follows:
Section 2 presents forecast methods and scenario assumptions
Section 3 cites report information sources
Attachment A Sector Energy Efficiency Measures
Attachment B — Industrial Sector Incentive Percentages of Measure Costs
Attachment C — Avoided Cost Assumptions
Section 2 — Methods and Scenario Assumptions
This forecast applies information taken from a variety of sources listed under Section 3 Sources
below.
2.1 Defining Energy Efficiency Potential
Energy efficiency potential studies were popular throughout the utility industry from the late
1990s through the mid-1990s. This period coincided with the advent of what was called least -cost
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
Page 145 of 204
97 April 2008
or integrated resource planning. Energy efficiency potential studies became one of the primary
means of characterizing the resource availability and value of energy efficiency within the overall
resource planning process.
This study defines several different types of energy efficiency potential: namely, technical,
economic and achievable program. These potentials are described below:
Technical potential, defined as the complete penetration of all measures analyzed in applications
where they were deemed technically feasible from an engineering perspective.
Economic potential, defined s the technical potential of those en energy -efficiency measures that
are cost-effective when compared to supply-side alternatives.
Achievable program potential, the amount of savings that would occur in response to specific
program funding and measure incentive levels
Naturally occurring potential is the amount of savings estimated to occur as result of normal
market forces absent programmatic intervention. For the purposes of this forecast prototypical
net -to -gross ratios34,35 were used to account for naturally occurring measure adoption and
program free -ridership as follows:
Residential: 80 percent (all other residential programs)
Commercial: 80 percent (all other nonresidential programs)
Industrial: 80 percent (all other nonresidential programs)
2.2 Summary of Analytical Steps
This energy efficiency forecast was performed on the conduct of a number of basic analytical
steps to produce estimates of the energy efficiency potentials introduced above. The key
analytical steps conducted are:
Step 1: Develop Initial Input Data
Step 2: Estimate Technical Potential
Step 3: Estimate Economic Potential and Supply Curves
Step 4: Estimate Achievable Program Potential
Step 1: Develop Initial Input Data
Development of Measure List (Attachment A)
Residential Sector: The list of measures was developed by starting with measures included in the
referenced residential sector energy efficiency potential study 3c Two major changes were
incorporated into this initial list of measures: (1) Compact Fluorescent Lamp (CFL) types and
sizes were expanded from three generic CLF applications to eight, varying by ranges of wattage
m Rulemaking 01-08-028, Decision 05-04-051, Attachment 3 — Energy Efficiency Policy Manual — Version 3,
CPUC, April 2005
35 E3 program cost-effectiveness calculator version 3b5
36 California Statewide Residential Sector Energy Efficiency Potential Study, KEMA-XENERGY, April 2003
Page 146 of 204
98 April 2008
and fixture configuration, and (2) heating ventilation and air conditioning measure efficiencies
were adjusted to align with new the new federal efficiency standards 37
Commercial Sector: The list of commercial sector measures were developed by reconciling the list
of measures presented in two key commercial sector potential studies38 updated to reflect new
federal efficiency standards.39
Industrial Sector: Industrial sector measure data were provided by Lawrence Berkeley National
Laboratories as presented in a recently completed industrial sector energy efficiency potential
forecast.90
Gather and Develop Measure Technical Data (costs and savings) on efficient measure
opportunities41
Gather, Analyze and Develop Building Characteristics: Information includes such building
characteristics as number of households, building type square footage, and electricity
consumption and intensity by end use, end-use consumptive load patterns, market shares of
baseline efficiency electric consuming equipment, and market shares of energy efficient
technologies and practices 92
Step 2: Estimate Technical Potential
Estimating Technical Potential is accomplished using the following core equation:
Measure Total Base Case Applicability Incomplete Feasibility X Savings
Technical Potential - Square Feet X Equipment EUI X Factor X Factor X Factor Factor
kWh/ft2
where:
3710 CFR 430.32 Residential Air Conditioners and Heat Pumps and 10 CFR 431.97 Commercial Minimum
Cooling and Heating Efficiency Standards
39 SW039A California Statewide commercial Sector Energy Efficiency Potential Study, Xenergy, May 2003
and PGE0252.01 California Energy Efficiency Potential Study, Itron, May 2006
39 Ibid. (footnote 3)
40 PGE0252.01 California Industrial Existing Construction Energy Efficiency Potential Study, KEMA, May
2006
412004-2005 Database for Energy Efficient Resources, Version 2.01, California Public Utilities Commission
(CPUC) and California Energy Commission, November 2005 — Certain measure savings, i.e., lighting
measures were derived using segment specific engineering calculations
42 Household percentages for age and type are derived from 2000 US Census escalated through 2005 using a
CAGR of 3.78 percent and applied to County's residential customer count; commercial floor space is
projected using segment whole building energy intensity in kWh/ft' are from CEC-0400-2005-036 Energy
Demand Forecast, California Energy Commission, June 2005 and Manufacturing Energy Consumption
Survey (MECS), US DOE EIA, 2002; baseline market shares, energy efficiency technologies market shares
and equipment densities are taken from energy efficiency potential studies (Section 7 Sources); lighting
technology densities were create based on activity specific foot candle and lighting power density
requirements.
Page 147 of 204
99 April 2008
Square Feet: The total floor space for all buildings in the market segment. For residential analysis
the number of dwelling units is substituted for square feet.
Base -case Equipment Energy Usage Intensity (EUI): The energy use per square foot by each base-
case technology in the market segment. This is the consumption of the energy -using equipment
that the efficient technology replaces or affects.
Applicability Factor: The fraction of floor space (or dwelling units) that is applicable for the
efficient technology in a given market segment.
Incomplete Factor: The fraction of applicable floor space (or dwelling units) that is not yet
converted to the efficient measure (1.0 minus the fraction of floor space that already has the energy
efficiency measure installed).
Feasibility Factor: The fraction of the applicable floor space (or dwelling units) that is technically
feasible for conversion to the efficient technology from an engineering perspective.
Savings Factor: The reduction in energy consumption resulting from application of the efficient
technology.
Step 3: Estimate Economic Potential and Supply Curves
Economic Potential: As introduced in Section 2.2 economic potential is the technical potential of
those energy conservation measures that are cost effective when compared to supply-side
alternatives. The Total Resource Cost (TRC) test -03 is applied to assess cost effectiveness. Expressed
as a benefit cost ratio, measure benefits are divided by program and participant costs, and must
yield a ratio greater than 1.0 to be considered cost-effective. Benefits are the net present value of
avoided supply costs (Avoided Cost Assumptions, see Attachment C). Incentives are treated as
transfer payments and are not considered in the TRC cost test.
EnerV7 Efficiency Supply Curves: Energy efficiency supply curves graph the amount of savings
that could be achieved at each level of cost, built up across individual measures. Efficiency
measures are sorted on a least -cost basis, total savings are calculated incrementally with respect
to measures that precede them. Supply curves typically reflect diminishing returns, i.e., costs
increase rapidly and savings decrease toward the end of the curve. Supply curves help to answer
the question "How much savings can be achieved, at what cost, by implementing which
measures?"
Step 4: Estimate Achievable Program Potential
Energy efficiency potential studies (Section 3 Sources) employ varying methods to predict
program participation rates. This forecast adopts the assumption that program funding is tied to
customer awareness and willingness to adopt. Under this reasoning consumer awareness is
linked to marketing budgets and willingness to adopt is linked to incentives that offset the
incrementally higher cost of energy efficient technologies.
Estimating achievable program potential is accomplished by applying a series of screens. First,
the applicability factor, incomplete factor and feasibility factor are applied to render economic
potential eligible stock (residential dwellings or commercial floor space). Second, awareness is
43 California Standard Practice Manual: Economic Analysis of Demand -Side Programs and Projects —
Chapter 4, CPUC, October 2001, Chapter 4, page 18
Page 148 of 204
100 April 2008
considered and the unaware consumer associated building stock is removed. Third, adoption is
calculated as a function of the Participant Cost Test. 44
Consumer Awareness Screen: This forecast treats Iack of consumer awareness as a market barrier
to adoption and applies a 25 percent assumption of awareness to impose realistic limits on
forecast market potential. This approximation was adopted in both SW039A California Statewide
Commercial Sector energy Efficiency Study, Xenergy, July 2002 (2002 study) and PGE0211.01
California Energy Efficiency Potential Study, Itron May 2006 (2004 study) 95
Participant Cost Test Screen: The participant cost test is the measure of quantifiable benefits and
costs to the customer due to participation in a program. Benefits of participation in a demand-
side program include the reduction in the customer's utility bill, any incentive paid by the utility
and any tax credit received. Costs of participation are all out-of-pocket expenses incurred as
result of participating in the program. Results of the test are expressed in four ways: net present
value per average participant, net present value for the total program, a benefit -cost ratio, and
discounted payback period (years).
Energy efficiency forecasts (Sources Section 3) apply either the benefit -cost ratio or the payback
period as the final screen to project customer adoption. The benefit -cost ratio is the ratio of total
benefits of a program to the total costs. The payback period is the number of years it takes until
the cumulative benefits equal the costs. Both benefit -cost ratio and payback period methods yield
acceptance curves where consumer probability to participate are projected. This forecast applies
the payback period method consistent with the most recent major energy efficient forecast for
residential, commercial and industrial customer sectors 46
2.3 Planning Scenario — Base Assumptions
Because achievable potential depends on the type and degree of intervention applied, potential
estimates typically include alternative funding scenarios. Given the scope and time -frame, the
forecast was constrained to a single achievable program scenario based on historic program
funding of similar programs47.
The following table summarizes the baseline planning scenario assumptions adopted:
q4 California Standard Practice Manual: Economic Analysis of Demand -Side Programs and Projects, CPUC,
October 2001, Chapter 2, page 8
45 PGE0211.01 California Energy Efficiency Potential Study, Itron May 2006, page 3-21 Approach and key
Assumptions "The 2002 study assumes that awareness is 25 percent ...this is the same as the 2004 study
assuming that the original level of awareness and willingness was 62.5%."
46 PGE0211.01 California Energy Efficiency Potential Study, Itron, May 2006
47 The base achievable funding scenario is tied to program budget levels similar to California 2004-2005
energy efficiency programs. Incentive dollars are estimated directly in REEP as a function of predicted
adoptions. Model inputs include the percentage of incremental measure cost paid as well as proportional
program budget allocations to administration and marketing functions.
Page 149 of 204
101 April 2008
Table 2-1 Baseline Planning Scenario Assumptions
Sector Measure
Category
Residentia148 All
Commercial Lighting
HVAC
Refrigeration
Office Equip.
Industria149 125 Measures
Incentive
Program Cost -
Program Cost
percent
Administration
Incentives
Measure Cost
33%
20%
80%
32.6%
20%
80%
45.8%
20%
80%
60.9%
20%
80%
50.0%
20%
80%
Variable
52.6%
47.4%
Attachment B
Administration program cost include marketing costs
2.4 Determination of Cost -Effective Programs
Measure cost-effectiveness as described in Section 2.2, Summary of Analytical Steps - Step 3,
economic potential is defined by the Total Resource Cost (TRC) test measuring the net -present -
value of the avoided cost of supply against program costs (less incentive payments) plus
participants' costs.
Provided below are residential achievable energy efficiency program potential annual program
cost, net -present -value of the associated avoided cost of supply, TRC test cost -benefit ratio, PAC
test cost -benefit ratio and levelized cost calculated as prescribed in the California Standard
Practice Manual (SPM).
Upon finalizing program designs Marin should perform sensitivity analyses testing the effects,
among other things, of varying funding incentive/marketing levels; perform the Ratepayer
Impact (RIM) cost tests and present Participant Cost Test results at the program aggregate level
(not usually done), as appropriate. The Participant Cost Test was applied within this forecast to
project customer participation.
The SPM states "A variant on the TRC test is the Societal Test. The Societal Test differs from the
TRC test in that it includes the effects of externalities (e.g., environmental, national security),
excludes tax credit benefits, and uses a different (societal) discount rate." At the same page the
SPM also states "The benefits calculated in the Total Resource Cost Test are the avoided costs, the
reduction in transmission, distribution, generation, and capacity costs valued at marginal cost for
the periods when there is a load reduction."
48 Source: PG&E 2004 EE Program Annual Report, May 2005, Table TA 2.1, Program Cost Estimate for Cost -
Effectiveness, Residential Program Area
19PGE0252.01 California Industrial Existing Construction Energy Efficiency Potential Study, KEMA, May
2006
50 SPM Chapter 4, Total Resource Cost Test Definition, page 18
Page 150 of 204
102 April 2008
Upon selection or final program designs, hourly time -of -use impacts should be applied to render
TRC measurements that include transmission and distribution load reductions. Additionally, at
that time, beneficial environmental impacts (externalities) can be included to render Societal Test
results identified as a secondary cost-effectiveness test under the Docket. For the purposes of this
analysis prototypical transmission and distribution avoided cost amounts and externality values
have been incorporated as a proxy to demonstrate their relative magnitude. Sector costs and
benefits, and statement of cost-effectiveness, are provided below with and without these
prototypical transmission, distribution and externality additions.
Page 151 of 204
103 April 2008
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Appendix C — List of Acronyms and Definitions
A-1— Bundled electric service customer class of PG&E, which refers to Small Commercial
customers
A-6 — Bundled electric service customer class of PG&E, which refers to Small Commercial
customers on time -of -use schedules
A-10 — Bundled electric service customer class of PG&E, which refers to Medium Commercial
customers (demand is above 200 kW but less than 499 kW for three consecutive months)
A&G — Administrative and General
AB 32 — The California Global Warming Solutions Act of 2006, which provides mandates
regarding future greenhouse gas emission levels in California
AB 117 — Assembly Bill 117, also known as the Community Choice Aggregation Law or CCA
legislation
AB 1890 — Assembly Bill 1890
ACEEE — American Council for an Energy -Efficient Economy
APT — Annual Procurement Target
AR/AP — Accounts Receivable/Accounts Payable
CAISO — California Independent System Operator
CALMAC — California Measurement Advisory Council
CARE — California Alternate Rates for Energy
CCA — Community Choice Aggregation
CEC — California Energy Commission
CO2 — Carbon Dioxide
CPUC — California Public Utilities Commission
CRS — Cost Responsibility Surcharge
CSI — California Solar Initiative
CTC — Competition Transition Charge
DG — Distributed Generation
DWR — Department of Water Resources
E-19 — Bundled electric service customer class of PG&E, which refers to Large Commercial
customers (demand exceeds 499 kW for three consecutive months)
E-20 —Bundled electric service customer class of PG&E, which refers to Industrial customers
(demand exceeds 999 kW for three consecutive months)
ED — Executive Director
EDI — Electronic Data Interchange
ERRA — Energy Resource Recovery Account, a balancing account utilized by PG&E to record
and recover power costs associated with PG&E's authorized procurement plan, pursuant to
California Public Utilities Code Section 454.5 (d)(3) and applicable CPUC Decisions
ESP — Energy Service Provider
FERC — Federal Energy Regulatory Commission
Full -Requirements Contract — A power services contract under which the supplier provides all
necessary services, including power procurement, scheduling coordination, data management,
ancillary services, and requisite capacity reserves as well as other functions; a "turn -key" power
procurement solution
GHG — Greenhouse Gas
GRC — General Rate Case
111 PaXpril2 15 08f 204
P
GW - Gigawatt: One gigawatt equates to 1,000 megawatts (MW), which is enough energy to
power approximately 750,000-1,000,000 average California homes
GWh - Gigawatt hour: One thousand MWhs, which is enough energy to supply the electric
needs of approximately 750-1,000 typical homes
ICLEI - International Council for Local Environmental Initiatives
IOU - Investor Owned Utilities
IPP - Independent Power Producer
1PT - Incremental Procurement Target
IT - Information Technology
JPA - Joint Powers Agency
KW - Kilowatt: Enough energy to power approximately one average California home
KWh - Kilowatt hour: Smallest unit of measurement used to quantify commercial energy
production
LOC - Letter of Credit
MCE - Marin Clean Energy Joint Powers Authority, a Joint Powers Agency with membership
consisting of Marin County and the eleven cities within the geographic boundaries of the
County
MRTU - Market Redesign and Technology Upgrade
MW - Megawatt: One megawatt equates to 1,000 kilowatts (kW), which is enough energy to
power approximately 750-1,000 average California homes
MWh - Megawatt hour: One megawatt produced for a duration of one hour, which is
equivalent to 1,000 kilowatt hours (kWh) - enough energy to supply the electric needs of a
typical home with an electric hot water system
NCPA - Northern California Power Agency
NEM - Net Energy Metering
NOPEC - Northern Ohio Public Energy Council
NOx - Nitrogen Oxides
NP15 - North of Path 15
NTAC - Northwest Transmission Assessment Committee
O&M - Operations and Maintenance
PA - Project Agreement
PG&E - Pacific Gas and Electric Company, the incumbent electric utility serving the Marin
Communities
PTC - Production Tax Credit
PUC - Public Utilities Code
PUCO - Public Utilities Commission of Ohio
PV - Photovoltaic
QF - Qualifying Facilities
RE - Renewable Energy
REC - Renewable Energy Certificate
RFB - Request for Bids
RFP - Request for Proposals
RFQ - Request for Qualifications
RPS - Renewables Portfolio Standard
RRDR - Renewable Resource Development Report
SCE - Southern California Edison Company
112 FagApril 2008 204
SDG&E — San Diego Gas and Electric Company
SEP — Supplemental Energy Payment
SJVPA — San Joaquin Valley Power Authority
SMUD — Sacramento Municipal Utility District
VEE — Verification, Editing and Estimation
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