HomeMy WebLinkAboutTC Agd Pkt 2008-11-05 (2)
Town Council Meeting
November 5, 2008
Agenda Item: 11/-/
STAFF REPORT
To: Mayor and Members of the Town Council
From: Office of the Town Manager
Office of the Town Attorney
Subject: Recommendation to Introduce on First Reading an Ordinance of the Town
Council of the Town of Tiburon approving the Marin Energy Authority Joint
Powers Agreement and Authorizing the Implementation of a Community
Choice Aggregation Program ·
Reviewed By: ~.
INTRODUCTION AND EXECUTIVE SUMMARY
The ordinance before the Council tonight is a step towards two goals: creating an alternative
energy supply for Marin residents and reducing greenhouse gas emissions.
Community Choice Aggregation, or "CCA," is a State authorized program that allows energy
consumers to band together with other members of their community to obtain energy from
alternative providers. A local government may implement a CCA program by ordinance; two or
more local governments may do so as a group by forming a joint powers authority ("JP A").
Over the past five years the County of Marin and its 11 cities and towns have worked together to
explore implementing a CCA program that would give County residents a "greener" choice for
their electrical energy needs. Meanwhile, in 2006, the State adopted Assembly Bill 32, the
California Global Warming Act of 2006. AB 32 instituted a state-wide program for reducing
greenhouse gases.l The Task Force charged with developing the CCA program decided to add
AB 32 compliance to the new JPA's mandate.
The result is the attached ordinance and joint powers agreement now before the Council. The
ordinance will trigger the following chain of events:
1. The ordinance approves the joint powers agreement and signals the Town's election to
participate in the proposed CCA program, subject to the right to withdraw from the JP A
before it actually implements the CCA program.
1 AB 32 is codified at Sections 38500 et seq. of the California Health and Safety Code. Earlier this year, the State
adopted Senate Bill 375, which adds a host of greenhouse-gas related regulations and requires regional planning
efforts to comply with AB 32-adopted regulations.
TOWN OF TIBURON
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Town Councill\kcting
November 5, 200S
2. The Agreement, upon execution by at least two parties, forms a JP A titled the Marin
Energy Agency ("MEA").
3. The MEA will solicit proposals from potential energy service providers (ESPs) to provide
electricity meeting certain environmental standards pursuant to a CCA program to be
called Marin Clean Energy ("MCE").
4. The MEA is not obliged to proceed with any of the proposals. If the MEA does select a
proposal, it will negotiate a draft contract with the ESP.
5. The MEA will circulate the proposed ESP contract to member agencies. The members
have sixty days to review the proposed contract and decide whether to participate in the
program. If a member decides to withdraw at this point, it may do so without cost or on-
going liability. We expect to arrive at this point in approximately one year.
6. If the MEA actually implements the MCE program, the County will recoup the upfront
costs of forming the MEA and exploring the program from MEA customers. If the MCE
does not implement the program, the County will absorb these unrecoverable costs.
7. Whether or not the MEA implements the MCE program, it will explore and possibly
implement other programs directed at compliance with the members AB 32 obligations.
On October 28, 2008, the County Board of Supervisors passed first reading of its ordinance
approving the MEA joint powers agreement. Most Marin cities and towns are scheduled to hold
their first readings in November; Corte Madera, Novato and Larkspur have not yet scheduled
consideration of the ordinance, but are expected to do so shortly. The County's goal is to form
the MEA in December and begin work on the request for proposals in January of2009.
Public meetings to review the MCE concept were held in Tiburon on May 7 and October 6 of
2008. Every Marin jurisdiction has also held educational sessions on Marin Clean Energy and
CCA both for the public and for a variety of community groups including the North Bay
Leadership Council, Marin Family Action, Marin Municipal Water District, Marin Builders
Exchange, Marin Realtors Association, Sausalito Lions Club, San Rafael Chamber of Commerce,
Mill Valley Rotary and many others.
Present this evening to assist in answering questions about the proposed Marin Energy Authority
are Dawn Weisz, the County planner who has been instrumental in developing the concept and
educating communities about it, Greg Stepanicich of Richards, Watson Gershon, the city attorney
for several Marin cities, whom the County of Marin retained to develop the ordinance and joint
power agreement, and William Monsen of MR W Associates, the principle author of a recent
independent review of the CCA business plan.
BACKGROUND
In this subject area, the use of acronyms is unavoidable. For your convenience, we offer the
following glossary:
TOWN OF TIBURON
PAGE 2 OF 6
CCA:
MCE:
ESP:
JPA:
MEA:
PG&E:
Tmvn Council Meeting
November 5, 200S
Community Choice Aggregation, a state-authorized program to procure
energy on behalf of consumers
Marin Clean Energy, a CCA program to be implemented by the MEA
Energy Service Provider
J oint Powers Authority, a public agency created by contract between
existing public agencies
Marin Energy Agency, ajoint powers authority
Pacific Gas and Electric Company
The Marin Energy Authority ~
The County's plan is to have all participating agencies adopt the attached ordinance by the end of
December, 2008 to form the MEA joint powers authority. The ordinance authorizes the adopting
agency to enter into the j oint powers agreement.
The Town currently belongs to a number of JP As and the MEA would be similar in most
respects. However, it will have several noteworthy atypical features:
· To protect local land use authority, Section 2.7 of the Agreement requires that the MEA
comply with the planning and building laws of any jurisdiction in which it locates or
constructs facilities.
· Section 4.9 sets forth a somewhat complicated voting formula for MCE-related decisions.
Each such decision must pass through two voting tiers, a "percentage" vote and a "share"
vote. Each member agency has one equally weighted vote for the percentage vote. In the
share vote, each member's vote is enhanced according to their total energy use. This
second tier effectively gives more weight to the votes of members using more energy with
the provision that no one agency's vote can ever be enough to carry the decision on that
tier.
· A board decision to amend the agreement or involuntarily remove a party requires a 2/3
majority vote.
· Although an agency may easily withdraw from the MEA before the MCE program begins,
withdrawal will be more complex after the program is under way, particularly if the
withdrawing agency has residents receiving MCE energy. We do not have a resolution
for this problem at present. Accordingly, Section 7.1.3 requires that the MEA's Operating
Rules and Regulations address that issue.
· As discussed earlier, the MEA would also be able to pursue non-CCA programs, to
further compliance with AB 32 mandates. This flexibility requires some creative drafting.
We do not know what these programs will look like or whether the Town will want to
participate. If member agencies are divided regarding a particular AB 32 program, it
would be possible to amend the joint powers agreement to create a separate governance
system. Moreover, any agency can withdraw from the MEA upon six months notice
under Section 7.
TOWN OF TIBURON
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Tmvn Council Meeting
November 5, 200S
· The County has agreed to fund the upfront costs associated with the MEA's formation and
implementation of the MCE program. These costs will be reimbursed only if the MEA
actually implements the MCE program, by recouping the cost from energy customers
(Section 6.3.2).
Community Choice Aggregation (aka Marin Clean Energy or MCE)
State law allows local governments to create programs to procure electricity on behalf of
customers within their jurisdictions under a program called Community Choice Aggregation or
CCA. F or the past several years, the County and the eleven incorporated cities and towns within
Marin have been investigating the feasibility of this opportunity to improve the renewable profile
of Marin's electricity and to help stabilize rates over time. The Town has participated in the
Local Government Task Force exploring CCA since 2006. In recent months, the Task Force
decided to expand the scope of !ts efforts to include greenhouse gas reduction programs
mandated by Assembly Bill 32, described further below.
The CCA Task Force generated the following documents:
· Marin CCA Business Plan;
· Local Renewables Analysis; and
· An independent peer review of the Marin CCA Business Plan.
The first purpose of the new agency, MEA, is to create and operate a county-wide CCA, Marin
Clean Energy (MCE). MEA would be a separate legal entity able to enter into contracts to
purchase renewably-generated electricity from independent producers. The MEA would solicit
proposals to supply electric power for the MCE project and carry out other technical functions.
If the MEA selects a proposal, it will negotiate a draft contract with the energy service provider
(ESP). The MEA will circulate the draft for a minimum 90-day review period.
Each MEA member government would then vote on whether to go forward with the contract to
implement CCA or not. Signing the contract with an Energy Service Provider would occur in
mid- to late 2009, and would be the formal step to launch the MCE project.
PG&E would distribute the MCE power, provide the balance of electricity needed and continue
to own and operate the distribution network of power lines. PG&E would also continue to
provide billing and customer service. Customers in participating municipalities and the
unincorporated County would have the ability to subscribe to power from MEA or could "opt
out" and stick with PG&E for all of their power. MEA Customers could choose between two
levels of participation: "light green" or "dark green". Initially, "light green" would provide
twice as much renewable energy as customers currently receive, increasing to approximately
50% within five years, at rates equal to or less than PG&E's, with rates projected to decrease
over time. Those selecting the "dark green" option would agree to pay 8-10% extra to receive
100% renewable power. (Please note that the actual source of the power one receives is a
function of the power-balancing that occurs at the regional and state level where electrons are
merged in the system as efficiency dictates.)
MCE is based on a fairly complicated and technical business plan that makes many assumptions
about the availability and reliability of both renewable and non-renewable resources into the
TOWN OF TIBURON
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Town Council Meeting
November 5, 200S
future. All of the participating entities want the highest possible level of certainty that the MCE
will achieve the predicted outcome of greener and, eventually, rate-stabilized power is achieved
and anticipate and address all possible downsides in advance. Accordingly, the MCE plan has
received substantial scrutiny. It was the subject of an extensive Peer Review commissioned by
the County in 2007, which concluded that the plan is feasible and would produce the desired
outcome. PG&E criticized that review, arguing that the assumptions used were overly rosy.
In part to counteract the effect of these dueling critiques, the cities and towns considering MCE
independently commissioned a third peer review of the business plan. That review found that
MCE " ... creatively proposes a workable path to providing green power to those in Marin who
want it while offering rates comparability and predictability to those who need it." The reviewers
also raised issues and posed questions they believe should be answered before participating cities
making a binding commitment to MCE (a decision point that will present itself approximately
one year from now). .The review recommended that the parties proceed to form the MCE Joint
Powers Authority at this time with ~the understanding that, if business plan projections do not
materialize as anticipated, it will be possible to withdraw from MCE without penalty during the
upcoming year (see Section 7.1.1.1 of the Agreement). ·
This last point is crucial to all participants, who need to know when and how participating
agencies, such as Tiburon, could elect to withdraw if they were dissatisfied with the prospects of
the enterprise. Up until such time as the MEA actually enters into agreements with energy
service providers any participating agency could withdraw from the JP A without penalty. This
arrangement is possible because the County has agreed to bear the costs incurred in the initial
process ifMCE fails to materialize because of agency withdrawals. IfMCE does move forward,
the County will eventually be reimbursed for these expenses through the rates charged to
program customers. This affords participating cities and towns the benefit of actually seeing
what the private sector (including possibly PG&E) has to offer in the way of contracts and if they
fit within the parameters set forth in the business plan prior to a commitment to participate in the
MEA.
It is important to note that, as structured in the JP A, participating agencies would not have their
municipal funds at risk in the enterprise. Marin Energy Authority would be a completely
separate legal entity that would succeed or fail without recourse to any of its member cities'
coffers. Its funding would come through its ability to issue debt and to set rates for its
customers.
AB 32 Mandates
AB 32 requires local governments to limit greenhouse gas (GHG) emissions from government
operations and potentially for some sectors in the community as well. An overall reduction of
approximately 30% may be needed to meet the state mandate. Countywide, this is equivalent to a
reduction of 955,500 tons of C02. In addition, a cap and trade program may be in place for local
governments so that those who are not reducing GHG emissions enough will be able to buy
credits from those who are reducing more than required. Currently, the cost of offsetting carbon
on the Chicago Climate Exchange is $4 per ton.
To address the requirements of AB 32 the proposed JPA "Marin Energy Authority" would allow
participating cities and towns to pool resources and address carbon emissions countywide. This
TOWN OF TIBURON
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Town Council Mceting
Novcmber 5, 200S
JP A could take on a number of projects to reduce greenhouse gas (GHG) emissions. Potential
projects could range from implementing the Community Choice Aggregation program described
above to increasing energy efficiency or installing more renewable energy supply. Due to the
high impact in GHG reductions the first program likely to be launched by the Marin Energy
Authority JP A would be Community Choice Aggregation.
FINANCIAL IMPACT
There is no fiscal impact to Tiburon in adopting the ordinance to form MEA. The Marin County
Board of Supervisors has allocated funding to cover start-up costs for the MCE effort undertaken
by the MEA. These start-up costs would be reimbursed through program revenue if the MCE
program begins to serve customers. At this junction, we cannot predict what expenses might be
incurred if the MEA board elects to pursue additional programs to MCE, but the Town as a
member of the JP A would participate in those decisions.
RECOMMENDA TION
Staff recommends that the Town Council introduce on first reading the proposed ordinance to
form Marin Energy Authority. This recommendation is based upon the following:
1. the program has the potential to offer electric customers in Tiburon both greener power
and stabilized rates over time;
2. there is no financial risk to the town to participate at this stage as the Town can withdraw
without penalty if it is dissatisfied with the contracts proffered by the energy service
providers later in 2009; and
3. the independent review commissioned by the cities and towns raises important questions
which, if answered between now and the withdrawal decision date, will enhance the
likelihood that a prudent choice can be made that that time to proceed or withdraw from
the JP A.
Therefore, staff recommends that the Town Council:
1. Hear the staff report and brief remarks from the invited presenters and ask questions;
2. Open the public hearing, hear from interested members of the public;
3. Close the public hearing; and
4. By motion, read the ordinance by title only and pass first reading of the ordinance
approving the Agreement to form the Marin Energy Authority JP A by roll call vote.
Attachments:
1. Ordinance Approving Marin Energy Authority Joint Powers Agreement
Exhibit A: Marin Energy Authority Joint Powers Agreement
Exhibit B: Marin Clean Energy Business Plan
2. Review ofMCE proposal by MRW Associates
Prepared By: Peggy Curran, Town Manager
Ann Danforth, Town Attorney
TOWN OF TIBURON PAGE 6 OF 6
TOWN OF TIBURON
1505 Tiburon Boulevard
Tiburon, CA 94920
Town Council Meeting
November 5, 2008
Agenda Item: P/I_ /
STAFF REPORT
To:
Mayor and Members of the Town Council
From:
Office of the Town Manager
Subject:
Modification to Joint Powers Agreement for Marin Energy Authority
Reviewed By:
~---.
NEW INFORMATION
Yesterday, November 4, the Board of Supervisors introduced on first reading a Joint Powers
Agreement forming Marin Energy Authority. The Agreement they introduced included one
variation from that found in your packets. It added one paragraph, new 8.3, entitled
"Indemnification of Parties". This new language is highlighted on the attached sheet.
Both the Town Attorney and the Town's Marin Clean Energy liaison, Councilmember Dick
Collins, have reviewed the proposed language and believe it is a useful addition to the document
under consideration.
RECOMMENDATION
If the Town Council wishes to proceed to introduce on first reading the ordinance creating the
Marin Energy Authority, staff recommends the Town Council move to include new paragraph 8.3
in Exhibit A of the ordinance, with the remaining paragraphs re-numbered accordingly.
Attachment: New paragraph 8.3 entitled "Indemnification of Parties"
Prepared By: Peggy Curran, Town Manager
TOWN OF TIBURON PAGE 1 OF 1
8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts
to settle all disputes arising out of or in connection with this Agreement. Should
such efforts to settle a dispute, after reasonable efforts, fail, the dispute shall be
settled by binding arbitration in accordance with policies and procedures
established by the Board.
8.2 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 Patties. Jhe Authoritv shall acquire such insuraIlc~_ coverage as is
ne~9JiSarYJo proteft the interests of the Authority. the Parties and the public. The
Authoritv shaH defend, indelnnifv and hold harnlless the Parties and each of their
respective Board or Councillnembers. oiJicers. agents and employees, iroln any and
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QL.ilLqiI~.f.1.lyJ[Q.l.IL!hQ_f.\~D..Q!!.GJ~...f:!:f.1.Ly-,i!.i~LQl)-t;E!ti.9_n~..~l~.g~,-...5.!.!J~J....~!..mj.?..~i..9n.~.....Q.f.Jl1~
Authority under this AQxeenlent
8.J.:! Amendment of this A2reement. 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.
8.4~ Assi2nment. 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 8.4 shall be null and
1090083-1
15
4!icd~1
#/
ORDINANCE NO.
AN ORDINANCE OF THE TOWN COUNCIL
OF THE TOWN OF TIBURON APPROVING THE
MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT AND AUTHORIZING THE
IMPLEMENTATION OF A
COMMUNITY CHOICE AGGREGATION PROGRAM
The Town Council of the Town ofTiburon ordains as follows:
SECTION 1. The Town of Tiburon 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 Town 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 Town joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin and
each municipality in the County. 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 Town 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" 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 from the Town 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 that 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 Town 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 Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the Town's jurisdiction by and through the Town'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 Town'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 Mayor is hereby authorized to execute the attached Joint Powers
Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names of the members of the Council voting for imd against the same in a
newspaper of general circulation published in the Town ofTiburon.
The foregoing ordinance was introduced at a meeting of the Town Council of the Town
of Tiburon held on , and adopted at a meeting held on , by the following vote:
AYES:
NOES:
ABSENT:
COUNCILMEMBERS:
COUNCILMEMBERS:
COUNCILMEMBERS:
JEFF SLA VITZ, MAYOR
TOWN OF TIBURON
ATTEST:
DIANE CRANE IACOPI, TOWN CLERK
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 Nova to)
[Town of Ross)
[Town of San Anselmo)
[City of San Rafael}
[City of Sa usa lito)
[Town of Tiburon)
[County of Marin)
EXHIBIT A
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.
RECIT ALS
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 illhabitants.
2. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act,
which mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels.
The California Air Resources Board is promulgating regulations to implement AB
32 which will require local government to develop programs to reduce
greenhouse emissions.
3. The purposes for the Initial Participants (as such term is defined in Section 2.2
below) entering into this Agreement include addressing climate change by
reducing energy related greenhouse gas emissions and securing energy supply and
price stability, energy efficiencies and local economic benefits. It is the intent of
this Agreement to promote the development and use of a wide range of renewable
energy sources and energy efficiency programs, including but not limited to solar
and wind energy production.
4. The Parties desire to establish a separate public agency, known as the Marin
Energy Authority ("Authority"), under the provisions of the Joint Exercise of
Powers Act of the State of California (Government Code Section 6500 et seq.)
("Act") in order to collectively study, promote, develop, conduct, operate, and
manage energy programs.
5. The Initial Participants have each adopted an ordinance electing to implement
through the Authority Community Choice Aggregation, an electric service
enterprise agency available to cities and counties pursuant to California Public
Utilities Code Section 366.2 ("CCA Program"). The first priority of the Authority
will be the consideration of those actions necessary to implement the CCA
Program. Regardless of whether or not Program Agreement 1 is approved and the
CCA Program becomes operational, the parties intend for the Authority to
continue to study, promote, develop, conduct, operate and manage other energy
programs.
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:
Exhibit B:
Exhibit C:
Exhibit D:
Definitions
List of the Parties
Annual Energy Use
V oting 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 8.3. 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 Purpose. The purpose of this Agreement is to establish an independent public
agency in order to exercise powers common to each Party to study, promote,
develop, conduct, operate, and manage energy and energy-related climate change
programs, and to exercise all other powers necessary and incidental to
accomplishing this purpose. Without limiting the generality of the foregoing, the
Parties intend for this Agreement to be used as a contractual mechanism by which
the Parties are authorized to participate as a group in the CCA Program, as further
described in Section 5.1. The Parties intend that subsequent agreements shall
define the terms and conditions associated with the actual implementation of the
CCA Program and any other energy programs approved by the Authority.
2.5 Powers. The Authority shall have all powers common to the Parties and such
additional powers accorded to it by law. The Authority is authorized, in its own
name, to exercise all powers and do all acts necessary and proper to carry out the
provisions of this Agreement and fulfill its purposes, including, but not limited to,
each of the following:
2.5.1
2.5.2
2.5.3
2.5.4
2.5.5
2.5.6
2.5.7
2.5.8
2.5.9
2.5.10
2.5.11
2.5.12
make and enter into contracts;
employ agents and employees, including but not limited to an Executive
Director;
acquire, contract, manage, maintain, and operate any buildings, works or
improvements;
acquire by eminent domain, or otherwise, except as limited under Section
6508 of the Act, and to hold or dispose of any property;
lease any property;
sue and be sued in its own name;
incur debts, liabilities, and obligations;
issue revenue bonds and other forms of indebtedness;
apply for, accept, and receive all licenses, permits, grants, loans or other
aids from any federal, state or local public agency;
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;
adopt rules, regulations, policies, bylaws and procedures governing the
operation of the Authority ("Operating Rules and Regulations"); and
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 Zonine and Buildine 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)( 1 0)
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 Continuine Participation. The Parties acknowledge that membership in the
Authority may change by the addition and/or withdrawal or termination of Parties.
The Parties agree to participate with such other Parties as may later be added, as
described in Section 3.1. The Parties also agree that the withdrawal or termination
of a Party shall not affect this Agreement or the remaining Parties' continuing
obligations under this Agreement.
ARTICLE 4
GOVERNANCE AND INTERNAL ORGANIZATION
4.1 Board of Directors. The governing body of the Authority shall be a Board of
Directors ("Board") consisting of one director for each Party appointed in
accordance with Section 4.2.
4.2 Appointment and Removal of Directors. The Directors shall be appointed and
may be removed as follows:
4.2.1 The governing body of each Party shall appoint and designate in writing
one regular Director who shall be authorized to act for and on behalf of the
Party on matters within the powers of the Authority. The governing body
of each Party also shall appoint and designate in writing one alternate
Director who may vote on matters when the regular Director is absent
from a Board meeting. The person appointed and designated as the
Director or the alternate Director shall be a member of the governing body
of the Party.
4.2.2 The Operating Rules and Regulations, to be developed and approved by
the Board in accordance with Section 2.5.11, shall specify the reasons for
and process associated with the removal of an individual Director for
cause. Notwithstanding the foregoing, no Party shall be deprived of its
right to seat a Director on the Board and any such Party for which its
Director and/or alternate Director has been removed may appoint a
replacement.
4.3 Terms of Office. Each Director shall serve at the pleasure of the governing body
of the Party that the Director represents, and may be removed as Director by such
governing body at any time. If at any time a vacancy occurs on the Board, a
replacement shall be appointed to fill the position of the previous Director in
accordance with the provisions of Section 4.2 within 90 days of the date that such
position becomes vacant.
4.4 Quorum. A majority of the Directors shall constitute a quorum, except that less
than a quorum may adjourn from time to time in accordance with law.
4.5 Powers and Function of the Board. The Board shall conduct or authorize to be
conducted all business and activities of the Authority, consistent with this
Agreement, the Authority Documents, the Operating Rules and Regulations, and
applicable law.
4.6 Executive Committee. The Board may establish an executive committee
consisting of a smaller number of Directors. The Board may delegate to the
executive committee such authority as the Board might otherwise exercise,
subject to limitations placed on the Board's authority to delegate certain essential
functions, as described in the Operating Rules and Regulations. The Board may
not delegate to the Executive Committee or any other committee its authority
under Section 2.5.11 to adopt and amend the Operating Rules and Regulations.
4.7 Commissions" Boards and Committees. The Board may establish any advisory
commissions, boards and committees as the Board deems appropriate to assist the
Board in carrying out its functions and implementing the CCA Program, other
energy programs and the provisions of this Agreement.
4.8 Director Compensation. Compensation for work performed by Directors on
behalf of the Authority shall be borne by the Party that appointed the Director.
The Board, however, may adopt by resolution a policy relating to the
reimbursement of expenses incurred by Directors.
4.9 Board V otine 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 8.3 (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 8.3 (the "percentage voting shares"), provided that, in instances in
which such other higher voting share percentage would result in anyone
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: (l/total number of
Directors) multiplied by 50, and
4.9.2.2 Annual Energv 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 ("kWhs"), 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 8.3.
4.11 Meetines and Special Meetines 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 Preliminarv Implementation of the CCA Proeram.
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)(1 0) 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 practi'Cable. 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 I 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
5.1.4.1, the remaining Parties to this Agreement shall be
only the Parties who voted in favor of the Required
Implementation Action.
5.1.4 Termination of CCA Program. Nothing contained in this Article or this
Agreement shall be construed to limit the discretion of the Authority to
terminate the implementation or operation of the CCA Program at any
time in accordance with any applicable requirements of state law.
5.2 Authority Documents. The Parties acknowledge and agree that the affairs of the
Authority will be implemented through various documents duly adopted by the
Board through Board resolution, including but not necessarily limited to the
Operating Rules and Regulations, the annual budget, and specified plans and
policies defined as the Authority Documents by this Agreement. The Parties agree
to abide by and comply with the terms and conditions of all such Authority
Documents that may be adopted by the Board, subject to the Parties' right to
withdraw from the Authority as described in Article 7.
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 Depositorv.
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 Budeet 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 8.3.
7.1.3 Continuing Liability; Further Assurances. A Party that withdraws its
membership in the Authority may be subject to certain continuing
liabilities, as described in Section 7.3. The withdrawing Party and the
Authority shall execute and deliver all further instruments and documents,
and take any further action that may be reasonably necessary, as
determined by the Board, to effectuate the orderly withdrawal of such
Party from membership in the Authority. The Operating Rules and
Regulations shall prescribe the rights if any of a withdrawn Party to
continue to participate in those Board discussions and decisions affecting
customers of the CCA Program that reside or do business within the
jurisdiction of the Party.
7.2 Involuntary Termination of a Party. This Agreement may be terminated with
respect to a Party for material non-compliance with provisions of this Agreement
or the Authority Documents upon an affirmative vote of the Board in which the
minimum percentage vote and percentage voting shares, as described in Section
4.9.1, shall be no less than 67%, excluding the vote and voting shares of the Party
subject to possible termination. Prior to any vote to terminate this Agreement with
respect to a Party, written notice of the proposed termination and the reason(s) for
such termination shall be delivered to the Party whose termination is proposed at
least 30 days prior to the regular Board meeting at which such matter shall first be
discussed as an agenda item. The written notice of proposed termination shall
specify the particular provisions of this Agreement or the Authority Documents
that the Party has allegedly violated. The Party subject to possible termination
shall have the opportunity at the next regular Board meeting to respond to any
reasons and allegations that may be cited as a basis for termination prior to a vote
regarding termination. A Party that has had its membership in the Authority
terminated may be subject to certain continuing liabilities, as described in Section
7.3. In the event that the Authority decides to not implement the CCA Program,
the minimum percentage vote of 67% shall be conducted in accordance with
Section 4.10 rather than Section 4.9.1.
7.3 Continuine Liability: Refund. Upon a withdrawal or involuntary termination of
a Party, the Party shall remain responsible for any claims, oemands, 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 Property upon Termination of Authority. Upon termination of
t.his Agreement as to all Parties, any surplus money or assets in possession of the
Authority for use under this Agreement, after payment of all liabilities, costs,
expenses, and charges incurred under this Agreement and under any program
documents, shall be returned to the then-existing Parties in proportion to the
contributions made by each.
ARTICLE 8
MISCELLANEOUS PROVISIONS
8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts
to settle all disputes arising out of or in connection with this Agreement. Should
such efforts to settle a dispute, after reasonable efforts, fail, the dispute shall be
settled by binding arbitration in accordance with policies and procedures
established by the Board.
8.2 Liability of Directors" Officers" and Employees. The Directors, officers, and
employees of the Authority shall use ordinary care and reasonable diligence in the
exercise of their powers and in the performance of their duties pursuant to this
Agreement. No current or former Director, officer, or employee will be
responsible for any act or omission by another Director, officer, or employee. The
Authority shall defend, indemnify and hold harmless the intlividual 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 Amendment of this Aereement. 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 670/0 shall be conducted in accordance with Section 4.10 rather
than Section 4.9.1.
8.4 Assienment. 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 8.4 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 8.4 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.
8.5 Severability. If one or more clauses, sentences, paragraphs or provisions of this
Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby
agreed by the Parties, that the remainder of the Agreement shall not be affected
thereby. Such clauses, sentences, paragraphs or provision shall be deemed
reformed so as to be lawful, valid and enforced to the maximum extent possible.
8.6 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.
8.7 Execution by Counterparts. This Agreement may be executed in any number of
counterparts, and upon execution by al~ 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.
8.8 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:
Title:
Date:
Party:
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
E>irector 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
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
Authority Total Energy Use
*Data provided by PG&E
kWh (2005*)
.
10,498,935
75,726,510
23,594,966
63,659,700
64,761,440
268,301,203
13,329,878
47,874,957
332,588,277
52,373,525
42,831,004
332,726,224
1,328,266,620
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%) 0.890/0 5.05 %
City of Larkspur 63,659,700 4.17% 2.400/0 6.56 %
City of Mill Valley 64,761,440 4.1 70/0 2.44% 6.60%
City of Novato 268,301,203 4.1 70/0 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 ofTiburon 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 50.000/0 50.000/0 100.00%
*Data provided by PG&E
FINAL REPORT
MARIN - CALIFORNIA
COMMUNITY CHOICE
AGGREGA TION
BUSINESS PLAN
April 2008
EXmBIT ~
For copies of this report contact the Marin County Community Development Agency
in San Rafael, California or visit www.marincleanenergy.info
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Acknowledgements.. ........ ........ ........ .............. ............. ............ ........... ........... .... ......... ......... ............. .......... ...... ....... ... i
Executive Summary...... ........ ..... ............ ................ .............. .................. .......... ......... ........ ......... ........ ....... ............ ..... 1
I.Governance and Organization. ......... .......... ..................... ................ ......... ......... .......... ....................... ......... ..1:4
2.Phased Customer Enrollment.... ........ .............. ............................ .................................................................. 25
3. Electric Resources................................................................... ........... ......................................... ..................... Q(~
4.Rates............................................................................... ........................................................................ ............ Z7
5.Financial Plan......................... ............. ......................................... .................................................. ......... ......... 29-
6.Financings .............................................................................................................................. ...........................29-
7.Implementation Schedule ..... ............... ............ ............. .............. .......... ........................................ ......... ..... 10+0
CHAPTER 1 - Introduction........ ......... .................... ........ ........................................... ..................................... ...l1U
Background on CCA................................................................... ................................... ................................. 131-3
CCA Program Components (Implementation Plan Requirements) ........................................................15+5
Program Implementation.......................................... ....... .......... ................................................................... .1.6-16
CHAPTER 2 - Organizational Plan................................................................................................................... 181-8
Organizational Overview..... .......... ............... ... ... ........ ....... ........... ......... ... ...... .......... .... ....... ............... ..... ..... 18+8
Governance..................................................................................................................... ................................. 202:Q
Officers....................................................................................................................... ...................................... 222-2:
Commi ttees .............................................................................................................................. ........................ 2..22-2:
Addition/Termination of Participation......................................... ............................... ................................ ~2..2-2:
Termination of Marin Clean Energy ........................................ ............................... ............ .... ..................... 2_~2-3
Agreements Overview....................... ...... ...................................................................................................... 2.;3.2-3
Joint Powers Agreement .................................... ....... ....................... .............................................................. 232-]
Program Agreement No.1....................... ............ ........ ......................... ................................. ......... ............... 242-4
Agency Operations.................................................................................................................... ..................... 242-4
Resource Planning .......................................................................................................................................... 242-4
Portfolio Operations........................................................................ ............................................................... 25A
Energy Efficiency..................................................................................... ....................................................... ~26
Ra te Setting....................................................................................................................................... ............... 2..6.26
Financial Management/Accounting .............. ......... ......... .............. ............................................................... 2626
Customer Services.. ............. ...................... ............ ......... ........ ................ ...................... ..... ....... ....... ....... ......... 27':t:7
Legal and Regulatory Representation....... .................... ......... ...................... ....... .................. ........ ............... 27':t:7
Roles and Functions .................. ............ ................. .............. ................. ........................... ............................... 28~
Staffing....................................................................................................................... ...................................... 292:9-
CHAPTER 3 - Loa d F orecas t and Resource Plan............................................................................................. ;3.1:J4
Introduction.................................................................................................................. ................................... .:1.4M
Program Phase-In.................. ................................ ......... ........................ ...... ................ .... ............................... 35J~
Phase 1 - Participant Accounts......................................................................................... ............................ 35~
Phase 2 - Large Accounts.......................................................... .............. ..................................... ................. 35~
Phase 3 - All Accounts................................................................................................................................... 36J6
Resource Plan Overview................................................................................................................................ 36J6
Supply Requirements...... ............................ ..... ..................................... ........................... ............. ................. 38~
Customer Participation Rates.................................................................................................. ...................... J2J9
Customer Forecast.......................................................................................................................................... 39J9
Sales Forecast........................................................... ......... ................ ........................ ....................................... 404G
Capacity Requirements.................................................................................................................................. il4.l-
Renewable Portfolio Standards Energy Requirements........... ...... ........................................................... ..1.;3.43
Basic RPS Requirements... ...................... ............................................................................................. 434J
RPS Compliance Rules................................ ................................ ......................................................... 4343
Marin Clean Energy's Renewable Portfolio Standards Requirement ........................................... 4444
Marin Clean Energy's Renewable Energy Goals............................. ........ ......................................... 4444
Resources .............................................................................................................................. .......................... .1.444
Purchased Power............................................................................................................................................ 4646
Renewab Ie Resources..................................................................................................................................... 4747
Near Term Renewable Potential........... ..................................................................... ......................... 4848
Medium and Long-Term Renewable Potential................................................................................ 4949
Planned Renewable Generation Resources................................................................. ...................... 5252
Energy Efficiency... .......................... ..... ................ .......................................................................................... 5252-
Baseline Energy Efficiency Potential Estimates............ ................................................. ................... 5454
CCA Program Energy Efficiency Goals............................................................................................. 5454
Demand Response ...... ..... ................... ...................... ........ ......... ........... ....... ........ .... ........... .......... ........ 5555
Distribu ted Generation.................................................................................................................... .............. 56~
Impact of Resource Plan on Greenhouse Gas Emissions............................................................................ 51138
CHAPTER 4 - Financial Plan....... ...................................................................................................................... 606G
Description of Cash Plow Analysis.............................................................................................................. 606(.)
Cost of CCA Program Operations................................................................................................................ {J..Q6G
Revenues from CCA Program Operations.................................................................................................. sil6+
Cash Flow Analysis Results........................................................................................................................... QJeJ
CCA Program Implementation Feasibility Analysis.............. .................................................. .................. 6464
Capital Requirements......................................................... ................................................... .................... ..... 6686
Startup Activities and Costs...................... .............. ................. ........ ................................. ............................ 6767-
Startup Cost Summary....................................................... ............................................................................ 6767-
Estimated Staffing Costs...................... .................. ...................... .................................................................. 6868
Estimated Infrastructure Costs. .................................................................................................................... 6868
Utility Implementation and Transaction Charges .............. ................ ......... ...... ............................ ............. 696-9-
Estimates of Third Party Contractor Costs........ ........ ........................ .......... ............ ............ ........................ 9.2.6-9-
P inancing Plan................................................................................................................................................. ZQ7G
Working Capital................ .................... .................. ........ ......... ............. ........................................... ...... ......... ZQ7G
Pro Forma ............ ...... ................... ................................... ........ ................. ....... ...... .......... .... ............ ........ ......... ZQ7G
Marin Clean Energy Pinancings................ .................................................................................................... 707G
CCA Program Start-up and Working Capital (Phases 1 and 2) ............................................................... 717+-
CCA Program Working Capital (Phase 3). ................ .................................................................................. 7"171-
Renewable Resource Project Financing .............................................. ...... ................................................... 717+-
Sensitivities and Uncertainties................ ...................................................................................................... 7373
Other Risks and Uncertainties....................................................................................... ..................... Z5..75
CHAPTER 5 - Ratesetting and Program Terms and Conditions ................................................................... 7777-
Introduction...................................................................................... ....................................... ........................ 777+
Rate Policies ............... ....................................... .............. ................................................... .............................. 777+
Rate Competitiveness....... .................. .................... ........................................ ......................... ....................... 777+
Rate Stability........... ......................... ....................... ......... ............. .......... ........................... ...................... ........ 787g
Equity among Customer Classes......... ............ ............ ................................................................................. 787g
Customer Understanding................................................................................................................. ............. Z_~7.8
Revenue Sufficiency... ................................................... ................................................................................. .7.2.79
100 percent Renewable Energy Delivery - "100 percent Green Tariff" .................................................. Z.2.7-9
Ra te Design...................................................................................................................................................... 7979
Net Energy Metering.............................................. ......................................... ............................................... 818J.
Rate Impacts.................................................................................................................................................... 81.81-
Disclosure and Due Process in Setting Rates and Allocating Costs among Participants ..................... 82~
Customer Rights and Responsibilities... ................. .............. ..... ....................................................... ........... 83gJ
Customer Notices....................................................................................................................... ..................... 83S3
T ermina tion Fee .............................................................................................................................................. 8484
Customer Confidentiality...... ..... ........ ... ....... ... ..... .......... .... ... ............ ......... .......... ........ ........ ........ ... .......... .... 8686
Responsibility for Payment........ ...................... ........... ........ ........................................................ ......... ......... 8686
Customer Deposits ... .................. .............. ................ ....... ....... ..... .......................... ........................ ................. BQ86
C~~:~~:;e~:;:se~i~.~.~.l~~.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::'8~:
Partnering with Large Customers...... ................. ......................................................................................... 8787
CHAPTER 7 - Procurement Process....... ............. ..... ......................................................................................... 8989-
In trod u cti on .............................................................................................................................. ....................... 8989-
Procurement Methods.......................... ........ .......... ................................................................................ ........ 8989-
Procurement at Startup.................................................................................................................................. 8989-
Key Contracts.......................................................................................................~...................... ....................2.000
Electric Supply Contract...................................................................................................................... 2_Q9G
Data Management Contract.......... ....................................... ....................................... ........................ 919-+
Chapter 8 - Program Termination ....................................... .................................... ............ ............ ......... ......... 9292-
Introduction.................................................................................................................. ................................... 9292-
Termination by Marin Clean Energy............... ........ ..... ....... .............. .......... ......... ............. .................... ...... 9292-
Termination by Members ...................... ............................ ..... ............................... ........................................ 93W
CHAPTER 9 - Appendices........................ ................ ............................................................ ............................. 9494-
Appendix A - Pro Forma 2014-2025............................................................................ .......... ...... ................. 9.5%
Appendix B - Energy Efficiency Potential in the Marin Communities ...................................................2.6.%
Appendix C - List of Acronyms and Definitions ...................................................................................111+1+
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
Barbar\! Morrison Council member
John Telischak Council member
George Rodericks City Manager
Pierce MacDonald Planning Manager
Corte Madera
Melissa Gill' Former Mayor
Carla Condon Councilmember
David Bracken Town Manager & Engineer
Bob Pendoley Director of Planning
Tony Gokoffski Senior Engineer
Fairfax
Larry Bragman Council member
Lew Tremaine Council member
Mike Rock Town Manager
Linda Kelly' Former Town Manager
Larkspur
Dan Hillmer Vice Mayor
Larry Chu Councilmember
Jean Bonander City Manager
Mill Valley
Shawn Marshall Mayor
Chris Raker' Former Mayor
Anne Montgomery City Manager
Eric Ericson Director of Finance & Human Resources
Nova to
Jim Leland Mayor Pro Tempore
Carole Dillon-Knutson Councilmember
Madeline Kellner Councilmember
Dan Keen City Manager
Jennifer Goldfinger Assistant to City Manager
Ross
Scot Hunter Mayor
Bill Cahill Mayor Pro Tempore
Richard Strauss Council member
Gary Broad Town Manager
Elise Semonian Senior Planner
San Anselmo
Peter Breen Vice Mayor
Barbara Thornton Council member
Debbie Stutsman Town Manager
San Rafael
Paul Cohen' Former Vice Mayor
Cyr Miller Councilmember
Damon Connolly Council member
Ken Nordhoff City Manager
Linda Jackson Principal Planner
Sausalito
Mike Kelly Mayor
Jonathan Leone Counci lmember
Herb Weiner Councilmember
Adam Politzer City Manager
Paul Kermoyan' Former Community Development Director
Kevin Bryant' Former Assistant to City Manager
Tiburon
Jeff Slavitz Mayor
Paul Smith' . Former Mayor
Miles Berger Councilmember
Richard Collins Council member
Peggy Curran Town Manager
Heidi Bigall Director of Administrative Services
Nick Nguyen Director of Public Worksrrown Engineer
MMWD
Cynthia Kohler Board President
David Behar Board Member
Paul Helliker General Manager
NMWD
Jack Baker Board Member
Dennis Rodoni Board Member
Chris DeGabriel General Manager
Robert Clark Facilities Superintendent
County of Marin
Hal Brown Supervisor
Charles McGlashan Supervisor
Joshua Townsend' Former State Assembly Member Rep
Leslie Alden Aide to Supervisor McGlashan
Cynthia Connolly Aide to Supervisor Brown
Matthew Hymel County Administrator
Alex McIntyre' Former Assistant County Administrator
Eric Engelbart Administrative Analyst
Mike Lowrie Administrative Analyst
Alex Hinds Community Development Agency Director
Dawn Weisz Principal Planner
Gmar Pena SustainabiIity Planning Aide
Jamie Tuckey Sustainability Intern
Technical Advisory Committee
Sean Casey Former SFPUC
Ray Dracker Center for Resource Solutions
Peter Luchetti GFP Advisors
Wally McOuat HMH Energy Resources, Inc.
Gwen Rose VoteSolar
Consultants
John Dalessi Navigant Consulting, Ine.
Kirby Dusel Navigant Consulting, Inc.
Jody London Jody London Consulting
Bill Marcus JBS Energy, Ine.
Tim Rosenfeld HMW International
Greg Stepanidch Attorney, MIRA JPA
*Former Task Force Member
- i -
Beginning in 2004, the County of Marin and the eleven cities within the county ("Marin
Communities" 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).1 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
Inteinational 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 700/0 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 800/0 renewable energy supply for the Marin Communities in 2014; alternatively, the
incumbent utility provides approximately 12-140/0 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 program 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.
1 The eleven cities located with the County of Marin include: Belvedere, Corte Madera, Fairfax, Larkspur, Mill Valley,
Novato, San Anselmo, San Rafael, Sausalito, Tiburon and Ross.
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:
~ 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 CommunitieS:
· 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 this 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 Bay CCA Program
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 JP A,
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
addl'essed 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 SJVP A 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, 2007.2 On April 30, 2007, the California Public
Utilities Commission provided notice to the SJVP A certifying that its Implementation Plan
contained sufficient data, as required by California Public Utilities Code Section 366.2. In
addition to the SJVP A, 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 SJVP A' s Implementation Plan were subsequently submitted on April 27, 2007; additional revisions
were filed with the CPUC on August 27, 2007.
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 JP A 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 JP A would adopt the Implementation Plan
required by the CCA legislation (AB 117) and register with the California Public Utilities
Commission as a Community 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 JP A agreement would specify the governance
provisions of Marin Clean Energy. Proposed principles for a JP A 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 P A-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 As a public entity, any business relationship between Marin Clean Energy and a third-party contractor is assumed
to result from a competitive solicitation/selection process.
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 1 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 were retained (10 percent opt-out per class).
5 April 2008
approximately $128 million. The break down of projected sales by major customer class is
shown in the following figure.
Proj ected Customer Mix In 2011
Marin Clean Energy
Customer Mix by Load
1%
17%.~-
1%
- ~51%
16%--
Iillil Residential
. Small Commercial
. Industrial
o Medium Commercial
o Large Commercial
. Agricul ture
Iillil Street Light
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
April 2008
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 SJVP A 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 April 2008
Marin Clean Energy Estimated 2011 Program Rates
Customer Class Program Rates - 100 Program Rates - PG&E Generation
percent Green Light Green Rate
(25/510/0)
(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 I, 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 the coming year.
Program customers 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 rate setting
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
April 2008
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
I. REVENUES FROM OPERATIONS ($):
(A) ELECTRICITY SALES: .
RESIDENTIAL $0 $27] $68,459,083 $71,209,427 $74,070,266 $213,739,048
GENERAL SERVICE (A-I) $0 $332,029 $16,246,125 $]6,911,607 $17,591,030 $51,080,79]
SMALL TIME-OF-USE (A-6) $0 $277,770 $5,769,373 $6,067,692 $6,311,462 $]8,426,297
ALTERN. RATE FOR MEDIUM USE (A-lO) $0 $15,499,5] 2 $21,734,676 $22,664,751 $23,575,307 $83,474,246
500 - 900kW DEMAND (E-19) $0 $6,597,654 $9,049,315 $9,375,412 $9,752,069 $34,774,45]
1000 + kW DEMAND (E-20) $0 $3,904,820 $5,405,411 $5,633,713 $5,860,048 $20,803,993
SlREET LIGHTING & TRAFFIC CONlROL $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 $426,859,577
II. COST OF OPERATIONS ($):
(A) ADMINISTRATIVE & GENERAL (A&G):
STAFFING $451,067 $2,661,067 $3,092,725 $3,185,507 $3,281,072 $12,67],437
INFRASlRUcruRE $139,500 $192,000 $157,500 $162,225 $167,092 $818,317
CONlRACTOR COSTS $434,833 $1,607,417 $2,608,875 $2,635,255 $2,714,313 $10,000,693
IOU FEES (INLCUDING BILLING) $200,023 $187,286 $1, ]28,200 $1,024,786 $],055,529 $3,595,825
CONTRACT STAFF $0 $0 $0 $0 $0 $0
SUBTOTAL - A&G $1,225,423 $4,647,770 $6,987,300 $7,007,773 $/,218,006 $27,086,271
(B) CCA PROGRAM OPERATIONS:
ELECTRICITY PROCUREMENT $0 $22,781,412 $107,727,159 $110,974,279 $114,317,379 $355,800,229
RENEW ABLE PORTFOLIO ADJUSlMENT $0 $1,422,695 $9,284,04] $8,400,44] $7,507,772 $26,614,948
SUBTOTAL - CCA PROGRAM OPERA TONS $0 $24,204,106 $117,011,200 $119,374,720 $] 21,825,152 $382,415,]77
TOTAL COST OF OPERATION $1,225,423 $28,85],876 $123,998,499 $126,382,492 $129,043,157 $409,501,448
CCA PROGRAM SURPLUS / (DEFICl1) ($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 close for the renewable resource project would be winter 2011. The
financing would be in the range of a 20 to 30 year term.
9 April 2008
7. 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
1/ 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
onc~ 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 JP A 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 JP A.
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 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 JP A 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
April 2008
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 (JP A'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/]P A (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
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 April 2008
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 and the eleven cities located therein could be organized, governed, operated, and
financed. Many aspects included within this business plan are universally applicable to any
local government(s) 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 develoJ?ed 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 SJVP A 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
April 2008
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 JP A'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
supporting this business plan utilize energy prices that were offered by private energy suppliers
to the East Bay Communities and the SJVP A.
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 seconq decision point occurs after
the JP A 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 JP A.
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 JP A 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 will continue to provide all non-generation-
13
April 2008
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.
4t
.~ rtmlil5
~I
,
.~
.~
.fh
s
,
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 implementation 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 April 2008
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 SJVP A, which
represents municipalities in the greater Fresno area, on January 29, 2007. Subsequent to this
submittal, the SJvp A 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
SJVP A 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 SJVP A 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.
15 April 2008
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 JP A. 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 Clean Energy. Formation of the JP A will be a
significant milestone. Once formed, the JP A 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 voter~ 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 JP A would require at least three participants, including
the County of Marin, the City of San Rafael and the City of N ovato, to execute the JP A
agreement to become effective.
7 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 April 2008
Timeline for Implementation
ACTIVITY
lete
City and County Ordinances
A
17
TIMELINE
March 2008
March 2008
March 2008
March 2008
March 2008 -
November 2008
April 2008 -
November 2008
December 2008
+30 Da s
+120 Da s
+120 Da s
+120 Da s
+ 180 Days
+200 Da s
+230 Da s
+240 Da s
+260 Da s
+270 Da s
+270 Da s
+270 Da s
+330 Da s
April 2008
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 ("JP A"). 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
JP A 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 JP A (and pass a related
ordinance in accordance with state law). For purposes of this business plan, the new JP A 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.
18
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 suppott and recommendations to
the Board in these regards. The following chapter contains proposed elements of a JP A
agreement. Once the principles are agreed to by representatives of the county and cities, a JP A
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
April 2008
Program Organization
Energy Commission
Legal
Credit
Resource Planning
Controller
Rates
Financial Planning
Portfolio Operations
Account Services
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 JP A 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 [500/0/12]) 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
April 2008
V oting Percentages for the Second Tier Vote
Estimated Percent Load Voting Pro Rata Total Voting
of Total Program Percentage Percentage Percentage
Member Load (50%) (500/0) (Tier 2)
Belvedere 0.79% 0.40% 4.17% 4.570/0
Corte Madera 5.70% 2.85% 4.17% 7.020/0
Fairfax 1.78% 0.89% 4.17% 5.06%
Larkspur 4.79% 2.40% 4.17% 6.570/0
Marin County 25.05% 12.52% 4.17% 16.69%
Mill Valley 4.88% 2.44% 4.17% 6.610/0
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% 5.970/0
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% 5.780/0
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, in 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 [500/0/12]) 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.
21
April 2008
Alternative Voting Percentages for the Second Tier Vote
Estimated Percent Account- Based Pro Rata Total Voting
of Total Program Voting Percentage Percentage Percentage
Member Accounts (50%) (500/0) (Tier 2)
Belvedere 0.95% 0.47% 4.17% 4.64%
Corte Madera 3.87% 1.94% 4.17% 6.11%
Fairfax 3.07% 1.53% 4.17% 5.70%
Larkspur 5.48% 2.74% 4.17% 6.91%
Marin County 24.96% 12.48% 4.17% 16.65%
Mill Valley 5.60% 2.80% 4.17% 6.97%
Novato 19.20% 9.60% 4.17% 13.77%
Ross 0.80% 0.40% 4.17% 4.57%
San Anselmo 4.94% 2.47% 4.17% 6.64%
San Rafael 22.93% 11.46% 4.17% 15.63%
Sausalito 4.35% 2.17% 4.17% 6.34%
Tiburon 3.86% 1.93% 4.17% 6.10%
100% 50.0% 50.0% 100.000/0
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 JP A
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, FinancelBudget/ 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/Tennination of Participation
The proposed principles for a JP A 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
April 2008
A JP A Member would be able to withdraw itself from the JP A 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 M~mber withdrawing from the JP A 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 JP A agrees to disband would
the requirement of Board representation by all Members cease.
Termination of Marin Clean Energy
The proposed principles for a JP A 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 JP A 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 JP A
Agreement and Program Agreement No.1 (PA-1). Each of these agreements and its functions
are discussed below.
Joint Powers Agreement
The JP A 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
April 2008
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 JP A facilities located within the jurisdiction of that Member.
Any amendments to the JP A 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-l, 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
JP A Agreement specifies the governance provisions of MCE, which is discussed in greater detail
below.
Program Agreement No.1
P A-I would outline the framework for the CCA Program, and transfer the participating
Members' authority under AB 117 to MCE. Approval of PA-l by a participant would authorize
the initiation of the CCA Program for its jurisdiction, subject to a commencement notice to be
made by the JP A Board. It is anticipated that the county and cities would consider approval of
P A-I 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
April 2008
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.
Intee;rated 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.
~ Scheduling 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
April 2008
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 forth in bond covenants. The Board will have the flexibility to consider rate
adjustments within certain ranges, provided that the overall revenue requirement is achieved;
this provides an opportunity for economic development rates or other rate incentives.
Financial Management/Accounting
The 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
April 2008
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
April 2008
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
dire~t 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
MCE Board of Directors
Executive Director
Ro les/Functions/ Activi ties
Executive/Poli /Le al
Finance
Energy Supplier
Rates & Support
Rate policy
Rate design
Cost-o -service
Resource Planning
Load research
Load forecasting
Su I -side/Demand side
Contract Mana ement - RFP/RFQ
Customer Service
Account representatives
Ener e cienc ro ram mana ement
Supply Operations
Procurement
Scheduling coordination
Settlements (lSO/Wholesale)
Short-term load orecastin
Account Management (Customer Information System)
Customer switching
New customer processing
Data exchange (EDI)
Payment processing (AR/AP)
Billing and retail settlements
Call center
Customer Account Services
Provider/Data Manager
MCE would enter into two key contracts with third parties to provide the day-to-day
operational functions necessary to procure electricity and manage customer account data. The
28
April 2008
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-te:on (two to five years), and
long-term anticipated staffing roles.
29
April 2008
Expectations for Staffing Roles
Near-Term
Function Start-Up (2 to 5 Years) Long-Term
Program Governance MCE Board MCE Board MCE Board
Program Management MCEED MCEED MCEED
Outreach MCEED MCEED MCEED
Customer Service MCEED MCEED MCEED
Key Account Management MCEED MCEED MCEED
Regulatory Third Party MCEED MCEED
(MCE ED and (Regulatory Analyst (Regulatory Analyst
Regulatory Analyst support) support)
support)
Legal MCE ED MCEED MCEED
Finance MCEED MCEED MCEED
Rates: Approve MCE Board MCE Board . MCE Board
Develop MCE ED (third Party MCE ED (third Party MCEED
support) support)
Resource Planning Third Party MCE ED (third party MCEED
(MCE ED support) support)
Energy Efficiency Third Party Third Party MCE ED (Program
(MCE ED and Energy Efficiency
Program Energy Staff)
Efficiency Staff
support)
Resource Development MCE ED (third party MCE ED (third party MCEED
support) support)
Portfolio Operations Third Party Third Party MCEED
(MCE ED support)
Scheduling Coordinator Third Party Third Party Third Party
(potentially MCE ED)
Data Management Third Party Third Party 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, As~istant 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
April 2008
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
April 2008
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~
o
~
-
o
~
o
~
.5
.......
.......
C'O
en
ca
'0
ol-'
..0
;j
CJ')
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
Staff (Full Time
Position Equivalents)
Management
Executive Director 1.0
Policy Analyst 1.0
Administrative Assistant 1.0
Finance and Rates
Manager 1.0 .
Rates Analyst 1.0
Accounting/B illing Analyst 1.0
Sales and Marketing
Manager 1.0
Account Representative 4.0
Communications Specialist 1.0
Administrative Assistant 1.0
Energy Efficiency
Manager 1.0
Project Manager 3.0
Regula tory
Manager 1.0
Regulatory Analyst 1.0
Information Technology
IT Specialist 1.0
Human Resources
HR Specialist 0.5
Total Staffing 20.5
33
April 2008
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 in MCE meeting over 8 0 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 partnership(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 capacity is in place
34 April 2008
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 1 - 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
cities 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
April 2008
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 1.8 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 percent participation ill 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 Plan 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 mix 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-lO, E-19 and E-20 customer classes.
36
April 2008
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
long-term 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.
Beginning 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-aver-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
April 2008
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 a new 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
deh\Clct from shareholder profits. With this in mind, MCE may develop unique rate schedules
that create specific incentives for owners of distributed renewable capacity, ensuring 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 b~havior, 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
(GWH)
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 -1,271 -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 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 (GWh)
Renewable Resources
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 Resources
Generation 0 0 0 0 0 0 0 0 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 1,337
Energy Open Position (GWh) 0 0 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
April 2008
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
April 2008
Marin Clean Energy
Enrolled Retail Service Accounts
Phase-In Period (End of Month)
Ian-IO May-IO Ian-II
Marin Customers
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:
Marin Clean Energy
Retail Service Accounts (End of Year)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Marin Customers
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 1,073 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 & Traffic 186 542 545 548 550 553 556 559 561 564
Ag & Pump. 1 177 178 179 180 181 182 183 183 184
Total 1,759 111,101 111,657 112,215 112,776 113,340 113,907 114,476 115,049 115,624
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
(GWH)
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 1,271 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 UFE 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 April 2008
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
April 2008
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
\ 174
May 66 172 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:
Marin Clean Energy
Capacity Requirements
(MW)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Demand (MW)
Retail Demand 72 228 229 230 231 232 234 235 236 237
Distributed Generation (4) (5) (6) (8) (9) (10) (12) (12) (13) (13)
Energy Efficiency (1) (2) (3) (3) (3) (3) (3) (3) (3)
Losses and U FE 5 16 15 15 15 15 15 15 15 15
Total Net Peak Demand 73 237 236 235 234 234 234 235 235 236
Reserve Requirement (%) 15')(, 15% 15% 15% 15% 15% 15% 15% 15% 15%
Capacity Reserve Requirement 11 36 35 35 35 35 35 35 35 35
Capacity Requirement Including 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
approximateJy 32 to 102 MW as shown in the following table:
Marin Clean Energy
Local Capacity Requirements
(MW)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
PG&E Planning Area System Peak (MW) 22,425 22,717 23,012 23,311 23,614 23,921 24,232 24,547 24,866 25,189
Total Capacity Requirement (115%) 25,789 26,124 26,464 26,808 27,156 27,509 27,867 28,229 28,596 28,968
Authority Peak (MW) 73 237 236 235 234 234 234 235 235 236
Authority Share of Planning Area 0.3% 0.9% 0.9% 0.9% 0.9% 0.9% 0.8% 0.8% 0.8% 0.8%
Local Capacity Requirement - Greater Bay Area 4,896 4,959 5,024 5,089 5,155 5,222 5,290 5,359 5,429 5,499
Local Capacity Requirement - Other PG&E 6,232 6,313 6,395 6,478 6,562 6,648 6,734 6,822 6,910 7,000
Authority Local Capacity Requirement Greater Bay 14 45 45 45 45 44 44 45 45 45
Authority Local Capacity Requirement Other PG&E 18 57 57 57 57 57 57 57 57 57
42
April 2008
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 renew abIes 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 tJ:le 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" (IPT), 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 IPT will be permitted upon demonstration of one or more of the
following: 1) insufficient response to a request-far-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.
43
April 2008
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
(MWH)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales 261,264 1,222,384 1,219,080 1,219,581 1,223,812 1,228,073 1,232,365 1,238,339 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 52,253 192,224 (661) 100 846 852 858 1,195 904
Annual Procurement Target 52,253 244,477 243,816 243,916 244,762 245,615 246,473 247,668 248,572
'Yo of Current Year Retail Sales 4% 20% 20% 20% 20% 20% 20% 20% 20'Yc,
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.
Marin Clean Energy
RPS Requirements and Program Renewable Energy Targets
(MWH)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales (MWh) 261,264 1,222,384 1,219,080 1,219,581 1,223,812 1,228,073 1,232,365 1,238,339 1,242,859 1,249,170
Annual RPS Target (Minimum MWh) 52,253 244,477 243,816 243,916 244,762 245,615 246,473 247,668 248,572
Program Target (% of Retail Sales) 5601.. 70% 70% 70% 81% 81% 81% 81% 81% 81%
Program Renewable Target (MWh) 145,048 857,657 855,339 855,691 985,245 988,676 992,131 996,940 1,000,579 1,005,660
Surplus In Excess of RPS (MWh) 145,048 805,404 610,862 611,875 741,329 743,914 746,517 750,467 752,911 757,088
Annuallncreasc (MWh) 145,048 712,609 (2,318) 352 129,555 3,431 3,456 4,809 3,639 5,081
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
April 2008
and the cleanest non-renewable (natural gas-fired) resources would supply the remammg
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. Through a power services
agreement, MCE would obtain full req~irements 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.
45
April 2008
Marin Clean Energy 2011 Resource Mix
IlillI Renewable Market Purchases
II Conventional Purchases
Marin Clean Energy 2017 Resource Mix
180/0
190/0
[El Renewable Market Purchases
II Conventional Purchases
D Renewable Generation (At Cost)
Purchased Power
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
April 2008
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 (700/0 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 2020.9 The vast majority of the resource
9 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; ].Hamrin, R. Dracker, ]. Martin, R. Wiser, K. Porter, D. Clement, M. Bolinger; November 2005.
47 April 2008
potential identified by the CEC is located in Southern California, concentrated in four specific
areas: Tehachapi area and Riverside County wind resources (2,800 MW), utility-scale solar in
the Southern California deserts (1,000 MW), and geothermal in the Imperial Valley (1,600 MW).
There are an estimated 450 MW of resources in the PG&E territory economically developable by
2010, primarily represented by wind resources in Solano and Alameda Counties (400 MW) and
geothermal (45 MW) near the Geysers.
Near 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 larget 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)
Resource Type PG&E Area SeE Area SDG&E Area10
Geothermal 1,576,800 0 5,085,180
Wind 525,236 4,780,800 394,200
Biomass 525,000 1,094,562 156,366
Total 2,627,036 5,875,362 5,635,746
Source: Community Choice Aggregation Demonstration Project; Renewable Resource
Development Roadmap; 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).l1 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
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 Power link 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 pricing nodes.
48 April 2008
deliverable to the PG&E service territory. A study prepared for Marin County identified nearly
850 MW of renewable resource potential within the County, capable of producing
approximately 1,300 GWh per year.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 CAIS0.15 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
12 Increasing Renewable Energy Resources in the County of Marin, Jody London Consulting, November 11, 2007.
13 The cost of potential congestion charges has been included in the risk analysis presented in Chapter 4.
14 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.
49 April 2008
access to renewable resources.16 These four projects are projected to come on-line between 2008
and 2010, pending CAISO approval, at a total estimated cost ranging between $171 and
$455 million. These four renewable-focused transmission projects are identified in the following
table:
PG&E Transmission Expansion Plan Summary
Proj ect Title Purpose County Proj ect Scope CAISO Expected Cost Targeted
\ and Approval Capacity Range In-Service
Benefit Status Increase ($) Date
(MW)
Vaca Dixon - Access Solano Reconductor 230 Not Yet Approx.300 20-50M May 2008
Contra Costa Resource k V Lines MW when
230k V completed
Reinforcement w/other
projects
Bogue Junction Access Sutter Reconfigure 115 Not Yet Not 1-5M May 2009
Reconfiguration Resource k V lines at Bogue Published
Junction
Midway - Access Fresno, Increase Not Yet Approx. 100- 2010
Gregg 500k V Resource Kings & Transmission 1,250 MW 200M
Line Kern Capacity to
Access Resources
Vaca Dixon - Access Solano Increase Not Yet Approx. 300 50-200M May 2010
Sobrante - Resource and Transmission MW when
Moraga 230k V Contra Capacity to completed
Reinforcement Costa Access Resources 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.
16 PG&E 2006 Electric Grid Expansion Plan, December 29, 2006.
50
April 2008
Other projects under consideration by PG&E include those considered by the Northwest
Transmission Assessment Committee (NTAC), which would bring renewable and other
generating resources to California from Canada and the Pacific Northwest, a submarine
transmission interconnection to British Columbia from northern California and the Frontier
Line, which would connect California to Wyoming capacity markets (primarily wind and
"clean" coal). These projects have not yet been fully developed and are still being studied by
PG&E.
As :tloted 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 resources17:
~ 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 (NCP A), that are currently developing renewable resources.
It bears mentioning that MCE will be in competition for renewable resources with the three
investor owned utilities, which together require nearly 12 million MWh annually to meet their
RPS requirements by 2010. Over the longer term, the transmission expansion plans of the
utilities will provide additional resource options for 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
17 In the long term, new technologies such as wave or tidal energy may become economically feasible as well.
51 April 2008
economic resources for their own portfolio needs during the early years of the Program. IS 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, pro actively 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 Proj ect Summary
Generation Type Wind
Location Greater Bay Area (e.g. Solano County)
Year On Line 2014
Capacity 150 MW
Production 450,702 MWh Per Year
Total Initial Cost Approx. $350 Million
A verage Production Cost $85 to $105 Per MWh
Generation Type Biomass
Location Marin County or the California Central Valley
Year On Line 2014
Capacity 50MW
Production 343,392 MWh Per Year
Total Initial Cost Approx. $125 Million
A verage Production Cost Approx. $65 to $80 Per MWh
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
18 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.
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 options.20
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 ROl-08-028, ATTACHMENT 3 ENERGY EFFICIENCY POLICY MANUAL FOR POST-2005
PROGRAMS, Page 2, Rule 11.1.
20 Ibid., Page 3, Rule 11.3.
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
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 1.0% 2,774 $1,889,983
Commercial 576,235,343 78,085,059 59,356,212 7,380,674 1.3% 1,334 $874,346
Industrial 107,454,070 15,924,110 14,539,192 255,323 0.2% 39 $37,825
Composite 1,416,529,661 311,943,461 181,251,677 15,095,774 1.1% 4,147 $2,802,154
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 t he estimated energy efficiency potential for each type of
energy efficiency initiative:23
21 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 10: PGE0211.01, May 24,2006, Figure 12-2: Distribution of Electric Energy Market Potential, Existing Incentive
Levels through 2016.
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 6.0%
Industrial New Construction 1.0%
Emerging Technologies 7.0%
The retrofit of existing buildings represents 85 percent of the total forecast energy efficiency
market potential. Studies show that the residential customer sector presents the largest
untapped efficiency gains.
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).
55 April 2008
goal would displace approximately 30 percent of MCE's local capacity requirement within the
Greater Bay Area.
Total Capacity Requirement (MW)
Demand Response Target
Percentage of Local Capacity Requirment
\
Marin Clean Energy
Demand Response Goals
(MW)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
84 273 271 270 270 269 269 270 270 272
14 14 13 13 13 13 14 14 14
0% 30'X, 30% 30% 30% 30% 30% 30% 30% 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.25
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.
Distributed 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. A verage 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.
56
April 2008
Residential Photovoltaic Costs
Size (KW) 1 2
Capacity Factor 17% 17%
Production (KWh/Year) 1,489 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 30 30
Rate 8.5% 8.5%
Monthly Payment $41.5 2 $98.42
Average Cost ($/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 5.
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 $2.2
billion of funding to target installation of 1,940 MW of solar systems within the investor owned
utility service areas by 2017. All electric customers of PG&E, SCE, and SDG&E are eligible to
apply for incentives. Approximately 44 percent of program funding is allocated to the PG&E
service territory. Assuming solar deployment would be proportionate to funding, the program
is intended to yield approximately 775 MW of solar within the PG&E service area. A minimum
of 13 MW should be deployed within the jurisdictional boundaries of MCE.
California Solar Initiative Deployment
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
IOU Territory Target (MW) 176 353 529 705 882 1,058 1,235 1,411 1,587 1,764 1,940 1,940
Total Funding ($MiIlions) 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% 440/0 40olr, 40'J{, 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) 4 9 10 12 12 13 13
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 th~ 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 C02 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
Marin Clean Energy Renewables (MWh)
Renewables Per RPS (MWh)
Program Renewable Impact (MWh)
C02 Reduction - Low (tonnes per year)
C02 Reduction - High (tonnes per year)
2010
145,048
44,415
100,633
40,253
71,148
2011
857,657
244,477
613,180
245,272
433,518
2012
855,339
243,816
611,523
244,609
432,347
2013
855,691
243,916
611,774
244,710
432,524
2014
985,245
244,762
740,483
296,193
523,521
2015
988,676
245,615
743,061
297,225
525,344
2016
992,131
246,473
745,658
298,263
527,180
2017
996,940
247,668
749,273
299,709
529,736
2018
1,000,579
248,572
752,007
300,803
531,669
2019
1,005,660
249,834
755,826
302,330
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.
58
April 2008
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.
59
April 2008
...,," """ "." ", <<" ":;; " "': ^' ",
,I.....I.I-I_IJI~li.llall 0' , ' " '," ~" ~ ,'" ,,<< ",iC,,;:"\'<<o~,';ii
<< " " ' " '" " ':-. >... > v
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;
~ Contractor Costs;
~ Infrastructure Requirements;
~ Billing Costs;
~ Scheduling Coordination;
~ Grid Management Charges; and
~ Franchise Fees.
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.
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
lOp Electric Rate ($/MWh)
Variance ($/MWh)
Variance in Generation Rate (%)
Impact to Monthly Residential Customer Bill (%)
$112.34
$93.61
($18.72)
-20.0%
-10.3%
$110.81
$92.34
($18.47)
-20.0%
-10.2%
$114.75
$95.63
($19.13)
-20.0%
-10.4%
$118.77
$98.97
($19.79)
-20.0%
-10.5%
CATEGORY
2010
2011
2012
2013
MCE's Electric Rate ($/MWh)--25/51 % 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. The power produced by this new renewable generating
capacity would be delivered to MCE at production costs, which 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
27 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.
62
April 2008
MARIN CLEAN ENERGY
AVERAGE PROGRAM PREMIUM (MONTHLY)
CUSTOMER USING 500KWh/MONTH
$8.00 ~ ~ .
I
$6.00 +-
$4.00
:=
f-4
Z
o
~ ($2.00)
~
~ ($4.00) I-
~ ($6.00)' ~ ~'\. ~~\.'1- _ 'J,.~"-.~ _~~'\.~"l.~'\.<::J _
j ($8.00)
t-J
o ($10.00) -- n_______________ ------~-
Q ($12.00)
($14.00)
($16.00)
$2.00
$0.00
-,
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 payments received and
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 emollment 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
feastbility 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
$18 million. Power supply costs below approximately 8.8 cents per kWh for the four-year
startup period would enable the program to at least match PG&E's rates for customers
subscribing to the Light Green Tariff. Conversely, power supply costs above this figure would
jeopardize the program's potential to offer Light Green Tariff rates that are equivalent to PG&E
during this time period, because CCA rates would be higher than those charged by PG&E.
64
April 2008
Marin Clean Energy
Summary of CCA Program Implementation
(January 2009 through December 2013)
CATEGORY 2009 2010 2011 2012 2013 TOTAL
I. REVENUES FROM OPERATIONS ($):
(A) ELECTRICITY SALES:
RESIDENTIAL $0 $271 $68,459,083 $71,209,427 $74,070,266 $213,739,048
GENERAL SERVICE (A-I) $0 $332,029 $16,246,125 $16,911,607 $17,591,030 $51,080,791
~MALL TIME-OF-USE (A-6) $0 $277,770 $5,769,373 $6,067,692 $6,311,462 $18,426,297
ALTERN. RATE FOR MEDIUM USE (A-I0) $0 $15,499,512 $21,734,676 $22,664,751 $23,575,307 $83,474,246
500 - 900kW DEMAND (E-19) $0 $6,597,654 $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 $426,859,577
II. COST OF OPERATIONS ($):
(A) ADMINISTRATIVE & GENERAL (A&G):
STAFFING $451,067 $2,661,067 $3,092,725 $3,185,507 $3,281,072 $12,671,437
INFRASTRUcruRE $139,500 $192,000 $157,500 $162,225 $167,092 $818,317
CONTRACTOR COSTS $434,833 $1,607,417 $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 $0 $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:
ELECTRICITY PROCUREMENT $0 $22,781,412 $107,727,159 $110,974,279 $114,317,379 $355,800,229
RENEW ABLE PORTFOLIO ADJUS1MENT $0 $1,422,695 $9,284,041 $8,400,441 $7,507,772 $26,614,948
SUBTOTAL - CCA PROGRAM OPERA TONS $0 $24,204,106 $117,011,200 $119,374,720 $121,825,152 $382,415,177
TOTAL COST OF OPERATION $1,225,423 $28,851,876 $123,998,499 $126,382,492 $129,043,157 $409,501,448
CCA PROGRAM SURPLUS / (DEFICI1) ($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.
65
April 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-I) $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-I0) $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 infrastructure that MCE 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.
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
. 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.
67
April 2008
Enrollment 1 - Pilot Phase 1 Notification and
Start-up Costs Pre-Startup Phase Cutover 1 Operations Enrollment Period Cutover 2
Staffing Jun-09 Jul-Q9 Aug-09 Sep-09 Oct-09 Nov-Q9 Dec-09 Jan-lO Feb-lO Mar-lO Apr-lO May-lO
FTEs 4 4 4 4 4 5 9 9 14.5 18.5 20.5 20.5
Cost $ 53,196 $ 53,196 $ 53,196 $ 53,196 $ 53,196 $ 70,338 $ 114,750 $ 114,750 $ 180,200 $ 218,379 $ 238,638 $ 238,638
Infrastructure
Cost $ 12,000 $ $ $ 73,125 $ 13,125 $ 16,125 $ 25,125 $ 13,125 $ 29,625 $ 25,125 $ 19,125 $ 13,125
Contractor Costs
Advertising/Comm. $ $ $ $ $ $ 20,000 $ 20,000 $ 10,000 $ 20,000 $ 50,000 $ 50,000 $ 10,000
Consulting $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417 $ 35,417
Legal $ 16,000 $ 16,000 $ 16,000 $ 16,000 $ 16,000 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667
Data Management $ $ $ $ $ $ 16,792 $ 16,792 $ 25,188 $ 25,188 $ 142,729 $ 142,729 $ 142,729
Subtotal Contractor Costs $ 51,417 $ 51,417 $ 51,417 $ 51,417 $ 51,417 $ 88,875 $ 88,875 $ 87,271 $ 97,271 $ 244,813 $ 244,813 $ 204,813
IOU Fees (Including Billing)
Cost $ $ $ $ 98,390 $ 98,390 $ 1,633 $ 1,610 $ 6,598 $ 4,421 $ 55,373 $ 49,189 $ 52,860
\
Grand Total $ 116,613 $ 104,613 $ 104,613 $ 276,128 $ 216,128 $ 176,971 $ 230,360 $ 221,744 $ 311,517 $ 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.
Enrollmentl- Phase 1
Staffing Plan (FfEs) Pre-Startup Pilot Phase Cutover 1 Operations Notification and Enrollment Period Cutover 2
Staff Jun-09 Jul-09 A ug-09 Sep-09 Ocl-09 Nov-09 Dec..()9 Jan-l0 Feb-l0 Mar-l0 Apr-l0 May-l0
Management
Executive Director $ 21,250 $ 2J,250 $ 21,250 $ 2J,250 $ 21,250 $ 21,250 $ 21,250 $ 21,250 $ 21,250 $ 21,250 $ 21,250 $ 21,250
Policy Analyst $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 1IJ,129 $ 1IJ,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129
AdministratIve Assistant $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792 $ 7,792
Finance and Rates
Manager $ $ $ $ $ $ 17,142 $ 17,142 $ 17,142 $ 17,142 $ 17,142 $ 17,142 $ 17,142
Hates Analyst $ $ $ $ $ $ $ $ $ $ $ 1IJ,129 $ 1IJ,129
Aca.lUntmglBilling Analyst $ $ $ $ $ $ $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 1IJ,129
Admlnistrativ(.' Assistmt $ $ $ $ $ $ $ $ $ $ $ $
Sales And Marketing
Manager $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025
ACL'()Unt Represent<1tives $ $ $ $ $ $ $ $ $ $ 30,388 $ 40,517 $ 40,517
CommlDlications Spc..'Cialist $ $ $ $ $ $ $ $ $ 1IJ,129 $ 10,129 $ 10,129 $ 10,129
Administrative Assistant $ $ $ $ $ $ $ $ $ $ 7,792 $ 7,792 $ 7,792
Energy Efficiency
Manager $ $ $ $ $ $ $ $ $ g,025 $ 14,025 $ 14,025 $ 14,025
Project Manager $ $ $ $ $ $ $ $ $ 36,231 $ 36,231 $ 36,231 $ 36,231
Regulatory
Manager $ $ $ $ $ $ $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025 $ 14,025
Regulatory Analyst $ $ $ $ $ $ $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 1IJ,129 $ 1IJ,129
lnfomlation Technology
IT Specialist $ $ $ $ $ $ $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129 $ 10,129
Human Resources
HR Specialist $ $ $ $ $ $ $ $ $ 5,065 $ 5,065 $ 5,065 $ 5,065
Subtotal Staffing $ 53,196 $ 53,196 $ 53,196 $ 53,196 $ 53,196 $ 70,338 $ 114,750 $ 114,750 $ 180,200 $ 218,379 $ 238,638 $ 238,638
Estimated Infrastructure Costs
Infrastructure or overhead needed to support the organization
peripheral equipment, office furnishings, office space
estimated at $240,000 during program startup. Office space and utilities are ongoing monthly
expenses that will begin to accrue before revenues form program operations commence and are
therefore assumed to be financed along with other startup costs.
includes computers
and utilities. These expenses
and
are
Infrastructure Costs ($/Month) Pre-Startu p Cutover 1 Phase 1 Notification and Cutover 2
Enrollment 1 - Pilot Phase Operations Enrollment Period
Jun-09 JuI-09 Aug-09 Sep-09 Oct-Q9 Nov-09 Dec-09 Jan-lO Feb-lO Mar-lO Apr-lO May-lO
Computers $ 12,000 $ $ $ $ $ 3,000 $ 12,000 $ $ 16,500 $ 12,000 $ 6,000 $
Furnishings $ $ $ $ 60,000 $ $ $ $ $ $ $ $
Office Space $ $ $ $ 10,938 $ 10,938 $ 10,938 $ 10,938 $ 10,938 $ 10,938 $ 10,938 $ 10,938 $ 10,938
Utilities $ $ $ $ 2,188 $ 2,188 $ 2,188 $ 2,188 $ 2,188 $ 2,188 $ 2,188 $ 2,188 $ 2,188
Subtotal Infrastructure $ 12,000 $ $ $ 73,125 $ 13,125 $ 16,125 $ 25,125 $ 13,125 $ 29,625 $ 25,125 $ 19,125 $ 13,125
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.
Utility Transaction Fees (UnitslMonth) Pre-Startup Enrollment I - Pilot Phase Cutover I Phase I Notification and Cutover 2
Operations Enrollment Period
Utilitv Fees Jun.{l9 Jul-09 Aug.{l9 Sep-09 Oct.{l9 Nov-09 Dec-09 Jan-IO Feb-IO Mar-IO Apr-IO May-IO
Opt-Out Notifications
Per Account 562 562 562 562 122,208 122,208 1,188
Per Event 1 1 1 1 1 1 1
Post enrollment notification
Per Account 562 1,188
Service Ini tiation
Per Hour 1,200 1,200
Customer List
.
Per Event 1 1 1
Mass enrollment
Per Account 562 109,987
Per Event 1 1
Opt-Out Fees
Per Opt Out 6,110 3,666 13
Customer Contact Fee
Per Minute 34 8 6 8 7,332 1,833 1,222
Billing Fee
Per Account 562 562 562 562 1,750
Utility Transaction Fees ($lMonth) Pre-Startup Enrollment I - Pilot Phase Cutover I Phase I Notification and Cutover 2
Operations Enrollment Period
Utilitv Fees Jun.{l9 Jul.{l9 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-IO Feb-IO Mar-IO A pr-IO May-IO
Opt-Out Notifications
Per Account $ $ $ $ $ $ 202 $ 202 $ 202 $ 202 $ 43,995 $ 43,995 $ 428
Per Event $ $ $ $ $ $ 1,400 $ 1,400 $ 1,400 $ 1,400 $ 1,400 $ 1,400 $ 1,400
Post enrollment notification $ $ $ $ $ $ $ $ $ $ $ $
Per Account $ $ $ $ $ $ $ $ 225 $ $ $ $ 475
Service Initiation $ $ $ $ $ $ $ $ $ $ $ $
Per Hour $ $ $ $ 96,000 $ 96,000 $ $ $ $ $ $ $
Customer List $ $ $ $ $ $ $ $ $ $ $ $
Per Event $ $ $ $ 2,390 $ 2,390 $ $ $ $ 2,390 $ $ $
Mass enrollment $ $ $ $ $ $ $ $ $ $ $ $
Per Account $ $ $ $ $ $ $ $ 225 $ $ $ $ 43,995
Per Event $ $ $ $ $ $ $ $ 4,120 $ $ $ $ 4,120
Opt-Out Fees $ $ $ $ $ $ $ $ $ $ $ $
Per Opt Out $ $ $ $ $ $ $ $ $ $ 2,811 $ 1,686 $ 6
Customer Contact Fee $ $ $ $ $ $ $ $ $ $ $ $
Per Minute $ $ $ $ $ $ 31 $ 8 $ 5 $ 8 $ 6,746 $ 1,686 $ 1,124
Billing Fee
Per Account $ $ $ $ $ $ $ $ 421 $ 421 $ 421 $ 421 $ 1,312
Subtotal $ $ $ $ 98,390 $ 98,390 $ 1,633 $ 1,610 $ 6,598 $ 4,421 $ 55,373 $ 49,189 $ 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.
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April 2008
Contractor Costs ($/Month) Pre-Startup Enrollment 1 - Pilot Phase Cutover 1 Phase 1 Notification and Cutover 2
Operations Enrollment Period
Contractor Costs Jun-09 JuI-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-lO Feb-lO Mar-lO Apr-lO May-1O
General advertising $ $ $ $ $ $ 20,000 $ 20,000 $ 10,000 $ 20,000 $ 50,000 $ 50,000 $ 10,000
Legal $ 16,000 $ 16,000 $ 16,000 $ 16,000 $ 16,000 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667 $ 16,667
Resource Planning $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500 $ 12,500
Implementation Support $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917 $ 22,917
Customer Enrollment $ $ $ $ $ $ 8,396 $ 8,396 $ 8,396 $ H,396 $ 33,583 $ 33,5H3 $ 33,583
Customer Care (Call Center) $ $ $ $ $ $ 8,396 $ 8,396 $ 8,396 $ 8,396 $ 100,750 $ 100,750 $ 100,750
Accounts Receivable and Verification $ $ $ $ $ $ $ $ 8,396 $ 8,396 $ 8,396 $ H,396 $ H,396
Total Contractor Costs $ 51,417 $ 51,417 $ 51,417 $ 51,417 $ 51,417 $ 88,875 $ H8,875 $ 87,271 $ 97,271 $ 244,813 $ 244,813 $ 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.28 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.
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 catried 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%.
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 capi~al 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 less 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, SMUD, 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 Estimated Issuance
Amount
1. Start-Up and Working $6.4 million No longer than 7 years Mid 2009
Capital (Phase 1 and 2)
2. Working Capital (Phase $15.8 million No longer than 5 years Late 2010
3)
3. Renewable Resource $475 million 20-30 years Late 2011
Project Financings (aggregate)
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April 2008
Sensitivities and Uncertainties
The primary focus of this 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;
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
adva~ce 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.
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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:
)0> The impact of AB32, the Greenhouse Gas Reduction law; and
)0> The impact of PG&E's advanced metering infrastructure program.
AB32
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 trClding 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
75
April 2008
requirements and thus reduce overall electricity procurement costs. This is another area where
additional analysis may be warranted as PG&E's plans are implemented.
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April 2008
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 and operating
77 April 2008
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
enroUed 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 cU3tOI)ler 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).
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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 - 1/100 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 lnay 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
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.3D 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 m 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.
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
qua\ified 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
Lighting
PG&E rates are based on those contained in Advice Letter No. 3115-E-A (Effective January I, 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.
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 a re 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:
82
April 2008
Projected 2011 Revenues by Customer Class (Dollars)
$549,460
$21,734,676
$755,054 --
$68,459,083
Il.!1 Residential
II Small Commercial
o Medium Commercial 0 Large Commercial
II Industrial
m Street Lighting
II Agricultural
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.
83
April 2008
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 cus~omers, 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 within 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
April 2008
Administrative Fee for Service Termination
Customer Class Fee
Residential $5
Small Commercial $5
Medium Commercial $10
Large Commercial $25
Industrial $25
Street Lighting $10
Agricultural and Pumping $10
The customer CRC will be equal to a pro rata share of any above market costs of 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 CRS= 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&R.
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
85
April 2008
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 fQr failure to pay electricity
bills, and Rule 23 mandates that partial payments are to be allocated pro rata between PG&E
and the CCA. In most circumstances, customers would be returned to utility service for failure
to pay bills in full and customer deposits would be withheld in the case of unpaid bills. PG&E
would attempt to collect any outstanding balance from customers in accordance with Rule 23
and the related CCA Service Agreement. The proposed process is for two late payment notices
to be provided to the customer within 30 days of the original bill due date. If payment is not
received within 45 days from the original due date, service would be transferred to the utility
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
April 2008
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 (January 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 with 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 April 2008
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 web site, 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
April 2008
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 a~opted 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 SJVP A 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 supplier will be responsible
89 April 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
custbmer services needed for the Program (Customer Account Services) will also be solicited.
The 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.
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 functions.32
The tlata manager is responsible for the following services:
~ Data exchange with PG&E;
~ Technical testing;
~ Customer information system;
~ Customer call center;
~ Billing administration/retail settlements; and
~ Reporting and audits of utility billing.
Utilizing a third party for account services eliminates a significant expense associated with
implementing a customer information system. Such systems can cost from five to ten million
dollars to implement and take significant time to deploy. A longer term contract is appropriate
for this service because of the time and expense that would be required to migrate data to a new
system. Separation of the data management contract from the energy supply contract gives
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.
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 or'dinance 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 JP A termination, the Board would disband under the
provisions identified in its JP A 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.
92
April 2008
Termination by Members
The JP A 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 JP A 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 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 JP A agrees to
disband would the requirement of Board representation by all Members cease.
93
April 2008
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Appendix A: Pro Forma 2014 - 2025
Appendix B: Energy Efficiency Potential in the Marin Communities
App\endix C: List of Acronyms and Definitions
94
April 2008
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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
April 2008
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
remodels, 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
Existing Commercial
Existing Industrial
Residential New Construction
Commercial New Construction
Industrial New Construction
Emerging Technologies
53.0%
18.0%
14.0%
1.0%
6.0%
1.0%
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
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:
1'echnical 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 occu.r 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.36 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
34 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
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. 40
Gather and Develop Measure Technical Data (costs and savings) on efficient measure
opportunities.41
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.42
Step 2: Estimate Technical Potential
Estimating Technical Potential is accomplished using the following core equation:
Measure
Technical Potential
Total
=
Square Feet
Base Case
Equipment EUI x
kWh/ft2
x
Incomplete
Factor x
Feasibility
Factor
Applicability
Factor
x
where:
3710 CFR 430.32 Residential Air Conditioners and Heat Pumps and 10 CFR 431.97 Commercial Minimum
Cooling and Heating Efficiency Standards
38 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
41 2004-2005 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/ft2 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
requiremen ts.
99
April 2008
x
Savings
Factor
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) test43 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.
Energy 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
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 lack 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
~alifornia Energy Efficiency Potential Study, Itron May 2006 (2004 study).45
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:
44 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.
101
April 2008
Table 2-1 Baseline Planning Scenario Assumptions
Sector Measure Incentive Program Cost - Program Cost
Ca tegory percent Administra tion Incentives
Measure Cost
Residential48 All 33% 20% 80%
Commercial Lighting 32.6% 20% 80%
HVAC 45.8% 20% 80%
Refrigeration 60.9% 20% 80%
Office Equip. 50.0% 20% 80%
Industrial49 125 Measures 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 states50 "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, an d 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
49PGE0252.01 California Industrial Existing Construction Energy Efficiency Potential Study\, KEMA, May
2006
50 SPM Chapter 4, Total Resource Cost Test Definition, page 18
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.
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 J2 - 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
C02 - 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
April 2008
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
IPT - Incremental Procurement Target
IT -\Information Technology
JP A - 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
April 2008
SDG&E - San Diego Gas and Electric Company
SEP - Supplemental Energy Payment
SJVP A - San Joaquin Valley Power Authority
SMUD - Sacramento Municipal Utility District
VEE - Verification, Editing and Estimation
113
April 2008
/Jffc ell ~ :2
1814 FRANKLIN STREET
SUITE 720
OAKLAND, CALIFORNIA
94612
MRW
TEL 510.834.1999
FAX 510.834.0918
mrw@mrwassoc.com
MRW & ASSOCIATES
October 15, 2008
Ms. Peggy Curran
Town Manager
Town of Tiburon
1505 Tiburon Boulevard
Tiburon, CA 94920
Subject:
Community Choice Aggregation Review
Dear Peggy:
As requested by the Towns and Cities in Marin County, MRW & Associates Inc. (MRW) has
reviewed the "Marin-California Community Choice Aggregation Businesses Plan" (Business
Plan) prepared by Navigant Consulting, dated April 2008. Overall, we found no fatal flaws in the
Business Plan. It creatively proposes a workable path to providing green power to those in
Marin who want it while offering rates comparability and predictability to those who need it.
Nonetheless, we found one gap that we believe should be addressed before the communities
make a final, binding decision commitment to the CCA: the lack of a quantitative risk analysis
and a plan to address issues that arise from that analysis. In this letter, we discuss our rationale
for recommending the risk assessment, comment on some of PG&E' s criticisms of the Business
Plan, as well as point out a number of relatively minor clarifications that we feel would enhance
the Business Plan.
In performing this review, we considered the following documents:
· "Marin-California Community Choice Aggregation Businesses Plan" prepared by
Navigant Consulting, dated April 2008 (Business Plan);
· "January 2008 Draft CCA Business Plan for the Marin Communities Assumptions
Underlying Projected Operating Results," (Assumption Sheet);
· "Review of the Business Plan for the Marin County Community Choice Aggregation
Program," prepared by William B. Marcus, dated February 29, 2008 (Marcus February
29 review);
· PG&E's Comments on January 2008 Marin CCA Business Plan, dated March 5, 2008
(PG&E Comments);
Ms. Peggy Curran
October 15, 2008
Page 2
· "Review of PG&E' s March 5, 2008 Comments on the Business Plan for the Marin
County Community Choice Aggregation Program," prepared by William B. Marcus,
dated March 31, 2008 (Marcus Response to PG&E); and
· "Community Choice Aggregation Update and Risk Analysis," a presentation by Navigant
Consulting prepared For Marin County, May 16,2006
We also had telephone conversations and/or e-mail exchanges with you, Tim Rosenfeld, and
John Dalessi ofNavigant Consulting, Inc. to obtain clarification of certain aspects of the
Business Plan.
We found that the key underlying assumptions made in the Business Plan (e.g., opt-outs, PG&E
rates, renewable costs, gas prices, other procurement costs such as firming-up wind power) fall
within expected ranges. But the Business Plan does not explore the financial outcomes under sets
of other equally reasonable estimates for those values. Forecasts for these variables are better
expressed in ranges with probabilities of occurrence. Both the Marcus February 29 review and
the PG&E Comments point this out, with PG&E proffering alternative assumptions that, by its
calculations, result in CCA costs exceeding PG&E' s retail generation costs. While many of the
assumptions used by PG&E may be construed as self-serving, it illustrates the point that different
assumptions can lead to a radically different outcome.
Prior to the first draft of a Marin CCA business plan, Navigant Consulting conducted a Monte
Carlo risk assessment for a hypothetical Marin CCA, which was summarized in a presentation
dated May 16, 2006. While that risk assessment assumed a different buying strategy than the
Business Plan and was based on now-outdated costs, it illustrates the kind of analysis that is
needed to evaluate the Business Plan.
The minimum key elements that should be included in such a risk assessment include:
· Natural gas and wholesale power costs
· Nature of "fixed" bids from third party provider, including the premium above spot
power prices required to obtain a fixed price, full requirements contract with the
creditworthy third party provider bearing all customer attrition risk.
· Cost and performance of the renewable power developed by the CCA in the fifth year
· Customer-opt out assumptions
· Customer migration between the 100% Green and the Light Green options.
It is important that the risk assessment treat PG&E rates, the CCA Cost Responsibility Surcharge
(CRS, or exit fee) and CCA procurement costs as interrelated; all three all linked to underlying
wholesale power costs, natural gas prices and the cost of renewable energy, including renewable
energy credits. For example, low wholesale power costs will not only reduce the cost ofPG&E
power, it will increase the CCA CRS. If one does not acknowledge that the CCA CRS and
wholesale market prices are inversely related, then the risk assessment may miss important
feedbacks and understate risks faced by customers. It is our understanding from conversations
with Tim Rosenfeld and staff at Navigant that the 2006 risk assessment included the links
between these key factors.
MR W & Associates, Inc.
Ms. Peggy Curran
October 15, 2008
Page 3
Along those same lines, it will be important to ensure that the quantitative risk assessment
properly characterizes the assumed linkage (or lack of linkage) between the CCA' s retail rates
and underlying market costs. It is our understanding that one option being considered for the
Light Green rate option is to provide power at a rate that is discounted relative to comparable
setvice from PG&E and then to escalate the rate at a fixed rate. If this is the case, then the Light
Green rate option will not reflect future changes in natural gas or power prices. The quantitative
risk assessment should reflect whatever rate design the CCA plans to pursue.
With respect to specific issues raised in the PG&E Comments, we find some to be valid while
others are not. The concerns raised oy PG&E that we feel should be considered are:
.
Resource assumptions. PG&E' s points out that the Plan may not have included the full
cost of generation, (e.g., resource adequacy, ancillary services, renewable interconnection
costs, etc. ). We note that the Assumption Sheet accompanying the January 2008 draft of
the Business Plan included assumed values for these variables. For that reason, we
assume that the Plan reflected those factors.
.
Renewable assumptions. PG&E argues that the renewable cost and performance
assumptions presented in the plan are wrong, or at least overly optimistic. Based on our
familiarity with the cost and operational characteristics of renewable resources
considered in the Business Plan, we find that, while the Business Plan's assumptions are
perhaps optimistic (e.g., biomass power available at $65-80/MWh), PG&E's suggested
alternative costs are at the high end of the published spectrum of renewable power costs
while PG&E' s performance assumptions for those resources are the low end. I We further
note that there are two countervailing trends in renewable costs, particularly for wind
turbines: market demand and materials costs are keeping installed costs high, to the point
they have increased significantly since 2006, while manufacturing economies of scale
and competition among providers is exerting downward pressure. We cannot tell which
of these factors will dominate over the next five years, further illustrating the need of the
risk analysis.
.
Gas prices. PG&E argues that the gas prices used in the Business Plan are wrong while
the Marcus Response to PG&E argues that PG&E's gas price forecast is low compared to
the (at the time) current NYEMX futures prices. It is our understanding from Navigant
that the April 2008 Business Plan used a gas price forecast that is lower than that
assumed in PG&E's review.2 In the past year the futures prices for gas delivered in 2009
and beyond has swung by over $5/MMBtu. The following figure presents the variability
of forecasted burnertip gas prices for 2011-2013 over the past 9 months.
1 For example, it is doubtful that a developer would even install a wind turbine with the capacity factor
recommended by PG&E (23%).
2 Bumertip gas prices (i.e., the price paid by the end user, including all commodity and gas transportation charges)
were not included in the Business Plan. Rather, MRW received these from John Dalessi ofNavigant Consulting, Inc.
MR W & Associates, Inc.
Ms. Peggy Curran
October 15, 2008
Page 4
Burnlrtip GIS Price
$12
;
:I $6
:I
4It
$2
$0
2011 2012 2013
As can be seen, burnertip gas prices assumed in the Business Plan are significantly lower
than the other data series, showing that the Business Plan used conservative gas prices.
However, this does not obviate the need for a more structured risk assessment. The point
is not that PG&E's or the Business Plan's gas prices are right or wrong, but that gas price
volatility (and its impact on wholesale power prices, PG&E's generation rates, and exit
fees that customers of the CCA will have to pay when they join the CCA) must be
acknowledged and addressed in future CCA planning materials.
· PG&E retail rate escalation. The rate at which rates have, on average, escalated "over
the past few years" is highly dependent upon the period over which one is looking and, as
pointed out by Marcus, what factors are included in the generation rate. Using PG&E' s
data, over the past 10 years, from 1998 to 2008, rates have escalated on average at 2%
annually, while over the past 3 years (2005-2008) the escalation rate is 4%. As the
following figure shows, generation rates have been volatile, and a single simple historical
escalation rate is insufficient to capture the whole story. This is particularly true with
such new factors as RPS and greenhouse gas compliance issues not reflected in the
historical trends. This volatility supports the need for the risk assessment recommended
above.
PG&E System Average Generation Rate*
$0.12
$0.10
4%/yr.
----:::
2 .
$0.08
I $0.06
$0.04
$0.02
$0.00
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
. Source: PG&E March 5 Comments, Appendix 2 (verified in PG&E Advice Letters)
MR W & Associates, Inc.
Ms. Peggy Curran
October 15, 2008
Page 5
.
Cost of Renewable Energy Purchases. On a smaller matter, PG&E questions whether
the CCA would be able to purchase renewable power at cost from tax-exempt publicly
owned utilities (POUs), hence capturing the benefit of tax-free financing. While the
Marcus Response to PG&E accurately points out that POUs, given their tax-free status,
are limited as to how much power they can sell to for-profit entities, we doubt that a POU
with excess renewable power would not want to maximize the benefit of the renewable
asset on behalf of its ratepayers. As such, we find the assumption that the CCA could
acquire renewable power at cost from a POU to be questionable unless the CCA had a
financial stake in the POU's development of the renewable resources. Follow-up
conversations with Tim Rosenfeld and the final Business Plan suggest this latter option-
partnering with POU s early in the development process-was what was envisioned for
the CCA.
.
CCA CRS. As noted by PG&E, the Business Plan includes a discussion of the CCA
CRS, but does not consider what it might be under adverse conditions (e.g., low
wholesale prices). This should be addressed in future planning documents.
.
Opt out uncertainty. PG&E questions the CCA opt-out rates assumed in the Business
Plan, particularly for medium and larger customers. There are no California precedents
for a CCA opt-out rates. Furthermore, given Marin's unique marketing plan, which
emphasizes green power elements over offering discounted electric pricing, the national
precedents for CCA opt-outs-Ohio and Massachusetts-are of limited usefulness.
Therefore the sensitivity of the financial viability of the CCA must be explored with
respect to large-scale opt outs, particularly for the larger customers, in future planning
documents.
.
Termination Charges. The Business Plan calls for a Cost Recovery Charge (CRC) to be
paid by CCA customers who, after the opt-out period has ended, elect to take service
from PG&E or via direct access. We agree with PG&E that this CRC was not well
explained in' the Business Plan. We recommend that future planning documents provide a
more in-depth discussion of this issue, and perhaps even quantitatively bracket possible
Termination Charges. An unknown, vaguely described termination charge adds
unneeded uncertainty for price-sensitive customers.
Finally, we note several other areas in the Business Plan that could benefit from clarification:
.
The expected pricing for Light Green power. We understand from Tim Rosenfeld that
initially the pricing for this product is expected to be at or below PG&E' s generation rate
and will escalate with a fixed escalator. This should be made clear in the future CCA
planning documents, since this is not the same as rate parity with PG&E' s generation rate
(which is implied in the Business Plan);
.
Clarify the meaning of "100% Green" product. The Business Plan's description of
"100% Green" power conforms to industry standards for green power: that the correct
MR W & Associates, Inc.
Ms. Peggy Curran
October 15, 2008
Page 6
number of green-generated kilowatt-hours (or RECs) have been purchased or generated
by the CCA to cover the green kilowatt-hours sold. However, that may not necessarily
be clear to CCA participants selecting the 100% Green option (i.e., that the CCA will
require some amount of fossil- fired generation (for ancillary services, system balancing,
and resource adequacy) but on an accounting basis, the CCA will have produced or
purchased renewable power to fully cover the 100% green customer's energy use).
.
Customer risk associated with the Transition Charge. As discussed above, this aspect
of the CCA operation needs to be more clearly defined and even quantified. Future
planning documents should address the CCA' s position regarding the potential for
customers to face a Transition Charge if they were to install onsite generation. 3
.
"Switching" rules regarding migration between the 1000/0 Green and Light Green
rate options. It is not clear whether such migration will be allowed and, if it is, under
what conditions. This should be clarified in future CCA planning documents.
.
Date of financial closing for MCE-owned renewable generation. We note a minor
typo on page 71, which states that the closing date is late 2010. The correct anticipated
the closing date in the Business Plan is late 2011.
Any new business must plan not only a pathway to success, but also have a thorough
understanding of the challenges it faces and how it can meet those challenges. The Business
Plan has outlined its pathway to success. Future CCA planning documents need to also illustrate
that the management has an appreciation of the challenges the CCA will likely face as well as the
CCA management's plans to address those challenges.
We understand that the Towns and Cities in Marin County are not financially committed to the
JP A and still have a number of "offramp" opportunities after the JP A is formed. Given the
upside potential of the Marin Clean Energy CCA presented in the Business Plan and the
offramps still available to the Towns and Cities of Marin, we recommend that they continue in
their participation in the planning and development of the CCA. Following the issuance of the
quantitative risk assessment recommended here and the results of the third party bid, the Towns
and Cities of Marin will be well positioned to make an informed decision whether to move
forward with participation in the CCA or not.
Please feel free to give us a call at (510) 834-1999 if you have questions about this matter.
Best regards,
William Monsen
Principal
Mark Fulmer
Principal
3 In the PG&E service territory, customers might be charged an exit fee if they install onsite generation.
MR W & Associates, Inc.
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