HomeMy WebLinkAbout12-03-2013 ac mladen ss1
Community Choice Aggregation
Base Case Feasibility Evaluation
County of Marin
Prepared By Navigant Consulting, Inc
March 2005
2
3
EXECUTIVE SUMMARY
This report offers Navigant Consulting, Inc.’s (NCI) evaluation of the feasibility
of forming a Community Choice Aggregation program, pursuant to provisions
of Assembly Bill 117, whereby the County and the cities within the County
would aggregate the electric loads of customers within their jurisdictions for
purposes of procuring electrical services. Community Choice Aggregation
relates to electric generation services only. Delivery of the electric power would
continue to be provided over PG&E transmission and distribution facilities at
rates regulated by the California Public Utilities Commission (CPUC) and under
the same terms and conditions that apply today. Community Choice
Aggregation allows the County to provide retail generation services to customers
without the need to acquire transmission and distribution infrastructure. All
PG&E customers within the County would have the option of buying electricity
from the County or, alternatively, remaining as generation customers of PG&E
by exercising their rights to opt-out of the program.
AB 117 grants the County authority to competitively procure electric services
rather than continuing to rely on PG&E as the single supplier for electric services
provided to customers within the County. Implementation of Community
Choice Aggregation provides the community the power to choose what
resources will serve their loads. Expanded access to competitive suppliers and
local control of resource planning decisions provides opportunities to enhance
rate stability for customers, significantly increase utilization of renewable energy
resources, and generate electricity cost savings.
The detailed analysis performed for the County suggests that by forming a
Community Choice Aggregation program, backed by investments in generation
resources, the County program could:
x Achieve nominal electricity cost savings averaging $6.8 million per year,
equivalent to approximately 3% of total electricity bills;
x Increase renewable energy utilization to 51% by 2017, more than doubling the
renewable energy content that PG&E would provide over the same time
period;
x Obtain control over electric generation costs to provide a higher level of rate
stability for local residents and businesses;
The scenario sensitivity analysis contained in this report shows that the existence
of cost savings is not dependent upon the specific financial assumptions
underlying the base case feasibility assessment but is primarily dependent upon
the supply portfolio developed for the program. The average program savings
range from a low of 1% to a high of 14% across the eight scenarios evaluated to
4
test the sensitivity of these results to changes in wholesale energy market
conditions, PG&E rate projections, and cost responsibility surcharges. Although
the County could implement a CCA program without investing in generation
resources, such a strategy is unlikely to yield sustainable electricity cost savings.
NCI recommends a staged approach to implementation that includes initially
purchasing all of the program’s electric supply requirements on the open market
and transitioning to a strategy of generating the bulk of the program’s resource
needs through community-owned generation.
The conclusions and recommendations of this study took into consideration the
County’s known interests and objectives. The study reflects substantial
involvement of County staff, both individually and through a series of
discussions with other local governments participating in the project. Various
portfolio options were evaluated in terms of their effectiveness in meeting the
objectives and interests of the community. Following detailed review of the
options, a preferred portfolio option was jointly developed with staff that would
best satisfy the stated objectives and interests of the County.
This report and supporting analysis show that it would be feasible and
economically viable for the County to implement a Community Choice
Aggregation program as early as 2006. Whereas all current CPUC decisions are
reflected in the feasibility assessment, the CPUC is still in the process of
finalizing certain detailed rules and protocols that will apply to Community
Choice Aggregation. The ongoing phase of the CPUC rulemaking is focused on
operations and transactional issues that will be important to a Community
Choice Aggregation program’s operations but that are unlikely to materially
impact the base case feasibility assessment presented herein.
Energy procurement and resource planning are subject to certain risks or
uncertainties that must be managed by the energy supplier, whether it is PG&E
or the operator of a Community Choice Aggregation program. Forming a
Community Choice Aggregation program would not increase operational risks,
but responsibility for their management would transfer to the Community
Choice Aggregator and/or its suppliers. The County will be able to obtain
services from a variety of large, experienced suppliers to help manage the
Community Choice Aggregation program. It would therefore be able to manage
energy procurement risks at least as effectively as does PG&E. Professional
program management and application of standard industry risk management
practices will be keys to this effort.
The County can phase-in implementation of Community Choice Aggregation to
help ensure a smooth transition for customers that join the program. A phase-in
would reduce implementation risk, contribute to the program’s financial benefits
5
during the initial startup stage, and reduce the need for initial capital to startup
the program.
NCI recommends that the County implement its Community Choice
Aggregation program through formation of a joint powers agency (JPA) with the
cities within the County. The JPA structure provides critical mass for the
program and provides an appropriate financing vehicle for the capital
investments needed to support a cost-effective aggregation program. Additional
financial benefits could be obtained by jointly operating the program with other
local governments in Northern California that are also participants in the
Community Choice Aggregation Demonstration Project via formation of a wider
regional JPA or through contractual arrangement with these entities, enabling
common program operations. Regional program operations provide economies
of scale that enhance the economic benefits available to the County through
Community Choice Aggregation.
6
7
LIST OF ACRONYMS
A&G – Administrative and General
AB 1890 – Assembly Bill 1890
AB 117 – Assembly Bill 117
CAISO – California Independent System Operator
CCA – Community Choice Aggregation
CEC – California Energy Commission
CPUC – California Public Utilities Commission
CRS – Cost Responsibility Surcharge
CTC – Competition Transition Charge
DG – Distributed Generation
DWR – Department of Water Resources
FERC – Federal Energy Regulatory Commission
GRC – General Rate Case
IOU – Investor Owned Utilities
IT – Information Technology
JPA – Joint Powers Agency
KW - Kilowatt
KWh – Kilowatt hour
MW – Megawatt
MWh – Megawatt hour
NOPEC – Northern Ohio Public Energy Council
NOx – Nitrogen Oxides
NP15 – North of Path 15
O&M – Operations and Maintenance
PG&E – Pacific Gas and Electric Company
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
RPS – Renewable Portfolio Standard
RRDR – Renewable Resource Development Report
SCE – Southern California Edison Company
SDG&E – San Diego Gas and Electric Company
SEP – Supplemental Energy Payment
VEE – Verification, Editing and Estimation
8
9
TABLE OF CONTENTS
1 INTRODUCTION..............................................................................................................................12
1.1 Objective .......................................................................................................... 12
1.2 Project Elements And Timeline.................................................................... 13
1.3 Phase 2 - Implementation Plan .................................................................... 13
2 OVERVIEW OF CCA.........................................................................................................................15
2.1 What Is CCA?................................................................................................. 15
2.2 Legal And Regulatory Authority................................................................. 16
2.2.1 Requirements After Filing The Implementation Plan ...................... 17
2.3 Status Of CPUC Rulemaking ....................................................................... 18
2.3.1 Phase 1 Issues ......................................................................................... 18
2.3.2 Phase 2 Issues ......................................................................................... 19
2.4 Aggregation In Other States ......................................................................... 19
2.5 Implementation Models ................................................................................ 20
2.5.1 Single Third Party Supplier .................................................................. 20
2.5.2 Multiple Third Party Service Providers .............................................. 20
2.5.3 Municipal Operations............................................................................ 21
2.5.4 Unilateral or Joint Operations .............................................................. 21
3 BENEFITS OF CCA............................................................................................................................23
3.1.1 Lower Electricity Costs.......................................................................... 24
3.1.2 Fuel Efficiency and Environmental Benefits ...................................... 25
3.1.3 Rate Stability ........................................................................................... 26
3.1.4 Energy Security ...................................................................................... 27
3.1.5 Customer Choice .................................................................................... 27
3.1.6 Demand Side Energy Efficiency .......................................................... 28
3.1.7 Self Generation And Wheeling ............................................................ 29
3.1.8 Regional Economic Competitiveness .................................................. 29
3.1.9 Creation of Strategic/Asset Value ....................................................... 29
3.1.10 Opportunities For Innovation .............................................................. 29
4 RISK ASSESSMENT.........................................................................................................................31
4.1.1 Implementation Plan Stage Risks ........................................................ 31
4.1.2 Operational Planning Stage Risks ....................................................... 32
4.1.3 Operations Stage Risks .......................................................................... 33
4.1.3.1 Operations Risk Discussion .............................................................. 36
4.1.3.2 Regulatory Risk Discussion .............................................................. 36
4.1.4 Risk Mitigation Through Physical and Financial Reserves ............. 37
4.1.4.1 Physical Reserves ............................................................................... 37
4.1.4.2 Financial Reserves .............................................................................. 37
4.1.5 Risk Mitigation Through Phased Implementation ........................... 38
5 FEASIBILITY ANALYSIS ................................................................................................................39
5.1 Study Approach ............................................................................................. 39
5.2 Customer Base ................................................................................................ 40
10
5.3 Key Assumptions ........................................................................................... 41
5.3.1 Utility Rate Benchmarks ....................................................................... 42
5.3.2 Cost Responsibility Surcharges............................................................ 44
5.3.3 Renewable Energy Subsidies................................................................ 45
5.4 Financial Analysis Structure......................................................................... 46
5.5 Load Analysis ................................................................................................. 48
5.5.1 Load Forecast Methodology ................................................................. 48
5.5.2 Community Energy Load Shape ......................................................... 49
5.5.3 Renewable Portfolio Standards Requirements .................................. 50
6 FINANCIAL PROJECTIONS...........................................................................................................53
6.1 Supply Portfolio Details ................................................................................ 54
6.2 Alternative Supply Scenarios ....................................................................... 56
6.2.1 Alternative Supply Scenario 1 .............................................................. 56
6.2.2 Alternative Supply Scenario 2 .............................................................. 57
6.2.3 Alternative Supply Scenario 3 .............................................................. 57
6.2.4 Alternative Supply Scenario 4 .............................................................. 58
6.3 Sensitivities ..................................................................................................... 58
7 EVALUATION OF COSTS AND BENEFITS...............................................................................67
7.1 Ability To Deliver Lower Rates ................................................................... 67
7.2 Rate Stability ................................................................................................... 67
7.3 Increased Utilization Of Renewable Energy .............................................. 67
7.3.1 Cost Of Renewable Energy ................................................................... 68
7.3.2 Municipal Financing of Renewable Energy Development .............. 69
7.3.3 Operational Issues For Renewable Energy ........................................ 70
8 REGIONAL COMMUNITY CHOICE AGGREGATION PROGRAM OPERATED UNDER
A JOINT POWERS AGENCY...................................................................................................72
8.1.1 Economies Of Scale From Combined CCA Operations ................... 72
8.1.2 Joint Powers Agency Structure Option............................................... 73
8.1.3 Purpose and Parties ............................................................................... 75
8.1.4 Authorization ......................................................................................... 75
8.1.5 JPA Governance ..................................................................................... 75
8.1.6 Revenue Bond Issuance......................................................................... 77
9 CONCLUSIONS AND RECOMMENDATIONS........................................................................80
9.1 Conclusions ..................................................................................................... 80
9.2 Recommendations.......................................................................................... 81
APPENDICES ............................................................................................................................................84
Appendix A – Resource Portfolio Planning Template ......................................... 85
Appendix B – Detailed Assumptions ...................................................................... 87
Appendix C – Sample Data Request Letter ............................................................ 92
Appendix D – CCA Functional Elements............................................................... 94
Appendix E – Base Case Pro Forma And Supporting Data............................... 100
Appendix F – Pro Forma Summary With Alternative Supply Portfolios........ 101
Appendix G – Electric Customers and Load Analysis ....................................... 103
Appendix H – Implementation Schedule ............................................................. 104
11
12
1 INTRODUCTION
1.1 Objective
The County is a participant in the Local Government Commission Community
Choice Aggregation Demonstration Project, which was commissioned by the
California Energy Commission (CEC) and the United States Department of
Energy to assist local governments in evaluating and implementing Community
Choice Aggregation. Under Community Choice Aggregation, the County and
the cities within the County would aggregate the electric loads of customers
within their jurisdictions for purposes of procuring electrical services.1
The purpose of this report is to evaluate the feasibility of the County forming a
Community Choice Aggregation Program. The report contains detailed
economic feasibility analyses and recommendations to help the community
evaluate the costs and benefits afforded by Community Choice Aggregation and
move towards development of an Implementation Plan.
The report and analyses contained herein comprise project deliverable Task 4:
Load Analysis and CPUC Decision Based Feasibility Analysis. This report builds
upon the Load Analysis and Assumptions Based Feasibility Analysis previously
provided to the County, which presented economic feasibility results for a CCA
program utilizing four alternative supply portfolios. Upon review of the
preliminary results, the County provided input on its preferred supply portfolios
with respect to the percentage of its supply it desires to be produced from
renewable energy resources and whether the County intends to utilize its
municipal financing capabilities to reduce the costs of is electricity procurement
program by financing energy development projects. These supply preferences
and other feedback received from the County staff are reflected in this final
report. This report additionally incorporates the CPUC’s December 16, 2004
decision in Phase 1 of the CCA rulemaking (Decision No. D.04-12-046).
As second phase of the Demonstration Project will include the development of a
template for use by communities in developing Implementation Plans for
submission to the California Public Utilities Commission (CPUC). Communities
can utilize the template to help them develop their Implementation Plans.
1 Throughout this report, the entity formed to become a Community Choice Aggregator, comprised of the
County and the cities within the County, is denoted by the term “Aggregator”.
13
1.2 Project Elements And Timeline
NCI recommends a two-phased approach for consideration of forming a CCA
program. Phase 1 includes the base case feasibility study and report, while
Phase 2 includes development of an Implementation Plan for submittal to the
CPUC. A high level overview of these phases is shown below:
Phase 1 Element Timeline
Community Selection Complete
Participant Orientation Complete
Renewable Resources Workshop Complete
Base Case Feasibility Analysis Complete
Participation in CPUC CCA Rulemaking Phase 1 Complete
Draft Evaluation and Report Complete
Final Feasibility Analysis March 2005
Final Evaluation and Report March 2005
Phase 2 Element
Development of Implementation Plan Template Ongoing
Participation in CPUC CCA Rulemaking Phase 2 Jan. 2005 – Jun. 2005
Prepare and Submit Implementation Plan Summer 2005
Support Implementation Plan Filing At CPUC Summer 2005
1.3 Phase 2 - Implementation Plan
After considering the expected benefits and costs of forming a CCA program,
communities that wish to proceed with forming a CCA program will need to
develop an Implementation Plan. AB 117 requires submission of an
Implementation Plan to the CPUC prior to the CCA commencing operations.
The law requires the Implementation Plan to “detail the process and
consequences of aggregation.” The Implementation Plan and subsequent
changes to it must be adopted at a duly noticed public hearing. The
Implementation Plan must contain all of the following:
¾ An organizational structure of the program, its operations, and its funding;
¾ Ratesetting and other costs to participants;
¾ Provisions for disclosure and due process in setting rates and allocating costs
among participants;
¾ The methods for entering and terminating agreements with other entities;
¾ The rights and responsibilities of program participants, including, but not
limited to, consumer protection procedures, credit issues, and shutoff
procedures;
14
¾ Termination of the program;
¾ 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.
A CCA must prepare a statement of intent with the Implementation Plan. Any
CCA program shall provide for the following:
¾ Universal access
¾ Reliability
¾ Equitable treatment of all classes of customers
¾ Any requirements establish ed by state law or by the CPUC concerning
aggregated service
The California Public Utilities Commission has responsibility to review the
Implementation Plan submitted by an Aggregator, and it may establish
additional detail regarding the form and content of an Implementation Plan in
Phase 2 of R.03-10-003.
15
2 OVERVIEW OF CCA
2.1 What Is CCA?
Assembly Bill 117 permits California cities, counties, or city and county joint
powers agencies (“local governments”), to implement a program to aggregate
the electric loads of electric service customers within their jurisdictional
boundaries to facilitate the purchase and sale of electricity. The local government
would become a Community Choice Aggregator (“Aggregator”) to procure
electric energy for residents and businesses within a community. All customers
currently receiving electric generation services from PG&E would be
automatically enrolled in the program, unless the customer notifies the
Aggregator of its desire to opt-out and remain a bundled service customer of
PG&E. The Aggregator would be responsible for operating the CCA program,
either by performing the functions necessary for program operations utilizing its
own employees or by contracting out operations to one or more third-party
operators or energy services providers.
Within the context of CCA, “electricity” means the electric energy commodity
only. CCA’s enabling legislation requires local utilities such as PG&E to provide
electricity delivery over its existing distribution system and provide end-
consumer metering, billing, collection and all traditional retail customer services
(i.e., call centers, outage restoration, extension of new service). Accordingly, the
infrastructure requirements of the CCA program do not include any electric
transmission or distribution related facilities to serve CCA retail loads. PG&E
must provide delivery services to CCA customers under the same terms and
conditions as provided to other of its customers.
It is important to distinguish an Aggregator from municipal utilities and from
energy service providers as each of these entities provides different services, has
different responsibilities, and operates under different regulatory frameworks. A
local government that implements a community choice aggregation program
does not become a municipal utility in the manner of the Los Angeles
Department of Water and Power or the Sacramento Municipal Utility District,
which own and operate transmission and distribution systems. A critical
distinguishing factor is that the Aggregator would not own the electric
distribution system within the County. Rather, it would own or procure electric
power from the wholesale markets, either through ownership of resources,
market purchases, or through a partner on behalf of the customers that choose to
aggregate their loads. The local investor owned utility (PG&E, SCE, or SDG&E)
would then be required to deliver the electric energy to the end-use customer
across its transmission and distribution facilities. In this sense, an Aggregator is
similar to an electricity service provider that sells electricity to direct access
16
customers. However, there are important differences between CCA and direct
access, and these two programs will operate under different sets of rules
established by the CPUC.
Customers of the CCA will pay the same charges for delivery (transmission and
distribution) as customers that remain as full service, “bundled” customers of
PG&E. These delivery charges represent approximately one half of the typical
household’s monthly electric bill. The Aggregator will establish rates for the
generation services it provides to CCA customers, and these customers will no
longer pay PG&E for generation services. However, PG&E will be authorized to
assess a surcharge for certain of its generation related costs that might otherwise
be shifted to its remaining bundled service customers. This surcharge is known
as the “cost responsibility surcharge” or “CRS”, and it will be regulated by the
CPUC. The cost responsibility surcharge is discussed in greater detail in Section
5.3.2.
By law, PG&E will perform all metering and billing for CCA customers. PG&E
will collect the Aggregator’s charges from CCA customers and transfer the funds
collected to the Aggregator in the monthly billing process. To a large extent
PG&E’s costs of providing metering, billing and customer services are included
in their existing delivery charges. However, the utilities have asserted that CCA
programs will cause additional costs related to metering, billing and customer
services, and they have requested the CPUC to authorize additional charges to be
assessed on Aggregators or CCA customers. This and other issues in the CPUC
Rulemaking are discussed in Section 2.5.
2.2 Legal And Regulatory Authority
A CCA program for electric customers is governed by the Community Choice
Aggregation legislation (AB 117, Chapter 838, September 24, 20022). A local
government could become an Aggregator for electric utility generation by
developing an Implementation Plan, and then having this plan approved by the
CPUC. AB 117 offers flexibility in that it is an “opt-out” program rather than an
“opt-in” program. This would allow the Aggregator to sign up customers
willing to switch from PG&E generation service to CCA service without the
necessity of developing an active marketing effort to lure customers. Instead, the
Aggregator would merely need to notify customers of the impending
Community Choice Aggregation program. Any customers that do not want to
participate in the program would be required to notify the Aggregator of their
election to opt-out within a specified amount of time.
2 AB 117 became effective January 1, 2003 amends Sections 218.3, 366, 394, and 394.25 of the
Public Utilities Code and creates Sections 331.1, 366.2, and 381.1 to the same Code.
17
AB 117 also requires full cooperation by the host investor owned utility in any
CCA program implemented by the County. In this regard, AB 117 would require
PG&E to provide necessary load information and other important data and
continue to provide transmission, distribution, metering, meter reading, billing
and other essential customer services.
2.2.1 Requirements After Filing The Implementation Plan
1. Within 10 days after the Implementation Plan is filed, the CPUC will notify
PG&E (PUC Section 366.2(c)(6)).
2. Within 90 days after the Aggregator files an Implementation Plan the CPUC
shall certify that it has received the Implementation plan, including any
additional information necessary to determine a cost recovery mechanism.
The Commission shall designate the earliest possible date for
implementation of a CCA program (PUC Section 366.2(c)(7)).
3. The Aggregator must offer the opportunity to purchase electricity to all
residential customers within its political boundaries (PUC Section 266.2(b))
4. PG&E shall fully cooperate with the Aggregator, including providing
appropriate billing, and electrical load data, in accordance with CPUC
procedures (PUC Section 366.2(c)(9))
5. The Aggregator must fully inform all customers of their right to opt-out of
the CCA program and to continue to receive service as a bundled customer
from PG&E. All customers must be notified twice within two months or 60
days prior to the date of automatic enrollment. In addition, notification
must continue for participating customers for at least two consecutive
billing cycles after enrollment (PUC Section 366.2(c)(11),(13).
6. Notification must contain the following information:
Customer will be automatically enrolled
Each customer has the right to opt-out of the program without penalty
The terms and conditions of CCA service (PUC Section 366.2(13)(A))
7. 7The Aggregator may request the Commission to approve and order PG&E
to provide the customer notifications (PUC Section 366.2(13)(B)).
8. The Aggregator must register with the CPUC and may be required to
provide additional information in order to verify compliance with rules for
consumer protection and other procedures (PUC 366.2(c)(14)). At the time
18
of registration, the Aggregator must post a bond or provide evidence of
sufficient insurance to cover any reentry fees that may be imposed against it
by the CPUC for involuntarily returning a customer to service of PG&E
(PUC Section 394.25(e)).
9. The Aggregator must notify PG&E that CCA service will begin within 30
days (PUC Section 366.2(c)(15)).
10. Once notified, PG&E shall transfer all applicable accounts to the new
supplier within a 30-day period from the date of the close of their normally
scheduled monthly metering and billing process (PUC Section 366.2(c)(16)).
11. PG&E shall recover from the Aggregator any costs reasonably attributable
to the Aggregator, as determined by the CPUC (PUC Section 366.2(c)(17)).
2.3 Status Of CPUC Rulemaking
While AB 117 does provide a statutory basis for Community Aggregation
projects, the CPUC has not yet developed and implemented final rules for the
development of such programs. On September 4, 2003, the CPUC issued an
order instituting a rulemaking or “OIR” (Rulemaking 03-09-007) in order to
develop the guidelines for community aggregation programs, as it was directed
to do under AB 117. On October 2, 2003, the CPUC reissued the rulemaking
under Docket No. R.03-10-003. The CPUC bifurcated the proceeding into two
phases. The scope of Phase 1 is to determine issues related to costs imposed by
the local utilities on Aggregators and CCA customers, namely cost responsibility
surcharges, transaction fees, and implementation costs. The general scope of
Phase 2 is to address the processes for interactions between Aggregators and the
local utilities and other operational details. The issues identified with each phase
are listed below:
2.3.1 Phase 1 Issues
x Cost responsibility surcharges – methodology, transparency, caps, new
utility procurement, rate design, phasing, assumption of in lieu MWh
x Transactions costs - implementation fees, fees related to CCA
establishment, enrollment fees, billing, payment and collection, monthly
account maintenance fee, interval metering fee, termination of CCA
program fee, special request fee, information fees
x Customer information issues – data needs of Aggregators, customer
confidentiality protections
19
2.3.2 Phase 2 Issues
x The detailed processes, costs, and fees authorized for the utilities’ CCA
implementation activities and utility transactions with CCAs (e.g.,
metering, billing, CCA establishment, notifications, enrollments, account
maintenance, termination)
x Rules and formats for notifying customers of CCA service and customer
opt-out opportunities
x Rules for switching customers to CCA service, processing customer opt-
outs, and returning CCA customers to utility service
x Customer reentry fees and bonding requirements imposed on CCAs
x CCA phase-in mechanisms and guidelines
x CCA consumer protection obligations
x CCA Implementation Plan requirements
The Commission issued its final decision (D.04-12-046) in Phase 1 on December
16, 2004. The schedule for Phase 2 has not yet been established, but it is expected
to conclude in the second or third quarter of 2005.
2.4 Aggregation In Other States
Aggregation programs exist in both Massachusetts and Ohio, with the Ohio
program being most similar to Community Choice Aggregation in California.
Ohio includes provisions for government aggregation on an opt-in or opt-out
basis. According to the Public Utilities Commission of Ohio (PUCO), Ohio has
had among the most successful electric choice programs in the nation, with
government aggregation leading the way.3 The greatest success is in those areas
of Ohio that have adopted aggregation. Northern Ohio has enjoyed a high rate
of customer switching due in large part to this process whereby communities
band together to buy electricity, in bulk, for their residents. In the first two years
of electric choice:
x More than 150 local governments passed ballot issues and were certified
by the PUCO to allow local units of government to represent their
communities in the competitive electricity market. Ohio is home to the
Northeast Ohio Public Energy Council (NOPEC), the largest public
aggregator in the United States. NOPEC represents 112 communities in
eight counties and more than 350,000 residential customers.
3 Information about the Ohio aggregation experience was obtained from The Ohio Retail Electric Choice
Programs Report of Market Activity 2001-2002, A Report by The Public Utilities Commission of Ohio,
May 2003.
20
Of those customers who have switched in Ohio, aggregation programs account
for:
¾ Nearly 93% of residential customers who have switched in Ohio
¾ More than 88% of commercial customers who have switched in Ohio
¾ Nearly 20% of industrial customers who have switched in Ohio
2.5 Implementation Models
There are a variety of approaches the County could take in implementing a CCA
program, varying in the degree of operational control, risk and benefits afforded
to the County.
2.5.1 Single Third Party Supplier
At one end of the spectrum, the County could pursue a minimalist approach,
essentially serving as a conduit between electric customers within the County
and a third party electric supplier. The Aggregator would solicit offers from
electric suppliers to serve the customers that choose to participate in the program
(i.e., do not opt out) and would largely rely on the supplier to administer the
program. An example would be for the Aggregator to negotiate a guaranteed
discount to the prevailing PG&E rate such that the supplier absorbs the risks of
meeting the obligation to provide electricity cost savings. This approach offers
very little risk to the Aggregator but also limits the potential upside, especially
with respect to the benefits offered by municipal-financed generation assets or
financing arrangements.4 Suppliers may not be willing to absorb the risks
associated with factors that are outside the control of the supplier, such as those
posed by changes in PG&E rates or the CRS. Furthermore, under the assumption
that suppliers would not charge less than the market price of electricity as
utilized in this analysis, the imposition of the CRS would appear to eliminate the
opportunity for cost savings to be obtained in the near term. Indicative bids
from electricity suppliers should be obtained early in the County’s
implementation planning to help determine whether this approach is financially
viable.
2.5.2 Multiple Third Party Service Providers
In pursuing this approach, the Aggregator would “unbundle” the electric
services needed for the program and negotiate contracts with third parties for
provision of these discrete services (e.g., billing services, scheduling
4 It may be possible to negotiate agreements with the electric supplier to integrate municipal resources or
utilize municipal bonding, but this would necessitate greater County involvement than represented by the
pure minimalist approach outlined here.
21
coordination, electric supply). The Aggregator would assume overall
responsibility for the program and for the performance of its contractors. The
Aggregator would be responsible for setting rates and program policies and for
general administration of the program. This approach offers several advantages,
including limited staffing requirements, greater control, diffusion of risk
(associated with supplier default), and the accumulation of industry knowledge
and experience that creates strategic value at the Aggregator. Under this
approach, the Aggregator would bear sole accountability for the results achieved
by the program; regardless of whether these are successes or failures.
2.5.3 Municipal Operations
In the longer term, the Aggregator could create the organization needed to
operate the CCA program, utilizing in-house staff and resources. Recruiting
skilled professional staff with electricity operations experience would be a
challenging endeavor in the near term and is probably not feasible for a planned
2006 start date. Over time, as the Aggregator gains experience with the program,
some or all functions that were initially contracted out to third parties could be
brought in-house, if desired.
2.5.4 Unilateral or Joint Operations
The County could implement a CCA program on its own or in combination with
other cities and/or counties through a Joint Powers Agency (JPA). Clearly, there
would be efficiencies and cost savings achieved by jointly implementing a single
program. Such a combined program provides scale economies, improving terms
of financing and power supply options. Customers would get the benefits of
greater bulk buying power and professional expertise available through a larger
organization. A larger organization would wield greater political influence and
more effectively participate in the regulatory process to protect member interests.
Individual implementation would require a greater investment of time and
expense by the County, and would entail generally higher operations costs. A
common program also removes some of the risk in making the decision to offer
aggregation services to customers because the County would not be proceeding
alone.
The primary disadvantage of implementation through a JPA is a joint program
could reduce the degree of autonomy exercised by the County over its program.
This report is premised on the County implementing a CCA program in
conjunction with the Marin County cities. The report also includes a pro forma
analysis of a joint CCA program, in combination with other local government
participants in the Demonstration Project. NCI recommends the County
22
coordinate with the other local governments to investigate formation of a
regional JPA or, alternatively, contractual arrangements that would provide the
efficiencies of combined operations.
23
3 BENEFITS OF CCA
The primary benefits offered by CCA are local control over the energy resources
utilized by the community and the ability to provide electricity to customers at a
lower overall cost. The cost savings can accrue to customers through lower
electric bills or can be used by the County to provide enhanced services to its
constituents. Local control manifests in a variety of benefits giving customers a
means to effectuate their preferences regarding the type of electricity production
they support as well as obtaining energy services that satisfy their unique needs.
Through CCA, the Aggregator can choose to structure a supply portfolio that
achieves cost efficiencies, fuel and technological diversity, environmental
improvement, and/or cost stability. The Aggregator can choose to develop its
own energy resources and decide which type of resources will be developed and
where such resources should be located, consistent with its general planning
responsibilities.
CCA would facilitate the County’s implementation of an aggressive program to
increase utilization of renewable energy resources and promote improved energy
efficiency. The Aggregator’s local perspective and its primary mission to serve
its customers rather than maximize profits for shareholders places it in a unique
position to integrate effective demand-side energy efficiency programs with
procurement of electricity supplies to lower overall energy costs for the
community.
Generally speaking, the cost competitiveness of the CCA program will depend
on the following factors:
x The mix of customers served by the Aggregator and the rate designs
charged by PG&E for the various customer classes
x The composite load profiles (hour-by-hour energy consumptions) of the
Aggregator’s customer portfolio
x The resource mix utilized by the Aggregator
x The use of low cost municipal bonds to finance generation resource
projects
x Electricity prices and prices for other services negotiated with third party
electric suppliers
x The trajectory of PG&E’s generation costs and whether all cost increases
are passed on to CCA customers through the cost responsibility surcharge
x The costs charged by PG&E for implementation activities and transactions
such as metering, billing, and customer services.
A CCA program would enable the County to capture the benefits of competition
among suppliers for the right to serve the community’s load. California’s
24
experience with direct access showed that suppliers were willing to offer
discounts to large customers of the investor owned utilities (IOUs). For the most
part, discounted rates were not offered to residential customers because of their
relatively small loads and the high marketing and transactions costs related to
serving mass-market customers. Some suppliers were able to charge higher
prices than the IOU’s for renewable or “green” energy, and most residential
customers that switched to direct access did so to increase the amount of
renewable energy used to supply their homes. The opt-out feature of CCA
eliminates most of the marketing and transactions costs that limited the
opportunities in the direct access market for residential and small commercial
customers. Through community aggregation, small customers can obtain
competitive electricity supplies directly from the wholesale market on a scale
that was simply not feasible under direct access rules.
3.1.1 Lower Electricity Costs
To the extent the Aggregator can obtain electricity at a lower cost than charged
by PG&E, the margin can be used to lower rates for CCA customers, contribute
to reserve or contingency funds, or augment the County’s revenues for provision
of public services to its constituents.
A comparison of PG&E’s rates to current market prices for electricity indicates
the margin embedded in the generation rates charged by PG&E. The table below
compares the current system average generation rate for PG&E to the estimated
cost of supplying the County at current market prices of electricity.
Cost Cents Per
KWh
PG&E Avg. Generation Rate 7.6
Estimated Supply Cost 5.6
Gross Margin 2.0
Absent the imposition of a CRS, the Aggregator could capture up to 2.0 cents per
kWh of margin by procuring electricity at market prices to supply the program.
However, AB 117 and ensuing CPUC rules authorize PG&E to impose
surcharges on customers of the CCA that are designed to shield PG&E and its
remaining customers from the costs of losing customers to the CCA. The
surcharge represents the difference, on a system average basis, of the average
cost of PG&E’s supply portfolio and the market price of electricity.
Conceptually, the imposition of the CRS on CCA customers means the
Aggregator must obtain electricity supplies at below market prices if it is to
provide electricity cost savings to its customers during the time period that the
CRS applies.
25
There are essentially two ways the Aggregator could obtain below-market
electricity prices: 1) the Aggregator could negotiate for low cost electric supplies
from third party providers, some of whom may be willing to offer discounted
prices in order to gain market share and position their firms for sales of other
value added services; or 2) the Aggregator could utilize its ability to issue low
cost municipal bonds to develop or contract for generation resources. Whereas
the opportunity for negotiation of low cost supplies would be circumstantial and
ultimately may not materialize, the Aggregator’s financing advantage offers a
clear and lasting competitive advantage.5 The Aggregator, being a public
agency, can finance generation projects at an effective cost of capital that is
approximately one half of PG&E’s or the typical merchant generation
developer’s. As described in greater detail in Section 6.3.2, the municipal
financing advantage is particularly well-suited to development of renewable
generation projects, with their relatively high capital costs and low operating
costs. By financing generation resources (conventional or renewable) or
providing capital to prepay for electricity purchases, the Aggregator can obtain
electricity at below market costs.
Once the CRS terminates at some point in the future, the Aggregator will
compete against PG&E’s then current supply portfolio, and PG&E will no longer
have the protection afforded by the CRS. By 2013, approximately 40% of the
PG&E supply portfolio will be comprised of power purchase contracts executed
after 2005. Therefore, the cost competitiveness of PG&E’s portfolio in the post
CRS timeframe will largely depend upon how efficiently PG&E procures
electricity supplies during the next several years. The conservative assumption
would be that PG&E will procure electricity at prevailing market prices and that
the Aggregator will need to bring its financing advantages to bear in order to
obtain electricity cost savings in the post CRS period.
3.1.2 Fuel Efficiency and Environmental Benefits
By implementing a CCA program, the Aggregator can cause new generation to
be developed, either by offering contracts to suppliers for the purchase of energy
or by direct involvement in developing new resources. Development of new
generation, whether renewable or fossil fueled, will displace production from
old, inefficient generation sources, which can significantly reduce environmental
impacts of electricity production. According to the CEC, approximately one
third of natural gas consumption in California derives from production of
electricity. Today’s natural gas-fired generation units can operate 30% to 40%
5 For the financial analysis contained in this feasibility analysis it is assumed that third party electric
suppliers would offer electricity at the full market price of electricity and would not offer discounts.
26
more efficiently than the 1960’s era generators that are currently online in
California. For every kWh produced from a new generation resource, there
would be up to 40% less natural gas consumption and even greater reductions in
air emissions and greenhouse gases.
A benefit that is particularly important to some communities is the ability to
promote use of renewable energy resources and significantly exceed the
renewable energy standards applicable to PG&E. Increased renewable
generation would reduce air pollution and emissions of greenhouse gases and
reduce dependence on natural gas consumption even further. For the same kWh
produced by renewable energy resources, natural gas consumption would drop
to zero and, depending on the renewable technology employed, air emissions
could also be eliminated.
3.1.3 Rate Stability
CCA enables the Aggregator to lock in electricity prices and provide multi-year
rate stability to its customers. Business customers in particular tend to value
predictability in their energy costs to aid in business planning. Rate stability can
be an attractive feature to help lure new businesses into the community or retain
those that may be considering leaving due to high and unstable electricity costs.
CCA allows the community to negotiate for long-term, fixed priced electric
supplies from a variety of suppliers. Likewise, increased reliance on renewable
energy technologies reduces exposure to the volatile natural gas market, which
in turn is a primary driver of electricity price volatility.
Historically, PG&Es rates have exhibited periods of relative stability punctuated
by periods of high rates during times of crisis or the addition of major generation
investments. Due to actions taken in response to the energy crisis of 2000-2001,
PG&E’s current supply portfolio is much more heavily weighted toward fixed
price contracts and renewable energy contracts than in the years immediately
preceding the energy crisis, and should be expected to deliver relatively stable
(but increasing) costs over the next several years. However, PG&E is not free to
operate in the market in the most efficient manner and must make procurement
decisions within the regulatory context in which it operates. To a large extent,
PG&E does not control its own destiny the way an Aggregator can.
The Aggregator would possess autonomy over its electricity procurement
decisions and the rates it charges to customers, which provides more control over
its costs and greater flexibility in its rate structures than PG&E is allowed under
CPUC regulation. More tools are available to the Aggregator to control its
electric supply costs and rates. For example, publicly owned (i.e., municipal)
utilities commonly create rate stabilization funds using retained margins that
27
enable the utility to weather short-term cost increases without the need to
increase rates. In contrast, PG&E cannot execute supply contracts or build new
generation resources without CPUC approval, nor can it establish or modify its
rates or reserve accounts without express approval from the CPUC. The
regulatory approval process can take many months, and the CPUC may in the
end deny the utility’s requested authorization. Put simply, the Aggregator has
more autonomy in its operations than does PG&E, which enhances the
Aggregator’s ability to provide rate stability to its customers.
New generation is needed to serve California’s increasing population and to
replace thousands of megawatts of aging power plants that will be retired in the
next several years. California is entering a period of major electricity
infrastructure investments, and the addition of new utility-owned generation
will place upward pressure on PG&E’s rates, contributing to future rate
instability. By assuming the responsibility for developing the infrastructure
needed to serve the County’s constituents, the County can shield its constituents
from future rate increases caused by PG&E generation investments.
3.1.4 Energy Security
As the majority of new power plants in the United States are fueled by natural
gas, the nation is increasingly becoming dependent upon imported natural gas.
The flurry of activity related to construction of new liquefied natural gas
terminals (LNG) along the California and Baja California coast attests to the
increased demand for imported natural gas. Many people are concerned that
during the next ten to twenty years the United States will become as dependent
on natural gas imports as it currently has become on imported oil. Such
dependence raises a host of political, environmental and security issues that
potentially threaten the nation’s vital interests. By implementing a CCA
program that relies more heavily on renewable energy resources, the Aggregator
can ensure that the electricity consumption of customers participating in the
program does not contribute to the problems associated with increased
dependence on imported natural gas.
3.1.5 Customer Choice
CCA provides choice to all electricity customers because all customers have the
option of being automatically enrolled in the CCA program or of remaining with
PG&E for provision of generation services. Direct access has been “suspended”
by the California legislature, and presently CCA is the only mechanism that
allows customers to buy electricity from an entity other than PG&E. All
customers can benefit from opportunities for choice and the disciplinary effects
28
of competition on PG&E’s service even if they do not take advantage of the CCA
program.
3.1.6 Demand Side Energy Efficiency
A CCA program would provide an organizational structure to support
administration of energy efficiency programs, and it would also enable seamless
integration of energy efficiency into the resource planning process of the
Aggregator. Energy efficiency or demand side management programs can be
tailored to the unique needs of the community and can be integrated with the
supply planning of the Aggregator, yielding overall lower supply costs. The
Aggregator’s rates can provide the revenue bonding capacity to finance worthy
public benefits programs such as installation of rooftop photovoltaic systems and
energy efficiency investments, with debt service provided via monthly customer
bills. The Aggregator’s knowledge of the community can help improve the
effectiveness of energy efficiency investments, as the Aggregator would be in a
better position to identify high potential energy efficiency opportunities in the
community.
Local governments should also have strong motivation to deploy effective
energy efficiency programs. Investor-owned utilities, such as PG&E, face an
inherent conflict of interest in administering energy efficiency programs because
the success of their programs reduces the utilities’ sales growth and potentially
their profitability. As an Aggregator, the County would be motivated to reduce
overall energy costs, both on the supply and demand side. An integrated
approach to supply planning, energy efficiency and demand response, which
reflects the specific circumstances of the community, should translate into greater
energy savings.
AB 117 requires that a proportional share of energy efficiency funding be spent
in the County if it forms a CCA program. Thus, formation of a CCA program
would obligate PG&E to ensure that the County is not under-served by current
energy efficiency programs administered by PG&E or third party administrators.
The Aggregator could seek authority to replace PG&E as administrator of energy
efficiency programs by submitting a program application to the CPUC.
However, current CPUC rules do not grant Aggregators special rights regarding
access to public goods funding for purposes of administering energy efficiency
programs. This issue may be reevaluated in Phase 2 of the CCA rulemaking
(R.03-10-003).
29
3.1.7 Self Generation And Wheeling
A CCA program would provide a legal mechanism to transmit excess power
from generation located “behind-the-meter” to other loads within the County.
For example, excess production from a County cogeneration or solar facility
could be used to serve other facilities rather than being sold to PG&E or lost to
the system. The CCA program could enable the County to obtain greater value
for its distributed generation facilities.6
3.1.8 Regional Economic Competitiveness
The Aggregator could use its ratemaking authority to establish economic
development and business attraction rates to help lure desirable businesses and
jobs to the community with the benefit of lower rates. Competitive electric rates
can also be a factor in retaining businesses that might otherwise leave the
community, seeking locations with lower costs of doing business. A CCA
program that provides low and stable rates can be an important factor in
maintaining regional economic competitiveness.
To the extent the Aggregator initiates development of local generation resources
to serve the CCA program, the reliability of the local area would be enhanced.
3.1.9 Creation of Strategic/Asset Value
Formation of a CCA program creates strategic value arising from the creation of
assets, infrastructure and annual cash flows. The Aggregator would be
developing expertise in energy matters, building infrastructure, and positioning
itself for an expanded role in the provision of energy services if future
circumstances warrant such an expanded role.
3.1.10 Opportunities For Innovation
A CCA program presents opportunities for the Aggregator to provide innovative
energy services to customers. The Aggregator could develop programs that
respond to the local concerns, needs, and values of their community members.
One example would be formation of “green pricing” programs that provide
customers the option of choosing to use more renewable energy. Customers that
value renewable energy would be able to voluntarily pay for any additional costs
of increasing the renewable energy mix, reducing the costs to be paid by more
6 Whether greater value can be achieved in practice would depend upon whether an existing contract is in
place governing the sale of excess power from the facility and upon the pricing terms and conditions of the
contract.
30
price sensitive customers. Other innovative services could include special rates
for population subgroups (e.g., low income, government facilities, enterprise
zones, etc.), program-financed distributed generation, or a host of other value-
added services.
31
4 RISK ASSESSMENT
The risks of forming a CCA program evolve as the County begins its
implementation planning process and then progresses to startup of program
operations. The County’s risk exposure also depends greatly upon the
implementation approach utilized by the County, as previously discussed in
section 2.5.
The major risk associated with forming a CCA program is the possibility that the
rates of the program exceed the comparable rates charged by PG&E, causing
customers to become dissatisfied with the program or attempt to return to PG&E
service. The Aggregator’s ratemaking authority and ability to raise rates if
necessary would protect the Aggregator from the financial impacts of
unanticipated program cost increases. Further, pending the development of
switching protocols in Phase 2 of the CCA rulemaking, the Aggregator could
terminate the program, if necessary, and return customers to PG&E service. The
program could set aside financial reserves to cover any reentry fees that may be
applicable in the case of program termination. For these reasons, the risks of the
County forming a CCA program generally remain with the customers that elect
to participate in the program. Similarly, customers of PG&E ultimately bear the
risks of PG&E’s energy procurement practices.
4.1.1 Implementation Plan Stage Risks
At the Implementation Plan stage, the County will have evaluated the feasibility
of becoming an Aggregator and assessed the expected costs, benefits, and risks of
implementing a CCA program. To progress to the next phase, the County will
need to commit additional funds for the development of an Implementation
Plan. The primary risk at this stage is political, especially if PG&E directly or
indirectly opposes the CCA program. Whereas each of the local utilities has
publicly supported CCA, there are always caveats that in practice might cause
them to oppose a specific implementation effort as it progresses towards an
Implementation Plan.
Typical utility responses to local government energy initiatives are to urge the
local government’s leaders to slow down so as not to rush into something they
do not fully understand. The utility may criticize the feasibility study’s
assumptions and methodology and suggest that becoming an Aggregator entails
great risk with little or no commensurate benefits. Furthermore, PG&E may
formally oppose elements of the Implementation Plan at the CPUC. For
example, each of the utilities has voiced opposition to allowing Aggregators to
phase-in operations over a multi-year period, and phase-in proposals contained
in an Implementation Plan may be protested. In the extreme case, the utility
32
might sponsor community organizations to oppose the program, as has been
done by both SCE and SDG&E in their efforts to oppose municipalities from
forming distribution utilities within their historical service territories. While
such strong opposition to a potential CCA program is unlikely, the County
should be realistic and not expect complete support from the utility for its efforts.
Once a commitment to developing the Implementation Plan is made a fairly
intensive effort will be required to decide the particulars of the CCA program.
Choices must be made regarding program management and organizational
structure, suppliers and resources, rates and customer protections, terms and
condition of service, financing and staffing.
At this stage, there is also the regulatory risk that the CPUC will adopt or modify
implementation rules to the detriment of the CCA program or in a way that
requires modifications to the Implementation Plan. The development of the
Implementation Plan can be done in parallel with the CPUC process. The
Implementation Plan should be filed with the CPUC after the CPUC issues its
final (Phase 2) in order to avoid the potential expense of re-filing the plan.
However, delays in the CPUC process can derail the implementation effort if the
process is dragged out indefinitely. Elected leaders that were early supporters of
implementing a CCA program may finish their terms before the program can be
implemented, and newly elected leaders may desire to reconsider the decision to
proceed with CCA implementation. Turnover of key staff could also jeopardize
timely program implementation.
4.1.2 Operational Planning Stage Risks
Following development and acceptance of the Implementation Plan, the
Aggregator will begin making commitments to be able to commence operations.
Depending on how the Aggregator elects to structure its program, additional
funds will be needed to finance the start-up activities. These may include the
following:
x Conduct recruiting and staffing
x Develop informational and program marketing materials
x Establish call center for customer inquiries
x Contact key customers to explain program, obtain commitment, and
release customer information
x Prepare short and long-term load forecast
x Develop capability or negotiate contracts for operational services
Electronic data interchange with utility: accept meter and usage data,
send billing data, accept payment and remittance information,
exchange customer switching information
33
Customer bill calculations
Scheduling coordinator services
Application of statistical load profiles and submittal of hourly usage
data for grid operator settlements
Resource planning, portfolio and risk management
Ratemaking
Load forecasting
Wholesale settlements
Credit
Information Technology
x Execute contracts for electric supply
x Identify generation projects and negotiate participation, if applicable
x Obtain financing for program capital requirements
x Execute service agreement with utility
x Complete utility technical testing
x Establish account with utility
x Send customer notices to eligible and ineligible (e.g., direct access)
customers
x Process customer opt-out requests
x Submit notification certification to CPUC
These commitments should not be made until the CPUC has finalized the rules
for CCA implementation, which is expected to take place in June 2005. At that
point, the regulatory risk diminishes significantly, and the Aggregator has a
great deal more certainty regarding the detailed processes that will be required
for operating a CCA program.
4.1.3 Operations Stage Risks
The primary risks inherent in the CCA operations are that unanticipated events
cause the Aggregator’s costs to increase or the rates of PG&E to decrease. In that
case the rates charged by the Aggregator could exceed those of PG&E, and
customers may become dissatisfied with the program. To the extent customers
are not precluded from leaving the program, the Aggregator could face stranded
costs and higher rates prompting additional customers to leave the program.
Appropriate program rules that limit customer switching or that impose exit fees
to compensate remaining program customers for commitments made on behalf
of the departing customers will mitigate the risk of losing customers. However,
if customers find themselves obligated to a program with higher rates than those
offered by PG&E (or other competitors), their dissatisfaction may be directed at
those responsible for administering the program. These risks highlight the
importance of clear disclosures in the customer notification process so that
34
potential customers are clearly informed of their rights and obligations prior to
taking service in the program.
The predominant cost of service variables and risks that might impact the
Aggregator’s operations cost are as follows:
x The cost responsibility surcharge will vary year-to-year. The CRS is
inversely related to the prevailing market price of electricity such that if
market prices fall, the CRS will increase. To the extent the CRS increases
and the Aggregator has locked in electricity prices through long-term
electricity or fuel contracts, the CCA customers’ total rates will increase.
The CRS could also increase if the CPUC allows PG&E to include new
power purchase contracts or resources in the CRS, and the costs are above
prevailing market prices.
x The Aggregator could improperly hedge its exposure to electricity and/or
natural gas price volatility, and adverse price movements could cause rate
increases for its customers. Similarly, the Aggregator could over-rely on
long-term contracts with fixed prices and find itself holding a high cost
portfolio if market prices subsequently fall.
x The Aggregator could fail to properly secure its customer base, making
debt financing via the capital markets impossible to obtain and exposing
the Aggregator to stranded costs if customers opt-out of the CCA
program. Even with appropriate switching rules, large customers may go
out of business or leave the area and leave behind costs that must be paid
by remaining program customers.
x The Aggregator’s energy suppliers could default on supply contracts
(credit risk) at times when energy spot markets are high, forcing the
Aggregator to purchase energy at excessively high prices. Customers
could fail to pay the Aggregator’s charges, and the Aggregator’s credit
policies and customer deposits may be insufficient to recover the
uncollectible bills .
x PG&E could make changes to its rate designs that reduce the cost of
generation services and increase the costs of delivery services or that shifts
costs among customer classes in a manner that disadvantages the
customer mix served by the Aggregator.
x Other regulatory risks associated with changes in the rules and tariffs
administered by the CPUC or in the wholesale markets regulated by the
Federal Energy Regulatory Commission (FERC) could increase the
35
Aggregator’s cost of providing service. For example, the institution of a
requirement to use geographic-specific load profiles for electricity
procurement could advantage coastal communities to the detriment of
those located in hotter, inland climates
Each of these risks can be mitigated, although not altogether eliminated. The
County can structure its program in such a way that it would be exposed to very
little risk, however. Electricity supply contracts can be structured to transfer
many of the risks to the program’s suppliers. The following table describes basic
risk management techniques for each of the primary risks associated with
operating a CCA program.
Risk Mitigation
Cost Responsibility Surcharge
Volatility
Utilizing shorter duration supply
contracts to a greater extent than
would otherwise be indicated would
offset the CRS risk. If market prices
decrease, the Aggregator’s supply
portfolio costs will also decrease,
offsetting the increase in the customer’s
CRS payments to PG&E.
Commodity Price Volatility Diversify supply portfolio with
contracts of various terms and with
multiple suppliers, renewable energy,
and conventional generation. Layoff
commodity price risks to energy
suppliers through fixed priced
contracts or guaranteed discount
pricing structures
Customer Attrition Establish exit fees following free opt-
out period. Negotiate term contracts
with large customers.
Credit Risk Periodic credit and exposure
monitoring; supplier diversity;
collateral and surety instruments.
Require deposits from customers and
return to utility for failure to pay bills.
Utility Rate Changes and Other
Regulatory Risks
Participate in CPUC process to prevent
shifting of costs to program customers
36
4.1.3.1 Operations Risk Discussion
Ultimately, the major operational risks are under the control of the program’s
management. Disciplined, professional management is key to managing risks
inherent in offering retail electric services. The Aggregator will be able to
contract for services from a variety of large, experienced energy suppliers that
have operational capabilities equal to or better than those of PG&E. It should be
noted that municipal utilities have been successfully managing commodity,
credit, and operational risks for many decades, even during times of high
commodity prices and supply shortages.
The experiences of PG&E, SCE and SDG&E during the energy crisis of 2000-2001
illustrate what can happen when risks are not properly managed. The investor
owned utilities’ exposure to commodity price risks during the energy crisis and
the ensuing financial devastation experienced by PG&E and SCE stemmed from
an artificial constraint imposed by the CPUC on their hedging abilities, coupled
with an inability to increase retail rates due the legislated rate freeze. The
CPUC’s so-called buy/sell requirement forced the utilities to buy 100% of their
energy from the state sanctioned (now defunct) California Power Exchange daily
market auction and sell 100% of their generation resources into that market.
Because the utilities had divested nearly all of their natural gas fired generation
resources, they were each heavily short on resources and overly reliant on the
spot market. When spot market prices spiked for an extended period of time, the
cash drain necessitated the State of California (Department of Water Resources)
to take over electricity procurement responsibilities from the utilities. Customers
of SDG&E were not protected by the rate freeze and suffered from excessive
rates as SDG&E was able to pass through its costs of procuring electricity from
the spot markets.
The Aggregator will not be subject to these types of constraints on its
procurement practices. Being a municipality, it will exercise its own authority
over its resource planning and ratemaking decisions. A professionally managed
electricity procurement program, following sound risk management practices,
would not expose itself to the risks that the investor owned utilities faced during
the energy crisis.
4.1.3.2 Regulatory Risk Discussion
Regulatory risks refer to the potential that decisions by regulators could cause
cost increases for the CCA program. The Aggregator can participate in
regulatory proceedings at the CPUC or FERC to try to influence the regulatory
process to protect its interests and those of its customers. Typically, associations
are formed among entities with common interests to participate on their behalf in
37
the regulatory process to effectuate maximum influence on regulators. The
amount of influence wielded in the regulatory process depends on the resources
the association can devote to participation and the political influence of the
associations members. Thus, to some extent the degree by which regulatory risk
can be managed depends upon the prevalence of CCA throughout the state. If
CCA becomes a widespread phenomenon, with many communities being
directly impacted by CPUC decisions, the CPUC is less likely to make decisions
that impose additional costs on Aggregators than if only one or two communities
would be impacted.
4.1.4 Risk Mitigation Through Physical and Financial Reserves
Physical and financial reserves are important components of a CCA program
that reduce program risk. Industry rules dictate certain reserve requirements for
all market participants to protect the integrity of the system. These rules ensure
no degradation of reliability would result if the County were to implement a
CCA program.
4.1.4.1 Physical Reserves
The program will be required to comply with industry rules governing the
provision of physical reserves to ensure reliable operation of the electric grid.
The California Independent System Operator (CAISO) requires load-serving
entities to maintain operating reserves (6% to 8% of load) and regulating reserve
(2.5% to 5%) that can be quickly called upon in the event that scheduled
resources experience outages or electricity consumption unexpectedly increases.
Load serving entities can arrange for their own reserves, or the CAISO will
charge the load serving entity for the costs of reserves procured on its behalf.
The costs of these reserves are included as an expense item in the pro forma.
On a longer-term basis, the CPUC requires load-serving entities to arrange for a
15% planning reserve margin, approximately one year in advance. The planning
reserve requirement was instituted in 2004 and is in intended to both ensure the
existence of adequate generation capacity as well as to reduce the ability of
power suppliers to charge high electricity prices that can occur when capacity is
scarce. The costs of planning reserves are included as an expense item in the pro
forma.
4.1.4.2 Financial Reserves
The program will maintain financial reserves in the form of rate stabilization
funds or other reserve funds that would be required by the banks to support
38
debt financing of program assets. Rate stabilization funds are maintained at the
discretion of program management and the program’s governing board. They
are used to cushion short-term cost increases as well as to accrue cash for future
capital expenditures. To the extent that debt financing is utilized to fund capital
expenditures, banks will require minimum debt service reserves equal to
approximately 10% of the amount borrowed, and will also impose minimum
debt service ratios to ensure adequate debt service coverage. These financial
reserves are included in program rates, but these funds are an asset of the
program that will ultimately be accessible for future rate reductions or other
program purposes.
4.1.5 Risk Mitigation Through Phased Implementation
The County could implement a CCA program in phases to limit any risks
associated with program startup and the transition of customers from PG&E to
service by the program. An example could be to initially offer the program to
non-residential customers for a pilot phase such as six months or one year and
then to open the program to all customers after the pilot phase is completed. By
starting with non-residential customers, the number of transactions (account
transfers, monthly billing, etc.) that must be completed would be a small fraction
of what would be required to serve the entire community at one time. Another
benefit of this type of phasing arises because non-residential customers are
higher margin customers so the initial phase-in period would provide greater
margins for the program to help cover program startup costs.
The CPUC will not determine which customers the CCA should serve.7
However, the County must comply with the legal requirements of AB 117 that
requires equitable treatment of all customer classes and the offering of service to
all residential customers. The Implementation Plan should describe the phasing
approach, if any, that the County intends to utilize and how that approach
complies with the law.
7 See D.04-12-046, Conclusion of Law No. 38.
39
5 FEASIBILITY ANALYSIS
5.1 Study Approach
In preparing the financial evaluation for a CCA program, NCI did a thorough
analysis of: (1) PG&E’s forecasted rates (including cost responsibility
surcharges); (2) CCA energy or commodity costs (including generation
ownership, power purchase contracts, renewable energy contracts and spot-
market purchases; (3) CAISO charges; (4) operations and scheduling costs; (5)
financing costs; and (6) revenue offsets and available financial incentives. Each
of these items was factored into the pro forma analysis. The CCA program’s
capital costs are amortized over a 30-year period and financed at a rate of 5.5%.
The interest and amortization are included in the annual costs of the program.
The financial pro forma analysis compares the total costs of operating the CCA
program with the total costs of continuing to take retail utility service from
PG&E.
A financial analysis was performed in order to develop financial pro forma,
which are then structured as consolidated statements of income for the CCA
program. The consolidated statements based on the financial pro forma are
located in Appendix E. As noted above, savings or potential income is the
margin between current retail power costs, as provided by PG&E, and the
Aggregator’s projected cost to provide the power. NCI began its evaluation with
a planning horizon beginning in the current year (2005) and then projected costs
20-years forward to 2024.
PG&E provides services at regulated cost-based rates. Hence, PG&E’s rates are
directly tied to a demonstrated “revenue requirement”, which is the total
revenues the utility is authorized to recover through rates. The revenue
requirement includes the utility’s expenses, return or profit, and taxes paid by
the utility. The financial analysis provided herein compares PG&E’s revenue
requirement at current and projected rates with the revenue requirement of the
CCA program to determine potential savings or income. Pro forma summary
tables compare each supply portfolio based on their relative ability to produce
operational cost savings or benefits.
In a CCA program, utility service is limited to the electric energy commodity
only. PG&E would continue to provide electricity delivery over its existing
distribution system and provide end-consumer metering, billing, collection and
all traditional retail customer services (i.e., call centers, outage restoration,
extension of new service). Accordingly, to evaluate the potential benefits for
CCA, only costs associated with wholesale electric commodity procurement and
related business expenses are considered.
40
5.2 Customer Base
The potential customer base for the CCA program is all of the electric customers
in the County, assuming the County forms a CCA program in conjunction with
the eleven Marin County cities. Otherwise, the customer base would be limited
to the electric customers within the unincorporated areas of the County. The
distribution of electricity sales with the County are shown in the chart below:
SAN RAFAEL
25%
CORTE MADERA
6%
BELVEDERE
1%
FAIRFAX
2%
MILL VALLEY
5%NOVATO
20%
MARIN
25%
LARKSPUR
5%
SAUSALITO
4%
TIBURON
3%
ROSS
1%
SAN ANSELMO
3%
Customers have the option to opt-out of the CCA program and continue to
receive their electric service from PG&E. Some customers may choose to not
participate in the program, or opt-out during the 60-day opt-out period, and
some direct access customers may be contractually prevented from initially
joining the program until their direct access contracts expire. The prevalence of
customer opt-outs will depend on a number of factors, not the least of which is
how the Aggregator’s electric rates compare to those of PG&E. Other factors that
will influence customers’ opt-out decisions include whether the Aggregator
provides non-price features important to customers such as increased renewable
energy purchases or expanded energy efficiency programs; customer loyalty or
enmity to PG&E; and other customer perceptions. Many of these factors are
directly dependent on the details of the Aggregator’s Implementation plan, and
the impacts cannot be reasonably estimated prior to completion of the County’s
implementation planning process. For the purposes of this feasibility analysis,
the report presents the potential benefits from CCA, assuming 100 percent
41
customer participation. Within a reasonable range of assumed opt-out
percentages, the study results can be adjusted proportionately.
5.3 Key Assumptions
As described in Section 2.2, the CPUC is in the process of finalizing the rules for
CCA implementation. NCI developed several framework assumptions for this
feasibility analysis and also adopted a set of detailed assumptions for various
unknown costs and implementation rules. This section describes the high level
assumptions that provide the framework for the analysis. The detailed
assumptions are listed in Appendix B.
1. CCA Rulemaking is completed by the third quarter of 2005, and CCA
operations can begin in January 2006
2. Charges authorized by the CPUC for Aggregators and CCA customers are
similar to those charged to direct access customers (transaction and
implementation fees)
3. Aggregators must maintain adequate capacity reserves to maintain
reliability standards and will follow standard industry risk management
practices. Aggregators will be held to the same capacity reserve standard
as PG&E.
4. Aggregators will match or exceed the renewable energy content of PG&E’s
portfolio and are eligible for the existing CEC subsidies provided for
renewable energy procurement up to the minimum renewable portfolio
standard (i.e., subsidies are available for the first 20% of renewable energy)
5. Market prices for renewable energy will reflect the developer’s costs,
including the effects of available subsidies
6. Aggregators can finance generation projects
7. Aggregators can obtain electricity from the wholesale market on
comparable terms with the IOUs
8. The CPUC does not allow IOUs to negotiate special rates or contracts to
retain customers
9. CCA operations can be outsourced to third parties
42
10. Reinstatement of direct access does not preempt CCA rights and customer
relationships
5.3.1 Utility Rate Benchmarks
Estimates of CCA cost savings potential are assessed by comparing CCA costs to
the rates that would otherwise be charged by PG&E. PG&E’s rates derive from
its costs or revenue requirement, and NCI modeled PG&E’s annual generation
revenue requirements for the 2005 to 2024 study period. The resulting rate
projection shows generation rates increasing at a modest average rate of 1.7% per
year due to offsetting influences on PG&E’s generation costs. The projected
annual rate increase of 1.7% is at the low end of historical trends.8 The reason for
this is that generation cost increases are somewhat offset by the expiration of
high cost DWR contracts in the 2004 to 2012 period, and the net result is a
moderately increasing rate forecast. Once the DWR contracts expire in 2012,
PG&E’s generation costs are expected to show annual increases consistent with
general levels of inflation and gas price escalation.
PG&E System Average Total Rate Projections
2005 - 2024
0
20
40
60
80
100
120
140
160
1802005200720092011201320152017201920212023
Dollars Per MWhNon-gen. Rate
DWR Bonds
Gen. Rate
PG&E’s generation revenue requirements are modeled for each resource in
PG&E’s generation portfolio, including the DWR contracts the CPUC allocated to
PG&E in Decision No. 02-09-053. As production from existing resources or
supply contracts decline over time, they are replaced by new power purchase
contracts at prevailing market prices. Short-term “spot market” purchases are
8 Depending upon the specific timeframe selected for comparison, during the past twenty-five years,
SDG&E rates have increased by an average annual rate of between 1% and 4%.
43
maintained at 15% of the total portfolio. New renewable contracts are added to
the resource mix to meet the applicable Renewable Portfolio Standards
requirements, and planning reserve requirements of 15% are enforced in the rate
projections.
PG&E Resource Mix
2005 - 2024
-
20,000,000
40,000,000
60,000,000
80,000,000
100,000,000
120,000,000
2005200720092011201320152017201920212023MWh Per YearResidual Net Short
New Renew ables (RPS)
New Bilaterals
DWR Contracts
Bilaterals
QFs
Hydro
Diablo Canyon
Thermal
The revenue requirement for each resource type was modeled based on data
provided by PG&E in its 2003 Cost of Service Proceeding and FERC Form 1
filings. The current costs are shown below. Costs were projected forward for the
study period by calculating annual depreciation, operations and maintenance
expenses, taxes, and authorized return on rate base for each resource.
PG&E Resource Costs
2005
0
50
100
150
200
Dollars Per MWhHydro
Nuclear
Residual Net Short
New Bilaterals
New Renew ables
DWR Contracts
QFs
Thermal
44
* The per unit cost of thermal resources is high due to the limited energy production from these
resources which are primarily used to provide system reserves.
5.3.2 Cost Responsibility Surcharges
The single greatest obstacle to achieving significant cost savings through CCA in
the next several years is PG&E’s imposition of cost responsibility surcharges on
CCA customers, which are designed to shield PG&E from any financial losses or
cost increases that might result from customers switching to service by the
Aggregator. NCI modeled expected cost responsibility surcharges using the
methodology adopted in the CCA Phase 1 Decision (D.04-12-046). According to
this methodology, the above market portion of PG&E’s generation portfolio,
including PG&E contracts and resources and the DWR contracts, are included in
the CRS. Other elements of the CRS include the DWR Bond Charge and, for
PG&E, the charge for recovery of the “regulatory asset” that was established to
enable PG&E’s emergence from bankruptcy. The latter two costs are reasonably
certain and predictable, while the uneconomic portfolio costs are less easily
predicted because they directly depend on future electricity market prices and
PG&E’s future generation costs.
In D.04-12-046, the CPUC adopted an interim CRS of 2.0 cents per kWh. 9 The
CPUC established the interim CRS for an 18-month period and ordered PG&E to
calculate an updated CRS based on current forecast data. The adopted CRS
methodology causes the CRS to be inversely related to electricity market prices:
i.e., as market prices increase the CRS declines and vice versa. Because current
market price projections are higher than those used by the CPUC to establish the
interim CRS estimate, the updated CRS is expected to be lower than the interim
amount. NCI used the interim CRS for 2005 and assumed that it would be
updated by PG&E prior to 2006.
The CRS cost estimates used in this analysis are consistent with the electricity
cost projections underlying the Aggregator’s modeled supply portfolio. The
electricity market prices are somewhat higher than the estimates used by the
CPUC to develop the 2.0 cents per kWh interim CRS. As a result, in NCI’s
analysis the CRS is projected to decline sharply from 2005 to 2006 as the interim
number is replaced with the updated cost figures. If future power prices turn
out lower than those used for the base case analysis, the CRS would be higher
than the forecasts used in this analysis. However, the cost of procuring power
for the CCA program would be lower than the costs used in the analysis. These
two impacts tend to offset each other. Therefore, the magnitude of the CRS
should not be looked at in isolation, but should be assessed in context with the
9 The 2.0 cents per kWh interim CRS is in addition to the DWR Bond Charge and the Regulatory Asset.
45
market price assumptions used in the overall feasibility assessment. The net
effect of higher or lower power prices on the overall cost of service for the CCA
program can be seen in the sensitivity analysis results presented in Section 6.3.
The following chart shows the components of the CRS for PG&E over the study
period under the base case scenario.
Cost Responsibility Surcharges
Pacific Gas And Electric Company
-
5
10
15
20
25
30
35
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023Dollars Per MWhDWR Bond
Regulatory Asset
CTC
DWR Power
With the exception of the DWR bond charge, the CRS is expected to become zero
by 2012, as DWR contracts expire, market prices trend upwards, and the cost of
the regulatory asset is fully recovered.
5.3.3 Renewable Energy Subsidies
A variety of tax incentives, credits and publicly funded subsidies exist for
renewable energy development, which reduce the effective cost of increasing the
renewable energy content of the program’s supply portfolio. These include the
following subsidies:
¾ Production Tax Credits
¾ Renewable Energy Production Incentives
¾ Supplemental Energy Payments (Public Goods Funds)
Some of the incentives, such as the production tax credit for renewable energy
production, are short-term and must be reauthorized by Congress on an annual
basis. Others, such as the public goods funding for renewable energy
development administered by the California Energy Commission
46
(“Supplemental Energy Payments”), are more long lived, but are contingent on
the sufficiency of the public goods fund collected through utility rates. The
economic analysis conducted for the County includes the effect of Supplemental
Energy Payments available to producers of renewable energy as described in
more detail below. The other potential subsidies are not included in the analysis
although they may ultimately be available to further reduce the program’s cost of
service.
Subsidies are included for renewable energy purchases from the market, to the
extent such purchases are needed to supplement production from the
Aggregator’s resources. The renewable energy costs for purchases up to the
minimum renewable portfolio standard are offset by Supplemental Energy
Payments, while the incremental renewable energy above and beyond the
minimum requirement is assumed to receive no subsidy. Thus, the costs of
renewable energy utilization above the first 20% would be paid entirely by
customers of the CCA.
No Supplemental Energy Payments are assumed to be available to offset costs of
the Aggregator’s renewable resources that it owns or otherwise finances. The
reason for this assumption is that the process for determining Supplemental
Energy Payments was premised on the utilities conducting competitive
solicitations for long-term supply contracts with producers of renewable energy.
Funds are made available to winning bidders to cover the excess of their costs
above a market benchmark, determined by the CPUC. The CPUC has so far been
focused on how the utilities are to meet the Renewable Portfolio Standards, and
the rules and protocols for making Supplemental Energy Payments available to
Community Choice Aggregators have not yet been established.
It is unclear at this time how the process developed for the utilities would apply
to an Aggregator that develops its own renewable resources rather than procures
renewable energy through long-term, competitively solicited contracts.
Financing structures that entail prepayment for energy through long-term power
purchase contracts with a renewable energy producer should theoretically allow
the Aggregator to receive the benefits of its financing advantages and also
qualify the producer for Supplemental Energy Payments. However, as stated
above, the rules have not been established, and the conservative assumption that
no such subsidy would be available was used in this analysis.
5.4 Financial Analysis Structure
CCA customer population electric loads are applied to PG&E’s current and
projected generation rates to yield its revenue requirement recovered from the
customers in the potential CCA area. CCA operating expenses are projected and
47
subtracted from PG&E’s revenue requirement to yield the projected financial
benefit. Elements contained in the analysis are summarized below and details of
the inputs, assumptions and sources are provided in Appendix B:
Utility Forecast Generation Rates
- Utility Retained Generation
- Qualifying Facility Generation
- Bilateral Power Purchase Contracts
- New Renewable Energy Purchases
- CAISO charges
- Residual Spot Market Purchases or Sales
CCA Energy Cost (Commodity Costs)
- Spot Market Purchases
- Power Purchase Contracts
- Renewable Energy Contracts
- Generation Ownership
California Independent System Operator Charges
- Ancillary Services/Reserves
- Grid Management Charges
- Deviation Charges
Operation and Scheduling Costs
- Electricity Procurement
- Risk and Credit Management10
- Load Forecasting
- Scheduling and Settlements
- Rates
- Account Services
- Administration
Non-Bypassable Charges/Cost Responsibility Surcharge
- Uneconomic Utility Retained Generation and Power Contracts
- DWR Power Purchase Contracts
- DWR Bond Charges - Financing Past Purchases
10 The costs of uncollectible customer accounts are not explicitly included in the pro forma, under the
premise that the Aggregator would require customer deposits from customers that pose likely credit risks,
similar to the accepted utility practice. Because under current rules the Aggregator cannot cause service to
be shut-off to the customers for failure to pay its portion of the bill whereas the utility can, it is important
that the Aggregator have the ability to screen customers prior to automatic enrollment for administration of
its credit policies and that the Aggregator has the right to return the customer to the utility for failure to
pays its charges. This issue should be addressed in Phase 2 of R.03-10-003.
48
5.5 Load Analysis
Detailed definition of community electric power needs is required to assess the
economic viability of the CCA providing electric energy as an alternative to the
community’s existing supplier, PG&E. Community electric demand and energy
consumption, generally referred to as electric load, has been analyzed and
described in charts and graphs located in Appendix G. NCI performed load
analysis and constructed a load forecast beginning with and based upon data
provided by PG&E in response to the Community’s formal request (see
Appendix C for sample data request letter). The Community’s annual hourly
load shape was developed, and a determination made regarding associated
energy supply requirements. The time-of-use supply requirements serve to
define the types of resources necessary to supply electric energy to the CCA.
5.5.1 Load Forecast Methodology
Community electric load data provided by PG&E was 12-month, year-to-date
energy consumption and number of customers by rate class as of October 2003.
PG&E provided up to 20 rate classes that NCI collapsed into 7 higher-level
Customer Sectors. Rate classes and their generic sector rate class description
assignments are listed in the following table:
Rate PG&E
Schedule Description Customer Sector Description
A-1 Small General Service Small Commercial
A-6 Small General Time-of-Use Service Small Commercial
AG-1 Agricultural Power Small Commercial
A-10 Medium General Demand-Metered Service Medium Commercial
E-1 Residential Service All-Residential
E-2 Experimental Residential Time-of-Use Service All-Residential
E-3 Experimental Residential Critical Peak Pricing Service All-Residential
E-7 Residential Time-of-Use Service All-Residential
E-8 Residential Seasonal Service Option All-Residential
E-9 Experimental Res Time-of-Use Service for Low Emission Vehicle Custs All-Residential
EML Master-Metered Multifamily CARE Program Service All-Residential
ES Multifamily Service All-Residential
ETL Mobile Home Park CARE Program Service All-Residential
E-19 Commercial/Industrial/General Large Commercial
Medium General Demand-Metered Time-of-Use Service
E-20 Commercial/Industrial/General Large Commercial/Industrial (C/I)
Demand Greater than 1,000 Kilowatts
LS-1 PG&E Owned Street and Highway Lighting Street Lighting
LS-2 Customer-Owned Street and Highway Lighting Street Lighting
LS-3 Customer-Owned Street and Highway Lighting Electrolier Meter Rate Street Lighting
OL-1 Outdoor Area Lighting Service Street Lighting
TC-1 Traffic Control Service Traffic Control
Rate Schedule to Customer Sector Assignment
49
The monthly load information was ordered by month; January through
December, to reflect monthly seasonal use patterns and treated as prototypical
for 2003 energy consumption. PG&E published static load profiles were
employed to allocate monthly energy (kWh) into each hour of the month and
then to each of the 8,760 hours within a year. Rate class static load profiles where
selected as most characteristic of load usage patterns in each of the Customer
Sectors as reflected in the following table:
Customer Sector Static Load Profile
Small Commercial A-1
Medium Commercial A-10
Large Commercial E-19
Large (C/I) E-20
Street Lighting LS-1
Traffic Control TC-1
Static Load Profile Assignment
A twenty-year electric load forecast was performed forecasting electric demand
energy requirements for years 2005 through 2024. Electric energy requirements
and customer populations were escalated based upon sector specific growth
planning statistics provided by the City; if none was provided PG&E system-
wide growth rates were applied.
The number of customer accounts and annual energy sales for the initial year
(2006) of the program are shown below.
Accts kWh Accounts kWh Accounts kWh Accounts kWh
Residential 103,499 668,775,747 105,051 678,807,383 106,627 688,989,494 108,226 699,324,336
Small Commercial 12,296 215,177,071 12,480 218,404,728 12,668 221,680,798 12,858 225,006,010
Medium Commercial 1,151 198,929,538 1,169 201,913,481 1,186 204,942,183 1,204 208,016,316
Large Commercial 186 90,023,919 188 91,374,278 191 92,744,892 194 94,136,065
Large C/I 24 137,688,934 24 139,754,268 24 141,850,582 25 143,978,341
Street Lighting 483 7,726,001 483 7,726,001 483 7,726,001 483 7,726,001
Traffic Control 161 542,202 161 542,202 161 542,202 161 542,202
Total 117,800 1,318,863,413 119,557 1,338,522,341 121,341 1,358,476,153 123,151 1,378,729,272
* 2003 Data Provided by Distribution Utility (PG&E) and Escalated by Applying The Following Growth Rates:
Growth Rates
Residential 1.50%
Commercial 1.50%
2005 * 2006 *2003 2004 *
5.5.2 Community Energy Load Shape
The community composite annual energy load shape (average kW per hour) was
developed by combining average loads in each hour from each of the Customer
50
Sector static load profiles identified above. A prototypical annual load profile is
shown in the following figure.
8760 Hours per YearElecetric Demand
Electric load was next broken down into quarterly and weekly demand periods
to capture seasonal variation in projected loads and electric generation resource
requirements. The resulting quarterly minimum, as well as peak power
requirements, is the basis for “sizing” the portfolio of contracts and generation
resources needed to serve the Aggregator’s load profile.
5.5.3 Renewable Portfolio Standards Requirements
The California Renewable Portfolio Standard Program (RPS) established by
Senate Bill 1078 requires that a retail seller of electricity purchase a specified
minimum percentage of electricity generated by qualifying renewable energy
resources. Community Choice Aggregators are required under SB 1078 to
procure a specified minimum percentage of total kilowatt hours sold to retail
end-use customers each calendar year from renewable resources.
Each distribution utility is required to increase its total procurement of eligible
energy resources by at least 1% per year so that 20% of its retail sales are
procured from eligible renewable energy resources by year 2017. CCA program
aggregated loads are a subset of load currently served by the distribution utilities
(SCE, PG&E and SDG&E). Therefore, analyses contained herein assume that
customer energy requirements of the prospective CCA will, at a minimum, be
equal to the renewable energy percentage required of each distribution utility.
Further, when the County applied for and was accepted into the CCA
Demonstration Project it declared as a goal to double the RPS and achieve a
51
renewable energy content of 40% by 2017. The following table reflects
distribution utility RPS renewable energy requirements projected forward.
PG&E SCE SDG&E
Year MIN MIN MIN
2003 16% 5%
2004 12% 17% 6%
2005 13% 18% 7%
2006 14% 19% 8%
2007 15% 20% 9%
2008 16% 20% 10%
2009 17% 20% 11%
2010 18% 20% 13%
2011 19% 20% 14%
2012 20% 20% 15%
2013 20% 20% 16%
2014 20% 20% 17%
2015 20% 20% 18%
2016 20% 20% 19%
2017 20% 20% 20%
2018 20% 20% 20%
2019 20% 20% 20%
2020 20% 20% 20%
2021 20% 20% 20%
2022 20% 20% 20%
2023 20% 20% 20%
2024 20% 20% 20%
The bill requires the CPUC to adopt rules for implementing the RPS, and CCA
planners must understand the renewable energy requirements before they can
assess the cost-benefits and make threshold decisions to implement a CCA
program. County minimum renewable energy requirements are summarized in
the table below.
52
Renewable Resource Requirements Projected Forward
MWh
1 X RPS 2 X RPS 1 X RPS 2 X RPS
2007 1,399,286 80 159 279,857 559,714
2008 1,420,151 86 172 284,030 568,061
2009 1,441,330 93 186 288,266 576,532
2010 1,462,826 100 200 292,565 585,130
2011 1,484,644 107 214 296,929 593,858
2012 1,506,790 114 229 301,358 602,716
2013 1,529,267 116 233 305,853 611,707
2014 1,552,082 118 236 310,416 620,833
2015 1,575,240 120 240 315,048 630,096
2016 1,598,744 122 243 319,749 639,498
2017 1,622,601 123 247 324,520 649,041
2018 1,646,816 125 251 329,363 658,727
2019 1,671,395 127 254 334,279 668,558
2020 1,696,341 129 258 339,268 678,537
2021 1,721,663 131 262 344,333 688,665
2022 1,747,363 133 266 349,473 698,945
2023 1,773,450 135 270 354,690 709,380
2024 1,799,928 137 274 359,986 719,971
Energy Renewable Capacity
Requirement (MW)
Renewable Energy
Requirement (MWh)
* Capacity figure is based on a capacity factor of 30%, typical of wind resources.
53
6 FINANCIAL PROJECTIONS
The supply portfolio modeled for the County contains a diverse mix of resources
reflective of a strong commitment to promotion of renewable energy.
The resource types include:
x Spot market purchases – short-term electricity purchases to supplement
resources under contract control of the Aggregator
x Contract purchases – longer term, fixed price power purchases. Terms
can be monthly, quarterly, annual or multi-year. For purposes of this
analysis, the contracts were structured with sequential two, three, or five-
year terms.
x Natural gas power production –production from a combined cycle natural
gas combustion turbine owned by the Aggregator used for baseload or
shaping purposes
x Renewable energy purchases – purchases of renewable energy to meet the
Aggregator’s renewable resource goals, with a minimum equal to PG&E’s
renewable energy mix. For purposes of this analysis, purchases are from a
generic renewable portfolio with a cost equal to the weighted average of
the renewable resources expected to fulfill California’s RPS.
x Renewable energy power production – production from renewable energy
resources owned by the Aggregator. For purposes of this analysis, an
equity position in wind and geothermal facilities sized to meet the
Aggregator’s renewable resource goals
x Off system sales – sales of excess energy into the spot market at times
when the resources under contract or ownership are in excess of the
Aggregator’s load requirements
The total cost of service for the CCA program was calculated and compared to
the generation costs charged by PG&E. The difference represents potential
savings or costs associated with the CCA program. These savings are shown for
each year in the study period, with positive numbers indicating lower costs for
the CCA and negative numbers indicating higher costs. Costs or savings are
shown both in millions of dollars per year and as a percentage of customers’
monthly electric bills.11
11 The percentage savings are expressed based on total electric bills, including PG&E delivery charges.
The percentage savings on the generation component of bills would be approximately double the
percentages shown.
54
Summary Of Electric Cost Savings From Community Choice Aggregation
Base Case Scenario
(Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 108.3 107.2 (1.0) -1%
2007 108.8 109.1 0.3 0%
2008 116.7 113.1 (3.5) -2%
2009 111.7 115.9 4.2 2%
2010 118.5 121.8 3.4 2%
2011 122.6 125.7 3.1 1%
2012 126.1 129.9 3.8 2%
2013 114.8 123.3 8.5 4%
2014 117.7 126.9 9.2 4%
2015 125.8 131.3 5.5 2%
2016 127.6 134.5 6.9 3%
2017 132.5 141.2 8.8 3%
2018 139.7 151.5 11.8 4%
2019 146.6 160.9 14.3 5%
2020 156.4 166.2 9.8 3%
2021 158.6 167.7 9.1 3%
2022 161.8 171.5 9.6 3%
2023 160.1 171.8 11.8 4%
2024 168.1 182.2 14.1 4%
Total 2,522.3 2,651.8 129.5 3%
Total nominal savings over the study period are $129.5 million or
approximately 3% of customers’ total electricity costs. Cost savings average
approximately $6.8 million per year.
6.1 Supply Portfolio Details
The CCA program would be supplied from a diverse portfolio of energy
resources. The portfolio is designed to achieve the County’s 51% renewable
energy objective in stages. The Aggregator initially matches the renewable
content of PG&E’s portfolio and incrementally increases the renewable
component to achieve a mix of 51% by 2017. The Aggregator invests in
generation resources to meet its baseload energy requirements. The portfolio
also includes power purchases through five-year contracts and spot market
55
purchases to supplement the production of the Aggregator’s generation
resources.
The resource mix includes both conventional and renewable resource ownership.
The portfolio initially contains only purchases from the open market, and
beginning in 2008, it includes production from wind and geothermal resources.
2008 was selected as the earliest feasible date for the Aggregator to acquire
equity in a new generation resources, considering lead times for negotiations,
permitting and financing.
CCA Generation Resources In CCA Portfolio
Resource Type Capacity (MW) On-line Capital Cost
($ Millions)
Wind 90 2008 101.1
Geothermal 10 2008 27.6
Gas Combined Cycle 50 2010 40.0
Wind 80 2013 100.2
Geothermal 20 2013 58.1
The assumed renewable generation resources were sized to meet the
Aggregator’s renewable energy target projected for the next several years. As a
result, the portfolio initially contains greater renewable energy than targeted.
Later, as load growth continues, the renewable production must be
supplemented with renewable energy purchases to meet the County’s targeted
renewable percentage of 51%.
56
Long Term Resource Mix Utilized For Financial Pro Forma
-20%
0%
20%
40%
60%
80%
100%
120%
2006 2008 2010 2012 2014 2016 2018 2020 2022 2024
Renew able Generation Renew able Purchases Gas Generation
Contract Purchases Spot Market Purchases Off System Sales
No subsidies are assumed to be available to offset costs of the Aggregator’s
renewable resources. Subsidies are included for renewable energy purchases, to
the extent such purchases are needed, consistent with the subsidy treatment
discussed in Section 5.3.3.
Capital expenditures associated with the preferred portfolio include startup costs
of $400 thousand and generation investments of $129 million in 2008, $40 million
in 2010, and $158 million in 2013. Initial financing of $5 million is used to
establish a rate stabilization fund to ensure that rates during the initial three
years of program operations remain at or below those of PG&E.
6.2 Alternative Supply Scenarios
Financial pro forma were prepared for four additional supply portfolios that
differ by varying the mix of renewable energy in the portfolio and by whether
the Aggregator owns generation resources used to supply electricity to the
program. The pro forma for the alternative supply portfolios are included in
Appendix F. Analysis of the alternative supply scenarios can assist the County
in understanding the cost effectiveness and tradeoffs among different resources
that could be included in a portfolio to supply the CCA program.
6.2.1 Alternative Supply Scenario 1
Supply Scenario 1 assumes the Aggregator doubles the renewable content of
PG&E and purchases all of its load requirements from the open market.
Inclusion of renewable energy increases the portfolio’s cost, even after
57
considering the subsidies potentially available to the Aggregator’s renewable
energy suppliers. The renewable energy costs for purchases up to the minimum
renewable portfolio standard are assumed to be offset by supplemental energy
payments administered by the CEC, while the incremental renewable energy
above and beyond the minimum requirement is assumed to receive no subsidy.
Thus, the second 20% of targeted renewable energy is paid entirely by customers
of the CCA.
Capital expenditures associated with Scenario 1 is limited to program startup
costs estimated at $400 thousand.
This supply strategy results in a loss over the study period of $218.7 million or
5% of total electricity costs.
6.2.2 Alternative Supply Scenario 2
Supply Scenario 2 assumes the Aggregator matches the renewable content of
PG&E and purchases all of its load requirements in the open market. Renewable
energy subsidies are available to offset the incremental cost of the Aggregator’s
renewable energy purchases.
Capital expenditures associated with Scenario 2 is limited to program startup
costs estimated at $400 thousand.
This supply strategy results in a loss over the study period of $173.4 million or
4% of total electricity costs.
6.2.3 Alternative Supply Scenario 3
Supply Scenario 3 assumes the Aggregator doubles the renewable content of
PG&E and produces electricity from resources that it owns. The portfolio also
includes power purchases through five-year contracts and spot market purchases
to supplement the production of the Aggregator’s generation resources. Supply
Scenario 3 includes both conventional and renewable resource ownership. The
portfolio initially contains only market purchases similar to Supply Scenario 1,
but beginning in 2008, it includes production from wind and natural gas-fired,
combined cycle resources. 2008 was selected as the earliest feasible date for the
Aggregator to acquire equity in a new generation resources, considering lead
times for negotiations, permitting and financing.
No subsidies are assumed to be available to offset costs of the Aggregator’s
renewable resources. Subsidies are included for renewable energy purchases, to
58
the extent such purchases are needed, consistent with the subsidy treatment
described for Scenario 1.
Capital expenditures associated with Scenario 3 include startup costs of $400
thousand and generation investments of $269 million in 2008 and $36 million in
2010.
This supply strategy results in total savings over the study period of $76.9
million or 2% of total electricity costs.
6.2.4 Alternative Supply Scenario 4
Scenario 4 is similar to Scenario 3 except that the portfolio matches the renewable
content of PG&E’s supply portfolio, with a corresponding increase in the
capacity of natural gas fired generation financed by the Aggregator.
Capital expenditures associated with Scenario 4 include startup costs of $400
thousand and generation investments of $135 million in 2008 and $68 million in
2010.
This supply strategy results in total savings over the study period of $72.4
million or 2% of total electricity costs.
Comparing the alternative supply scenarios reveals the cost advantage enjoyed
by the CCA in financing capital intensive generation projects. The incremental
cost of increasing renewable energy from 20% to 40% is not a significant factor in
the program’s cost-effectiveness.
6.3 Sensitivities
Sensitivity analyses can help put upper and lower bounds on the expected
financial results from implementing a CCA program. NCI performed sensitivity
analyses for the major variables expected to impact the financial results. The
results of these sensitivities are shown below:
x Natural gas and power prices (+/- 25%)
x Cost responsibility surcharges (+/- 50%)
x PG&E system average rate projections (1% to 3% annual growth)
x PG&E revenue allocation changes to reduce cross subsidies (As
proposed in its General Rate Case)
None of the sensitivity scenarios eliminated program savings over the study
period. However, the high and low natural gas/power prices scenario
59
(Scenarios 2 and 3) and the high CRS scenario (Scenario 5) caused revenue losses
in the early years of the program. The County should pay particular attention to
changes in these variables if and when it proceeds with implementation of its
CCA program. A phase-in of program operations would mitigate exposure to
these factors. Another method for accelerating financial benefits would be to
create a rate stabilization fund by issuing debt that would be backed by the
future revenue streams of the program, thereby moving a portion of future
savings forward in time.
Annual financial results associated with the sensitivity scenarios are shown in
the following tables.
60
Scenario 2: Natural Gas And Power Prices Are Reduced By 25% From The
Base Case (Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 103.2 103.1 (0.1) 0%
2007 104.0 104.8 0.7 0%
2008 115.9 108.5 (7.4) -4%
2009 110.9 110.9 (0.0) 0%
2010 113.2 111.1 (2.1) -1%
2011 110.6 113.8 3.2 2%
2012 112.2 116.8 4.6 2%
2013 105.6 109.4 3.8 2%
2014 107.6 112.3 4.8 2%
2015 113.1 116.0 2.9 1%
2016 115.2 118.6 3.4 2%
2017 117.1 124.0 7.0 3%
2018 119.3 132.1 12.8 5%
2019 124.6 139.5 14.9 6%
2020 132.1 143.9 11.8 4%
2021 133.8 145.3 11.4 4%
2022 136.3 148.5 12.1 4%
2023 133.1 147.3 14.2 5%
2024 139.3 155.5 16.2 5%
Total 2,247.1 2,361.3 114.2 3%
61
Scenario 3: Natural Gas And Power Prices 25% Higher Than Base Case
(Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 115.3 111.3 (4.0) -2%
2007 117.8 113.3 (4.6) -2%
2008 124.7 117.7 (7.0) -3%
2009 126.6 120.8 (5.7) -3%
2010 136.7 132.3 (4.4) -2%
2011 141.0 137.3 (3.7) -2%
2012 145.2 142.7 (2.5) -1%
2013 131.3 136.8 5.5 2%
2014 132.2 141.0 8.8 4%
2015 142.3 146.3 4.0 2%
2016 145.5 150.0 4.5 2%
2017 151.4 158.0 6.6 2%
2018 160.3 170.5 10.1 3%
2019 168.8 181.7 12.9 4%
2020 180.9 188.0 7.1 2%
2021 183.5 189.5 6.0 2%
2022 187.5 193.9 6.4 2%
2023 187.2 195.8 8.6 3%
2024 197.1 208.3 11.2 3%
Total 2,875.4 2,935.3 59.9 1%
62
Scenario 4: CRS Is Reduced By 50% From Base Case (Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 95.0 104.1 9.1 5%
2007 96.2 105.9 9.7 5%
2008 103.0 109.9 6.9 3%
2009 102.5 112.6 10.2 5%
2010 109.9 118.5 8.6 4%
2011 113.9 122.3 8.5 4%
2012 117.2 126.5 9.3 4%
2013 110.3 119.8 9.5 4%
2014 113.2 123.3 10.1 4%
2015 121.3 127.7 6.4 3%
2016 123.9 130.9 7.0 3%
2017 128.7 137.6 8.9 4%
2018 135.9 147.8 11.9 4%
2019 142.7 157.1 14.4 5%
2020 152.4 162.4 10.0 3%
2021 154.6 163.8 9.2 3%
2022 158.0 167.5 9.6 3%
2023 160.2 171.8 11.7 4%
2024 168.2 182.2 14.0 4%
Total 2,407.0 2,591.9 184.9 4%
63
Scenario 5: CRS Is Increased By 50% From Base Case (Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 120.0 110.4 (9.6) -5%
2007 119.8 112.2 (7.6) -4%
2008 129.2 116.4 (12.9) -6%
2009 119.3 119.2 (0.1) 0%
2010 126.1 125.1 (1.0) 0%
2011 129.8 129.0 (0.7) 0%
2012 133.6 133.4 (0.2) 0%
2013 120.4 126.8 6.4 3%
2014 120.7 130.4 9.7 4%
2015 128.9 134.9 6.0 2%
2016 131.5 138.1 6.6 3%
2017 136.4 144.9 8.5 3%
2018 143.7 155.2 11.5 4%
2019 150.7 164.7 14.0 5%
2020 160.5 170.1 9.5 3%
2021 162.8 171.6 8.8 3%
2022 165.9 175.4 9.6 3%
2023 160.2 171.8 11.7 4%
2024 168.2 182.2 14.0 4%
Total 2,627.6 2,711.7 84.1 2%
64
Scenario 6: PG&E Generation Rates Increase At An Annual Rate Of 1%
(Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 107.5 107.6 0.1 0%
2007 108.0 110.2 2.2 1%
2008 117.1 112.9 (4.1) -2%
2009 110.9 115.7 4.8 2%
2010 117.7 118.5 0.9 0%
2011 121.8 121.4 (0.4) 0%
2012 125.4 124.4 (0.9) 0%
2013 114.0 127.5 13.5 6%
2014 116.9 130.6 13.6 6%
2015 125.1 133.8 8.7 4%
2016 127.7 137.1 9.3 4%
2017 132.6 140.4 7.9 3%
2018 139.8 143.9 4.1 2%
2019 146.6 147.4 0.8 0%
2020 156.4 151.0 (5.4) -2%
2021 158.6 154.8 (3.9) -1%
2022 161.9 158.6 (3.3) -1%
2023 160.1 154.4 (5.7) -2%
2024 168.1 158.3 (9.8) -3%
Total 2,516.1 2,548.4 32.3 1%
65
Scenario 7: PG&E Generation Rates Increase At An Annual Rate Of 3%
(Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 107.5 111.6 4.1 2%
2007 108.1 116.5 8.5 4%
2008 115.1 121.6 6.6 3%
2009 110.9 126.9 16.0 8%
2010 117.7 132.5 14.8 7%
2011 121.9 138.3 16.4 7%
2012 125.4 144.4 18.9 8%
2013 114.1 150.7 36.6 16%
2014 117.1 157.3 40.3 17%
2015 125.3 164.3 39.0 16%
2016 127.9 171.5 43.6 18%
2017 132.7 179.1 46.3 18%
2018 140.0 187.0 47.0 17%
2019 146.8 195.2 48.4 17%
2020 156.6 203.9 47.2 16%
2021 158.8 212.9 54.0 18%
2022 162.1 222.3 60.2 20%
2023 160.4 224.1 63.8 20%
2024 168.4 234.3 65.9 20%
Total 2,516.8 3,194.5 677.7 14%
66
Scenario 8: PG&E’s Proposed Revenue Allocation To Customer Groups In Its
2003 General Rate Case (Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 107.5 107.0 (0.5) 0%
2007 108.0 108.8 0.8 0%
2008 117.2 112.9 (4.3) -2%
2009 110.9 115.6 4.8 2%
2010 117.7 121.5 3.9 2%
2011 121.8 125.4 3.6 2%
2012 125.4 129.6 4.3 2%
2013 114.0 123.0 9.0 4%
2014 116.9 126.6 9.6 4%
2015 125.1 131.0 5.9 2%
2016 127.7 134.2 6.5 3%
2017 132.6 140.9 8.4 3%
2018 139.8 151.2 11.4 4%
2019 146.7 160.5 13.8 5%
2020 156.5 165.8 9.4 3%
2021 158.7 167.3 8.6 3%
2022 161.9 171.1 9.2 3%
2023 160.2 171.4 11.3 4%
2024 168.2 181.8 13.6 4%
Total 2,516.7 2,645.8 129.1 3%
67
7 EVALUATION OF COSTS AND BENEFITS
This section summarizes NCI’s evaluation of the costs and benefits of
implementing a CCA program in the County. Evaluation criteria are the ability
to deliver lower rates, stable prices, and allowance for increased utilization of
renewable energy.
7.1 Ability To Deliver Lower Rates
The economic analysis demonstrates that it is feasible for the County to
implement a CCA program. Customers would be able to obtain electric service
at rates below those charged by PG&E. Under the most likely scenario, expected
savings average 3% of total electric bills over the study period.
Based on the year-by-year financial projections, NCI concludes that electric bill
savings opportunities would initially be modest and would increase over time.
Savings would be dependent upon utilization of municipal debt financing of
generation projects or long-term power purchases. The cost savings may be
sufficient in and of themselves to justify the decision to pursue CCA. The
estimated cost savings also help support and justify the decision to pursue CCA
to achieve other benefits, such as rate stability, local control, and increased
opportunities for renewable energy development.
7.2 Rate Stability
The Aggregator could structure its portfolio to emphasize cost predictability and
provide stable prices to CCA customers. Long-term supply contracts at fixed
prices can provide predictable costs for terms of ten years or longer. Investments
in renewable resources, such as wind resources, solar, biomass and geothermal,
eliminate the dependence on natural gas and the exposure to fluctuations in
natural gas prices for that element of the supply portfolio.
The sensitivity analysis shows an expected range of program savings of between
1% and 14% over the study period. The Aggregator’s portfolio would
demonstrate relatively stable prices to consumers. Under the base case scenario,
which reflects very conservative assumptions regarding future increases in
PG&E’s rates, the CCA program costs are expected to show 17% greater stability
than PG&E’s rates.
7.3 Increased Utilization Of Renewable Energy
The Aggregator would determine how much renewable energy to include in its
portfolio, over and above the minimum percentages required pursuant to the
68
California RPS. The cost of purchasing renewable energy is greater than the
costs of purchasing electricity produced from fossil fuels, so exceeding the RPS
via power purchases will increase the average cost of the Aggregator’s portfolio
to some degree. However, the analysis shows that doubling the RPS would have
only a modest overall impact on customer bills, as discussed below.
7.3.1 Cost Of Renewable Energy
The CEC’s Renewable Resources Development Report (RRDR) published in
November 2003 shows the mix and costs of the renewable resources that will
likely be utilized to meet the California RPS. The cost of buying renewable
energy can be estimated by creating a generic portfolio of these resources using
the contributions for each type projected in the RRDR study to calculate a
weighted average cost. The average cost of these resources, weighted by their
expected contribution to the RPS, is shown below:
Renewable Resource Technologies Expected To Fulfill The California
Renewable Portfolio Standard (2003 Dollars)
Source: CEC Renewable Development Resource Report
Resource Portfolio
Contribution
2005 Levelized
Production Cost
($/MWh)
Wind (Class 4 site) 66% 60 *
Concentrating Solar 1% 121
Landfill Gas 4% 44
Solid Biomass (Direct
Combustion)
4% 66
Geothermal (Binary) 25% 55
Weighted Average 59
* The cost of wind is based on the levelized cost of $49 per MWh presented in the RRDR plus an
additional $11 per MWh capacity cost to reflect that capacity must be acquired separately because
of the intermittency of wind resources. These figures do not include production tax credits,
which many people believe will be reinstated once Congress passes a comprehensive energy bill.
Escalating the cost to 2006 by assuming 2.5% annual inflation yields a 2006
average renewable cost of $62 per MWh. This represents a premium of
approximately $18 per MWh above the projected market prices of system power
in 2006.
All else being equal and assuming no Aggregator capital financing of renewable
energy, the cost of doubling PG&E’s 14% renewable mix would be $18/MWh *
69
0.14 = $2.52 per MWh. A typical household would pay $1.26 more per month to
double the amount of renewable energy used to supply its electricity
consumption.12 The premium declines over time as natural gas and electricity
market prices are expected to rise faster than the cost of renewable energy
production. For instance, assuming average annual increases in the market price
of system power of 2.8% used in this study, the renewable price premium falls to
$4 per MWh by 2014. By 2018, the market price of renewable energy is expected
to be no greater than the cost of conventional generation resources.13
The projected costs of renewable and conventional electricity are shown in the
following chart:
Northern California Market Price Projections For Renewable And
Conventional Electricity
-
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
2005200720092011201320152017201920212023Dollars Per MWhRenewable Energy
System Power
7.3.2 Municipal Financing of Renewable Energy Development
As described in this feasibility study, the Aggregator can reduce the cost of
acquiring renewable energy by financing development of renewable resources
used to supply its CCA program. The following table compares the total cost of
a hypothetical 100 MW wind energy project utilizing the financing structures
typical of an investor owned utility vs. those available to the Aggregator. The
12 Typical residential consumption is approximately 500 kWh or 0.5 MWh per month.
13 The cost of transmission investments that may be needed to bring large amounts of renewable energy to
load centers is not included in this analysis. These costs will be included in transmission rates that are paid
by all users of the grid and should not impact the CCA economic analysis.
70
underlying assumptions are that the utility’s capital structure is comprised of
50% debt and 50% equity at an overall cost of capital of 9%, while the Aggregator
employs 100% debt financing at a rate of 5.5%. The utility is subject to federal
and state income taxes of 40.75% so that the tax-effected cost of capital is 12.9%.
The Aggregator makes no return, has no income tax obligation and establishes its
revenue requirement based on the cash requirements needed to cover expenses
and debt service.
Cost Comparison – IOU Vs. Aggregator Ownership of Wind Resource
(Thousand of Dollars)
Cost Element Investor Owned
Utility
Aggregator
Capital Cost ($000) 15,951 7,730
Operations & Maintenance
($000)
2,198 2,198
Firming Capacity ($000) 3,022 3,022
Total First Year Cost ($000) 21,171 12,950
Cost Per MWh ($/MWh) 77 47
During the first year of operation, the Aggregator can produce energy at a cost
that is nearly 40% lower than what the investor owned utility would incur if it
owned the identical resource. The Aggregator’s cost of producing renewable
energy would be nearly the same as the market price of system power.
7.3.3 Operational Issues For Renewable Energy
Renewable resources are generally non-dispatchable, operating as either
baseload resources or on an as-available basis. Wind and solar resources
produce electricity only during certain times of the day when there is sufficient
wind or sun. These characteristics place an operational limit on the amount of
renewable energy that can be included in the overall resource mix. Depending
on a community’s load duration curve, which defines its base load requirements,
the operational limit could range between 50% and 70%.14 It would be possible
to exceed these amounts by over-procuring, but doing so would require the
Aggregator to sell excess energy into the market during many hours of the year,
thereby taking on additional risks associated with wholesale sales of energy.
14 This refers only to the County’s program operations and is not intended to imply that the entire system
could efficiently integrate such large amounts of renewable energy.
71
A similar issue exists with reliance on intermittent wind production. If an
Aggregator with an average load requirement of 200 MW established a 50%
renewable target, it would need approximately 300 MW of wind capacity. With
a typical capacity factor of 32%, production from 300 MW of wind capacity
would average the 100 MW needed to meet the target. However, at any moment
in time, the Aggregator could have between 0 and 300 MW of production. The
Aggregator would either need to purchase 200 MW of replacement energy or it
would have 100 MW excess energy to sell. These imbalances impose financial
risk on the Aggregator as the prices at which it must buy and sell energy may not
be identical.
One way that the CCA could safely exceed the operational limits on renewable
energy is by purchasing renewable energy certificates (RECs) from producers of
renewable energy. The CEC is currently investigating a system that would
facilitate trading of RECs, and private markets for RECs have been in existence
for several years. The tradable REC concept allows the renewable attribute
associated with renewable energy production to be sold separately from the
electrical energy. Through appropriate tracking and verification, the buyer can
be assured that for each REC purchased a kWh of renewable energy was
produced during the year; however, the renewable production need not match
the buyer’s load requirements on an hour-by-hour basis. By separating the
renewable attribute from the electrical energy, a CCA could ensure that enough
renewable energy was produced over the course of the year to supply 100% of its
customers’ load requirements, while avoiding the need to sell excess energy. The
price of the REC should be approximately equal to the cost difference between
the market price for system power and the cost of renewable energy production,
after considering all available incentives.
72
8 REGIONAL COMMUNITY CHOICE AGGREGATION PROGRAM
OPERATED UNDER A JOINT POWERS AGENCY
8.1.1 Economies Of Scale From Combined CCA Operations
By combining the electric loads of multiple cities and/or counties for CCA
operations, scale economies can be achieved that increase the benefits available
to the individual members. Operational cost saving can be captured through
common program administration and energy procurement activities. Diversity
among community load shapes enables the sharing of capacity reserves,
lowering overall procurement costs. The flatter load shape of a combined CCA
program reduces the costs of serving the load, thereby increasing the benefits
available to each of the participating communities.
NCI performed a financial assessment of combining the seven Bay Area
communities participating in the CCA demonstration project for purposes of a
common CCA operation. The Bay Area participants are listed below along with
the shares of 2006 electricity sales.
Bay Area Participants In The CCA Demonstration Project
2006 Electricity Sales
Pleasanton
11%
Berkeley
9%
Richmond
10%
Vallejo
8%
Emeryville
4%
Oakland
34%
Marin
24%
73
Annual financial results of a joint program are shown below.
Bay Area CCA Program Financial Summary (Millions of Dollars)
Year Total CCA Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - 0.0 0%
2006 432.0 457.8 25.8 3%
2007 434.0 465.8 31.8 4%
2008 462.3 483.3 21.0 3%
2009 444.5 495.3 50.8 6%
2010 476.1 520.8 44.7 5%
2011 490.7 537.5 46.8 5%
2012 503.7 555.9 52.1 6%
2013 460.5 527.6 67.0 7%
2014 473.6 543.0 69.4 7%
2015 504.6 562.3 57.7 6%
2016 516.8 576.2 59.4 6%
2017 534.1 605.3 71.2 7%
2018 560.1 649.6 89.6 8%
2019 585.5 690.2 104.7 9%
2020 628.5 713.3 84.8 7%
2021 639.5 719.8 80.3 7%
2022 653.5 736.4 82.9 7%
2023 644.2 739.5 95.4 7%
2024 674.0 784.5 110.5 8%
Total 10,118.3 11,364.2 1,246.0 6%
A combined operation would yield over $300 million in additional financial
benefits during the study period compared to the benefits achievable through
individual CCA operations. This represents a 34% improvement in financial
benefits from joint operation.
8.1.2 Joint Powers Agency Structure Option
Joint Power Agencies (JPA) are common legal structures that many public
agencies have formed and used to offer services in a more economical and
efficient manner. CCA JPA formation can combine city and county jurisdictions
to secure long-term power contracts or development its own generation
resources. Multiple member CCA JPAs may benefit from flatter electric load
74
shapes, reducing the overall cost to serve. There are numerous operating
examples of jurisdictions forming JPAs to procure electric energy in wholesale
markets for delivery to member constituent retail markets. The following
describes some of the benefits and impediments of the CCA JPA structure
option:
Summary of Benefits
¾ The JPA structure enables its party agencies to jointly exercise any power
common to them. CCA enabling legislation cites eligible jurisdictions as
cities, counties or JPAs comprised of cities and counties.
¾ The CCA JPA will be a non-profit agency and its motives are not profit
driven.
¾ Parties to the JPA would share cost/risk and assist with any JPA project.
¾ JPA formation can combine its members in securing long-term power
contracts or entering into agreements with agencies in the development of
generation resources.
¾ JPA members could benefit from economies of scale associated with
building a large project with its greater plant efficiencies and lower unit
costs.
¾ The JPA may authorize the issuance of low cost bonds by ordinance
subject to referendum but without a vote of the electros within the public
entities comprising the JPA
¾ A JPA provides a organizational, legal and financial structure to integrate
its parties and facilitate the implementation and operation of projects (in
this case utilities)
¾ This structure minimizes direct exposure of the member jurisdictions and
at the same time provides a conduit to key capital, political, and
intellectual resources for the other JPA members.
¾ This structure could reduce or eliminate the need for redundant personnel
and systems to facilitate energy supply for the multiple member
jurisdictions.
¾ JPA Operational Business Plans could incorporate phased customer
segment participation and provide flexibility to subcontract the
organizational depth needed during initial CCA operation.
75
Summary of Impediments
¾ Forming a JPA is time consuming; It is necessary to establish a working
group or advisory panel of all parties, and parties must agree on approach
and structure (the fewer the parties the more streamlined the process).
¾ The challenge for governance is to provide equitable representation for
both large and small members without compromising either’s options.
¾ The decision-making process can be cumbersome, during both formation
and operation (decisions tend to be “consensus” driven, slowing processes
and compromising positions - members seek to protect their own interest).
8.1.3 Purpose and Parties
A JPA is formed when it is to the advantage of two or more public entities with
common powers to consolidate their forces to acquire or construct a joint-use
facility or when local public entities wish to pool with other public entities to
save costs to acquire equipment or to acquire or construct facilities for their
individual use. A joint exercise of powers agreement must be approved by all
participating entities, and this may include the federal government or any federal
department or agency, this state, another state or any state department or
agency, a county, county board of supervisors, city public corporation, or public
district of this state or another state.
8.1.4 Authorization
A Joint Powers authority is empowered by Chapter 5, commencing with section
6500 of Division 7 of Title 1 of the Government Code, to issue bonds, notes,
Commercial paper, including certain kinds of variable rate securities for
specified purposes, and to enter into leases to acquire land and equipment or to
acquire or construct public facilities. The JPA entity is created when member
jurisdictions enter into a joint exercise of powers agreement, forming a joint
powers agency and by adopting identical concurrent, ordinances.
8.1.5 JPA Governance
A commission responsible for administering the CCA JPA would be established
comprised of representatives from each party to the CCA JPA Joint Powers
Agreement. A quorum of the CCA JPA Commission (Commission) would
consist of those Commissioners, or their designated alternatives, representing a
76
numerical majority of the Parties. Voting on JPA actions could be facilitated
wherein each Party would have the right to cast one vote. In the alternative,
voting may be conducted where each party has a number of votes equal to its
percentage share of CCA JPA expenses. Such procedures would be developed
by a working group or advisory panel of all parties as referenced above.
In addition to voting representation on the Commission, flexibility for Parties to
take actions alone or in concert other selected JPA members, and thereby ensure
members can protect and pursue individual interests, can be facilitated through
the development and use of a hierarchy of structured agreements. In the example
below, precedence of agreements can be established where, for example, a
Project or Operating Agreement takes precedence over a Facilities Agreement. In
this case action can be taken by JPA members without executing a higher-level
membership-wide agreement. In this way specific operational arrangements
between a limited numbers of Parties take “precedence” over higher-level
membership-wide agreements. The names and use of agreement structures
would be adjusted to more closely reflect CCA JPA activities. The following is an
example of hierarchical of JPA Agreements used by the Northern California
Power Agency:
Agreement Hierarchy:
1. Joint Powers Agreement
2. Pooling Agreement
3. Facilities Agreement
4. Project Agreement
5. Operating Agreement
Joint Powers Agreement: Through the Joint powers Agreement a CCA
might be established as a public agency pursuant to the Joint Exercise of
Powers Act of the Government Code of the State of California authorized
to acquire, construct, finance and operate buildings, works, facilities and
improvements for the generation of electric capacity and energy for resale.
Each of the Parties to the Agreement would be a city or a county
jurisdiction authorized to implement a CCA pursuant as defined in
enabling legislation AB 117 (Migden – Chapter 838, Statutes of 2002).
Pooling Agreement: Each Party to the Pooling Agreement is a Party to the
CCA Joint Powers Agreement. The Pooling Agreement establishes
facilities, staff, and the capability for: Planning for the addition of facilities;
entering into long-tem and short-term, firm and non-firm interchange
transactions; dispatching and scheduling all available resources to meet
the combined loads of the Parties.
77
Facilities Agreement: A Participant in an CCA Facilities Agreement is an
CCA JPA member and a signatory to the CCA Joint Powers Agreement
(JPA). The Facilities Agreement provides a framework for membership
joint design, construction and operation of power supply facilities.
Project Agreement: Establishes the framework for the development,
design, financing, construction and operation of specific projects.
Operating Agreement: Detailed descriptions, principles and procedures
(including operating and cost recovery) for CCA JPA projects.
8.1.6 Revenue Bond Issuance
The JPA may authorize the issuance of revenue bonds by ordinance subject to
referendum but without a vote of the electors within the public entities
comprising the JPA. However, JPAs may also issue securities pursuant to a
resolution of the authority backed by loan agreements and/or bond purchase
agreement with participating member agencies. The law provides that some but
not all of the members of a JPA may participate in a bond issue and that only
those participating will be obligated to repay the debt incurred.
Below we list a number of financing alternatives to consider once a JPA has been
formed.
78
Figure 12
Comparative Features of Alternative Financing Methods
Financing
Method/Characteristics
General
Obligation
Bonds
Limited
Obligations
Bonds
Special
Assessment
Certificates
of
Participation
Revenue Bonds
Project Financeable
Acquisition &
improvements
of land and
buildings
Acquisition &
improvements of
land and
buildings
Facilities of local
benefit to
property
Unrestricted Revenue producing
facilities
Authorization
Issuer’s
governing board
& public election
(2/3 vote)
Resolution of
issue governing
board and 2/3
vote
Resolution of
issuer, petition of
beneficiaries
Resolution of
issuer
governing
board
Resolution of issuer
governing board
Area of Authorization
Jurisdiction
Boundary of
issuer facilities
district (flexible)
Boundary of
issuer facilities
district (flexible)
Flexible N/A Service area of issuer
Hearing Procedure
None None Majority protest
hearing
Maybe
ordinance
adoption
None
Validation None None None None None
Nature of debt service
payments
Unlimited ad
valorem tax
Portion of
current revenues
Annual
assessments
based on benefits
received;
property taxes
may not be used
Rental or
installment
payments
Service charges and
fees from users
Source of debt service
payment
Property owners
in issuer
jurisdiction
General
revenues of
issuer
Annual property
assessments
General
&/or
enterprise
revenues of
issuer
Service charge and fee
collections
Security
Full faith and
credit
Revenue
collections and
coverage test
Tax collections/
Foreclosure
Lease or
installment
sale contract
Coverage test and
contracts
Lessor/Lessee Required No No No Yes NO
Refundable Yes Yes Yes Yes Yes
Debt Service Funds
subject to Gann Limit
No No No Yes Yes
Structural Features
Reserve Fund No Yes Yes Yes Yes
Capitalized Interest
No No Yes Yes New enterprise only
Debt Service Coverage
NO Yes Value/lien ratio
3:1
No Yes
Method of Sale
Competitive or
Negotiated
Competitive or
Negotiated
Competitive or
Negotiated
Competitive
or
Negotiated
Competitive or
Negotiated
Advantages
Lower interest
rate
No pledge of
General Fund
Isolates projects No voter
approval
Higher interest rate
Disadvantages
Voter approval
required
Voter approval Limited security
Higher interest
rates
Highly
structured
Limited
flexibility
Debt Service Reserve
Fund
79
The overview above provides a broad perspective on the various financing
techniques that will be available to a CCA JPA. However, the ultimate method
that the CCA JPA chooses will based on a number of factors:
Purposes of Financing: Proceeds of the financing can be used for a number of
different uses including but not limited to: Start-up costs, construction of new
plant and equipment, initial capital for power purchases, Operations and
maintenance expenses among others. As outlined above, the purpose of the
financing can and will affect the type of bond issue that the CCA JPA can utilize
to finance its various costs. In the end the JPA may execute a series of different
products to meet each of its various purposes.
Tax Eligibility: An important consideration in determining the appropriate
technique will depend largely on the tax-exempt eligibility of the potential
financing. As all the objectives (i.e. purposes and uses of the proceeds) of the
specific financing become known, NCI along with counsel for the JPA will have a
better sense as to whether the JPA will be eligible to issue tax-exempt bonds. We
will obviously attempt to create a structure that maximizes the use of tax-exempt
bonds which will ultimately provides the lowest cost of financing to the JPA.
80
9 CONCLUSIONS AND RECOMMENDATIONS
9.1 Conclusions
There are three general criteria, as described under Section 5, for assessing
benefits of CCA. These are the potential for reduced rates, the ability to increase
utilization of renewable energy, and enhanced local control/rate stability. This
analysis shows it is possible to achieve each of the three objectives by forming a
CCA program, under the most likely scenarios. Formation of a CCA program
offers benefits but is not entirely without risks, both financial and political. The
County should clearly define its reasons for pursuing CCA so that program
implementation reflects and fulfills clearly defined objectives. These reasons
could include one or more of the following goals:
- Proactively address energy and infrastructure issues in the community
- Expand use of renewable energy resources and increase energy efficiency
(e.g., reduce greenhouse gas emissions, reduce dependence on fossil fuels
and imported natural gas)
- Reduce energy costs or enhance general fund revenue
- Provide for electric rate stability and local control
- Provide other utility services, such as energy efficiency and distributed
generation
- Increase the tools available for economic development and planning
- Position County for provision of expanded electricity service offerings in
the future
Ultimately, a primary benefit of CCA is giving consumers greater control over
their energy choices and devolving responsibility for energy planning to the local
level. The County should take a long-term view in considering the decision to
form a CCA program and be prepared to weather challenges that may arise in
the short-term. Participation in a regional CCA program via formation of a joint
powers agency would offer benefits of scale that would not be available under a
standalone program. The County should explore opportunities for joining with
other local governments in the region to form a regional CCA program if the
County decides to move forward with implementation.
Lower Rates
The analysis indicates the County is likely to obtain cost savings equal to over
$6.8 million per year or approximately 3% of customers’ electricity bills on
average over the study period. These cost savings could be used to reduce rates
and/or to create a new revenue stream for the general fund. The scenario
analysis shows that savings are not dependent upon the specific financial
81
assumptions underlying the base case. The average program savings range from
a low of 1% to a high of 14% across the eight scenarios evaluated to test the
sensitivity of these results to changes in wholesale energy market conditions,
PG&E rate projections, and cost responsibility surcharges. A conservative
interpretation of these findings suggest that over the next several years there
would be moderate cost benefits from implementing a CCA program, primarily
due to the imposition of cost responsibility surcharges on CCA customers. Cost
benefits will be more significant over the longer term as the CRS begins to
decline and eventually expires.
Increased Renewable Energy
The analysis shows that a 51% renewable energy target can be achieved with no
rate increases for customers if the Aggregator is willing to finance renewable
resource development to supply the CCA program. The cost effectiveness of
increasing renewable energy utilization to this degree is greatly enhanced by the
involvement of the public sector through CCA because of the public sector’s
access to low cost capital and the contract coverage afforded by the CCA’s large
customer base. A primary benefit of forming a CCA program is to create the
ability to increase utilization of renewable energy. The realistic implementation
approach used in this feasibility analysis incorporates a hybrid supply strategy
and gradual ramp-up of renewable energy utilization, initially utilizing contracts
with third parties to match the PG&E renewable energy mix and eventually
progressing to municipal ownership/financing of generation.
Local control/rate stability
Ultimately the long-term benefits of a CCA program in the community resolve
around local control. Such control includes the ability for the County and aligned
agencies to effect resource planning and infrastructure investment in an
integrated fashion responsive to the community’s needs and values. Local
control also manifests in avoiding the cost consequences of the utility’s long-term
procurement decisions, which must be made considering the competing interests
of shareholders, regulators, and consumers. The County faces no such conflicts
and can focus on its primary mission of representing the interests of consumers.
9.2 Recommendations
1. Communicate final study results through community workshops and
identify next steps in proceeding toward Implementation Plan filing.
82
2. Consider whether natural alliances exist among neighboring communities,
and explore partnering arrangements to optimize supply side alternatives
and regional CCA implementation.
3. Make decision whether to proceed with development of an
Implementation Plan.
83
84
APPENDICES
85
Appendix A – Resource Portfolio Planning Template
Fifth Supply Scenario Variables
1. Renewable Energy (RE) Targets
a. End-State Percentage (20-100% by 2017) ________
b. RE Ramp Rate 2006 – 2023, Cite Yearly Targets
1) 2006 min. 14%
2) 2017 min. 20%
c. RE Equity Position
1) Physical Resource Entitlement (ownership/investment)
a) Yes __ No __
b) Percentage of Total RE __
c) In-Service Dates and Capacities (MW)
2) Market Purchases
a) Percentage of Total RE __
b) Contract Schedule and Capacities (MW)
2. Conventional Generation Resource Equity Position
a. Physical Resource Entitlement (ownership/investment)
1) Yes __ No __
2) In-Service Dates and Capacities (MW)
b. Market Purchases - Contract Schedule and Capacities (MW)
3. Distributed Generation
a. Capacity (kW)
1) Existing
a) Technology (PV/micro-turbine/etc)
b) Capacity (kW)
c) Energy (kWh)
d) Cost
e) In-Service Dates
2) Planned
a) Technology (PV/micro-turbine/etc)
b) Capacity (kW)
c) Energy (kWh)
d) Cost
e) In-Service Dates
4. Spot Market Purchases (assumed minimized – under 20% energy unless
instructed otherwise)
5. Based Upon the 5th or “Preferred” Supply Portfolio Sensitivities Will be
Assessed for the Following Variables:
a. Natural gas/power prices (+/- 25%)
b. Cost responsibility surcharge (+/- 25%)
86
c. IOU rate projections (+/- 5%)
d. IOU rate design (GRC proposals)
e. Renewable subsidies (SEP, PTC)
f. Combined operation with other Project participants
87
Appendix B – Detailed Assumptions
Key Assumptions Used In CCA Feasibility Analysis and Modeling - Pacific Gas
& Electric Territory
1) Metering and Billing
a) No new metering requirements for CCA customers.
b) Billing charges same as direct access from Schedules E-ESP and E-EUS.
c) Billing charges based on Rate-Ready Billing Option from Schedule E-ESP.
2) Financing
a) Tax exempt financing for startup costs and any new generation
development @ 5.5%.
b) 100% debt financing.
c) Financing term is 30 years.
d) Minimum debt coverage ratio of 1.25.
e) Bond insurance cost of 1.6% of par value.
f) Bond transaction cost of 1% of par value.
g) Debt reserve of 10% of par value.
3) Startup and Operations Costs
a) Startup costs include regulatory and legal @ $350,000.
b) Operational costs are outsourced @ $2.50 per MWh unless and until CCA
reaches approximately 1.5 million MWh in sales.
c) If performed internally, the cost is estimated at $3.9 M per year plus 10
cents per MWh, including IT.
d) Activities include scheduling coordination, procurement/planning, risk
management, credit, rates and load research, A&G, and IT.
e) The CCA will begin serving customers in January 2006
4) Resource Adequacy
a) CCAs subject to same resource adequacy requirement as IOUs, per D.04-
01-050.
b) Planning reserves are required to bring total reserves, including ISO
required ancillary services, up to 15% of peak load.
c) Costs of meeting planning reserves equal to market value of capacity.
88
d) Spot market purchases limited to between 5% and 20% of CCA portfolio;
the remainder of the portfolio is comprised of long-term contracts and/or
resource ownership.
5) Renewable Energy Portfolio
a) Renewable purchases are from a generic portfolio comprised of Class 4
Wind, Binary Geothermal, Solid Fuel Biomass, Land Fill Gas Biomass, and
Concentrating Solar Power.
b) The cost and resource mix comprising the portfolio is derived from the
CEC's Renewable Resources Development Report (11/7/03) See RRDR,
Table 4, page 37 and discussion at page 87. 2005 costs are escalated at a
nominal rate of 1% per year.
c) The cost of the generic renewables portfolio equals the estimated
developers' costs, including return on investment. Market price of
renewable energy equal to maximum of cost or market price of system
energy
d) The cost of wind energy assumes no extension of the production tax
credit.
e) Wind energy must be firmed via capacity contracts due to its intermittent
nature. The cost of wind energy is adjusted for a capacity adder to firm
the intermittent resource, at market value of capacity.
f) Renewable ownership costs are derived by applying municipal financing
assumptions to the cost data in RRDR Appendix D, page D-6. 2005 costs
are escalated at a nominal rate of 1% per year.
g) Ownership cost incorporate technology specific assumptions regarding
installed capital costs, fixed operations and maintenance, capacity factor,
fuel cost, and capacity cost adder applied to intermittent resources.
h) The ownership costs of intermittent resources also includes a risk factor of
$5 per MWh related to the potential differences between energy prices for
sales from excess production versus purchases for production shortfalls.
i) CCAs will rely primarily on large-scale renewable projects to meet and
exceed the RPS. These are Wind, Geothermal, Solid Fuel Biomass, and
Concentrating Solar Power.
j) CCA owned generation resources can be online by 2008.
k) Distributed generation options, such as rooftop PV systems, are
incorporated in the feasibility analysis based on community specific
planning. Renewable DG production, if any, will be in addition to the
RPS minimums.
l) Supplemental energy payments are available to offset the incremental
costs of renewable contract purchases (10-Year Terms) up to the minimum
RPS requirement. PGC funds are sufficient to buy down 100% of the cost
premium of renewables.
89
m) Supplemental energy payments are not available for city-owned resources
and not available for purchases in excess of the RPS minimums.
n) CCAs are required to match the renewable energy percentage of the
respective investor owned utility in the first year of CCA operations.
o) IOU renewable baseline percentages are derived from RRDR Appendix A,
page A-2 and increased by 1% per year until 20% is achieved by 2017.
6) Wholesale Energy Markets
a) Electricity market price forecast based on projected market clearing
system heat rates and natural gas price projections.
b) Natural gas price projections prepared by NCI in January 2005.
c) Implied system clearing heat rates for 2005-2010 are 8,000, 8250, 8700,
9000, 10,000, 10,500. Market equilibrium assumed at implied system heat
rate of 11,000 after 2010.
d) On-peak energy priced at 15% premium; off-peak energy priced at 15%
discount; real time energy at 10% premium.
e) Long term contracts priced at 5% premium to expected spot market prices.
f) Capacity costs valued at $100,000 per MW-Year, escalated at 2.5%
annually; costs are embedded in energy prices derived as above.
g) Ancillary services and related costs estimated based on historical
relationship to market prices, projected forward.
h) Ancillary services requirements based on percentage of CCA's load per
current CAISO practice.
i) Ancillary services types are Regulation, Spinning Reserve, Non-Spinning
Reserve, Replacement Reserve.
j) California Independent System Operator (CAISO) administrative and
neutrality charges are derived from current rates, escalated at 2.5%
annually.
k) CAISO charges are Grid Management Charge - Control Area Service, Grid
Management Charge - Inter-zonal Scheduling, Grid Management Charge -
Ancillary Services and Real Time Operations, Unaccounted For Energy
Charge, Neutrality Charge, Congestion Charge, De
l) No explicit modeling of impact from move to locational marginal pricing;
assumed that loads will be protected from congestion costs by allocation
of congestion revenue rights and zonal averaging of prices.
m) Distribution losses are 7%.
7) Generation Cost
a) CCA's choosing to own generation will acquire equity interests in
combined cycle gas turbine facilities based on the following cost and
operating parameters:
b) Installed cost of $700 per KW.
90
c) Heat rate of 7,000 mmbtu/MWh.
d) $3 per MWh fixed and variable O&M
e) 0.1 pounds per MWh emissions..
f) $10 per pound cost of NOx emissions.
g) 90% planned capacity factor.
h) 2% forced outage rate.
i) Excess sales sold at prevailing market clearing prices.
8) Cost Responsibility Surcharges
a) Cost responsibility surcharges calculated annually using total portfolio
indifference method adopted in direct access proceeding (includes old and
new resources) (R.02-01-011) and CCA Rulemaking (D.04-12-046)
b) CRS reduced by pro rata share of cost of ancillary services and planning
reserves
c) No cap on cost responsibility surcharge for CCAs.
d) Cost responsibility surcharge includes DWR bonds, DWR power charge,
utility CTC, and Regulatory Asset.
e) Uniform "indifference fee" per KWh for all CCA customers, regardless of
rate class and CCA startup date. No baseline credits reflecting AB1X
protections for residential consumption up to 130% of baseline allocation.
f) Uniform DWR bond charge per KWh, statewide.
g) CTC rate varies by customer class based on current tariffs.
h) DWR bond charge projections based on currently applicable rate as of
January 2005.
i) No transfer to CCA of DWR contracts, renewable energy, or capacity
contracts implied by payment of cost responsibility surcharges.
9) IOU Rate Projections
a) IOU rates for generation are the competitive reference point for assessing
CCA cost savings potential.
b) Current IOU rate schedules (Advice Letter 2570-E-A) as of January 2005
applied to CCA customer billing determinants (estimated), aggregated by
major rate group.
c) Generation rates and total rates (generation plus non-generation)
projected forward based on percentage changes in IOU system average
rates.
d) IOU generation costs projected based on current resource mix, adjusted
over time for planned generation retirements, DWR contracts, QF
contracts, and renewable energy contracts to meet RPS.
91
e) PG&E owned generation resources includes Nuclear (Diablo Canyon),
Hydro, and Fossil facilities. Production and sales data are from PG&E’s
Long Term Resource Plan.
f) Generation costs and beginning rate base for each generation type are
derived from 2003 General Rate Case filing.
g) Generation costs include operations and maintenance, return,
depreciation, uncollectibles, A&G, franchise fees, taxes other than income,
taxes based on income, fuel, thermal decommissioning, and other.
h) Future capital additions increased for Diablo Canyon turbine replacement
anticipated in the 2007 - 2009 timeframe.
i) Purchased Power includes QF contracts, existing bilateral contracts, DWR
contracts, new renewable contracts, new bilateral contracts, and spot
market purchases.
j) New bilateral contracts entered into as needed to maintain spot purchases
(residual net short) at or below 10% of IOU portfolio.
k) PG&E maintains planning reserves of 15% of annual peak load. Existing
ancillary services requirements are included in the 15% planning reserves
requirement.
l) Spot market purchases to meet the residual net short are priced at average
of NP15 peak (6 X 16) and base (7 X 24) power prices.
m) Majority of QFs (80%) paid according to settlement price through 2005,
and then based on annual short run avoided cost formula.
n) QF capacity payments derived from FERC Form 1 data.
o) QF capacity/energy projections derived from the Consultant's Report
supporting DWR bond financing.
p) RPS purchases from generic renewable portfolio as described above;
Supplemental Energy Payments fully offset incremental costs relative to
non-renewable energy.
q) DWR costs and volumes adjusted over time based on terms of the
individual contracts allocated to PG&E per D.02-09-053.
r) DWR "remittance rate" calculated using CPUC methodology (D. 04-12-
014).
s) Regulatory asset cost calculated based on terms of approved Bankruptcy
Settlement.
t) Cost offset for bundled customer generation costs from cost responsibility
surcharges paid by Direct Access Customers based on capped collection
rate from direct access proceeding (R.02-01-011)
u) Non-generation costs escalated at constant 1.5% per year. Non-generation
rates are only used to express the CCA cost impacts as percentage of
customers' total electric bills.
v) Same input assumptions as above for wholesale electricity prices, capacity
prices, natural gas prices, ancillary services costs, CAISO charges, RPS %
and prices, supplemental energy payments, and DWR bonds charges.
92
Appendix C – Sample Data Request Letter
[DATE]
Pacific Gas & Electric Company
Governmental Affairs
Attention: [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE]
77 Beale Street
San Francisco, CA 94105
SUBJECT: Information Request Per D.03-07-034
Dear [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE]:
The [CITY OR COUNTY] of [NAME] (CITY OR COUNTY) is currently reviewing its
options in becoming a Community Choice Aggregator (CCA) in accordance with AB
117, enacted in 2002, for: 1) administering energy efficiency programs; and 2) possibly
providing electrical energy as related to this legislation. On July 10, 2003, the California
Public Utilities Commission (CPUC) approved an “Interim Opinion Implementing
Provisions of Assembly Bill 117 Relating to Energy Efficiency Program Fund
Disbursements” (Decision 03-07-034). As part of this Decision, the CPUC directed
Pacific Gas & Electric Company (PG&E) to provide certain types of information to
cities, counties, and CCAs.
The [CITY OR COUNTY] respectfully requests the information listed below, as
enumerated in Attachment C of D.03-07-034 for all electric customers within the [CITY
OR COUNTY].
1. Energy consumption for each customer class for a given period of time and a given
city.
The [CITY OR COUNTY] requests the total number of customers and monthly
energy consumption in kWh for the following rate groups: residential (E-1 and all
93
other residential services), small commercial (A-1, A-6) medium commercial (A-
10), small industrial (E-19), large industrial (E-20), agricultural, and outdoor and
street lighting. Please provide the above information separately for customers
currently receiving bundled utility service from PG&E and customers currently
served under direct access arrangements with energy service providers.
2. System-wide residential and nonresidential load shapes and most recent hourly load
shapes for the climate band encompassing the [CITY OR COUNTY].
3. The proportional share in the potential CCA territory, as defined in the Commission’s
energy efficiency policy manual.
The [CITY OR COUNTY] understands that D.03-07-034 ordered that PG&E “shall
provide the information and data described in Attachment C to any city, county or CCA
that requests it, as set forth in this order without charge.” We also understand through
this Decision that this information “should be provided…within one week of the
request.”
Please send this information in electronic form via e-mail to [E-MAIL ADDRESS]. If
you have any questions regarding this request, please contact [NAME] at
[TELEPHONE]. The [CITY OR COUNTY OF NAME] appreciates your assistance.
Sincerely,
[NAME]
[TITLE]
[CITY OR COUNTY NAME]
94
Appendix D – CCA Functional Elements
The operations of a CCA program include all activities needed to procure
electricity for end-use customers, schedule delivery of the electricity, conduct
financial settlements for wholesale electricity purchases and sales, determine the
costs charged to individual customers, and interface with PG&E which would
provide billing, metering, and customer services to CCA customers. These
activities can be grouped into the broad categories described below.
1. Portfolio Operations
Portfolio operations encompass the activities necessary for wholesale
procurement of electricity to serve end-use customers. These activities are
virtually identical to the supply functions performed by local utilities, municipal
utilities, and energy service providers.
a. Electricity Procurement
The essential purpose of the Aggregator is to assemble a portfolio of electricity
supply sources on behalf of its customers. As an Aggregator, the County can
choose from various types of resources and wholesale electricity products to
achieve a supply portfolio that appropriately reflects the desired balance of cost
certainty, environmental considerations, cost effectiveness, and operational and
contractual flexibility.
A variety of generation resources or electricity purchase contracts can be
employed to provide for the time-varying load requirements of the CCA
program. The pattern of aggregate electricity usage typically follows daily,
weekly and seasonal cycles, peaking during the afternoon hours and the summer
months. The Aggregator must consider these load patterns when assembling a
supply portfolio to properly match resources to the aggregate load shape of its
customer base. Different types of generation resources and supply contracts
supply the base load requirements, intermediate resource needs, and peaking
load requirements. These concepts are illustrated in the following diagram.
95
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
300,000.0
kWThursdayTuesday SaturdayFriday
Base ȱLoadȱforȱGenerationȱResources
orȱ7ȱXȱ24ȱPowerȱProducts
PeakȱLoadȱorȱ
6ȱXȱ16ȱPowerȱ
Product
PeakȱLoadȱorȱ
6ȱXȱ16ȱPowerȱ
Product
SpotȱMarketȱPurchases
“Imbalances”ȱor
LoadȱFollowingȱProducts
SpotȱMarketȱPurchases
“Imbalances”ȱor
LoadȱFollowingȱProducts
A typical supply portfolio would utilize generation owned by the Aggregator or
long-term contracts for the majority of projected base load requirements. These
base load resources would be supplemented with intermediate resources or peak
products as well as short-term contracts covering the additional seasonal load
requirements of the portfolio, typically in the third quarter of each year. Spot
market purchases and sales are used to fill the residual “net short” load
requirements.
b. Risk And Credit Management
Risk management techniques would be employed to reduce the Aggregator’s
exposure to the volatility of energy markets and insulate customer rates from
sudden changes in wholesale market prices. Credit monitoring is also important
to keep abreast of changes in a supplier’s financial condition and credit rating.
Common practice in the energy industry is to periodically calculate the financial
exposure to a supplier by comparing the value of the supply contract to the
contractual price, utilizing so called “mark-to-market” valuation. Exposure to
suppliers is greatest when the contractual price is low relative to prevailing
market prices, and the risk of default becomes a concern. Collateral and other
security instruments, such as letters of credits or surety bonds, are commonly
used to manage credit risks between wholesale electricity buyers and sellers.
c. Load Forecasting
96
In performing the electricity procurement functions, it is necessary to 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.
The CCA will be required to purchase energy on the wholesale market for each
hour of the day. To support financial settlements and energy procurement, an
accurate record of total, time-of-day specific electricity demand and energy usage
is essential. Lacking this, the CCA operator is required to rely on the distribution
utility’s recorded usage for each individual customer. All customer classes are
not metered in the same way. In particular, residential and small commercial
consumers (electric demand less the 20 kW) typically have simple electro-
mechanical meters capable of metering only cumulative energy consumption.
Medium commercial customers (electric demand in the range of 20 to 500 kW)
are typically metered with energy and demand meters, but still lack time-of-day
recording. Large commercial and industrial customers (electric demand greater
than 500 kW) are typically equipped with data recording meters recording
electric demand on five, ten or fifteen minute intervals (interval data recording
meters or IDR).
Without a time-of-use record of energy consumed, the Aggregator will have to
rely on prototypical rateclass load profiles. The California Independent System
Operator (CAISO) allows use of load profiles that are approved by the local
regulatory agency (CPUC) for scheduling and settlement. These load profiles are
derived by distribution utility load research based on IDR metering of a stratified
random sample from each rateclass (residential, small commercial, medium
commercial, industrial). Hence, they represent the average or typical customer
and not the CCA’s actual customers. To date, the CPUC has approved the use of
rateclass load profiles for use by the utilities and energy service providers for
electricity scheduling and settlement. The local utilities have opposed proposals
made in R.03-10-003 that Aggregators be allowed to use area-specific load
profiles for these purposes.
CCAs have the option, under the law, to meter electricity supplied to the
jurisdictional territories comprising the CCA to obtain an accurate record of
aggregated loads. PG&E is required to “install, maintain and calibrate metering
devices at mutually agreeable locations within or adjacent to the CCA’s political
boundaries” at the request and at the expense of the CCA. PG&E will also be
required to “read the metering devices and provide the data collected to the CCA
at the aggregator’s expense.”15 Utilities are directed under CPUC Order
15 California Public Utilities Code §366.2(c)(18)
97
Instituting Rulemaking R.03.09.007 (August 21, 2003) to develop specific tariff
language to meet the requirements. Assessing the size, type, location, quantity
and installation cost of such CCA wholesale metering will require an analysis of
PG&E’s distribution system, in concert with utility Service Planners, and, will
require PG&E to comply with the CPUC’s Order to develop applicable tariff
terms and conditions. At this time, it is not clear to what extent the CPUC or the
CAISO would have to approve the Aggregator’s use of boundary meters for
electricity scheduling and settlement.
d. Scheduling Coordination
Scheduling coordination costs are the costs associated with scheduling and
settling electric supply transactions with the CAISO. All customer meters must
be represented by a CAISO-certified scheduling coordinator. The scheduling
coordinator submits schedules to the CAISO of hourly electric demands and
supply resources on behalf of the Aggregator. The scheduling coordinator is
responsible for costs associated with imbalances or deviations between the actual
hourly loads and the actual hourly production of the resources it represents. It is
also responsible for the costs of reserves and other services (“ancillary services”)
provided by the CAISO that are needed for reliable operation of the transmission
system.
The Aggregator has several choices for obtaining services of a scheduling
coordinator. Some companies act as independent scheduling coordinators and
charge service fees for their services. Other companies such as power marketers
or energy service providers will provide scheduling coordination services as part
of a larger package of energy services, including wholesale electricity supply,
load forecasting, and risk management. The charges for providing the
scheduling coordinator services are bundled into the overall cost of electricity
provided by the supplier. It is also possible for the Aggregator to become a
CAISO certified scheduling coordinator, which requires acquisition of
specialized software, completion of certification training conducted by the
CAISO, and continuous staffing of a scheduling desk for 24 x 7 operations.
2. Rates
The Aggregator is responsible for setting its charges for the generation services it
provides to CCA customers. The first step in setting rates is to determine the
total dollars that must be collected from customers in order to cover all of the
Aggregator’s costs of doing business. This amount is known as the revenue
requirement and consists of operating expenses, depreciation and amortization,
interest and financing expenses, taxes, and reserve funds.
98
The revenue requirement is allocated to the various classes of customers in the
CCA program, such as residential, small commercial, medium commercial, large
industrial, agricultural, and street lighting customers. Revenue allocation is
typically done on a cost of service basis, so that rates are reflective of differences
in the Aggregator’s costs of serving the different customer classes. The
Aggregator may employ load research to estimate customer class load profiles
and cost of service by use of sampling techniques, whereby load research meters
that can record customer electricity consumption on a 5 to 15 minute interval
basis are installed on a small sample of customers within each rate class.
Alternatively, the Aggregator may utilize the customer class load profiles created
by PG&E.
Rate design is the process of setting the specific charges applicable to customer
electricity usage. Rate schedules define the charges for each kWh, kW or other
unit of electric service, and there may be one or more rate schedules applicable to
each customer class. Rates are set so recover the Aggregator’s revenue
requirement on a forecast basis and are adjusted as needed to maintain sufficient
revenues for the Aggregator.
3. Account Services
The Aggregator must be able to exchange customer meter usage data
electronically with PG&E using the utility’s standard electronic data interchange
procedures and formats. The Aggregator must receive and process customer
payments collected by PG&E. Aggregators may also need the capability to
calculate individual customer bills and provide the amount to be collected to
PG&E in the formats and by the timelines required for inclusion in the bills sent
by the local utilities. PG&E is the only local utility that offers “rate ready” billing
service, whereby PG&E will calculate individual customer bills using the rates
provided by the Aggregator. PG&E also offers “bill ready” billing service
whereby the Aggregator calculates the amounts due from each customer and
submits to PG&E for collections. SCE and SDG&E only offer “bill ready” billing.
The Aggregator must also be able to obtain customer meter data and process the
data for submission to the CAISO through its scheduling coordinator so that the
CAISO can complete its financial settlement process. Customer meter data must
be processed in accordance with the CPUC’s protocols for verification,
estimation, and editing (VEE) of meter data. PG&E will perform the VEE
function for Aggregators as part of their metering service function. However, the
Aggregator must apply load profiles to the usage data of customers whose
consumption is measured on a cumulative monthly basis (e.g. residential and
small commercial) in order to create the hourly usage data that must be
submitted to the CAISO.
99
4. Administration
Administration and management of the CCA program includes finance, legal,
regulatory, contract management and other program management functions.
The scope of the administrative function depends on the complexity of the CCA
implementation, which can range from a single contract with an energy services
provider for operation of the program to the planning and staffing required for
in-house operation and management of all aspects of the CCA program, with
variations in between these two extremes. At a minimum, a senior level manager
with experience in the electric utility industry should head the CCA program.
100
Appendix E – Base Case Pro Forma And Supporting Data
COUNTY OF MARIN
SUMMARY OF PRO FORMA RESULTS ($ MILLIONS)
51% RENEWABLE ENERGY
Year Commodity Costs
Reserves and ISO
Charges
Operations &
Scheduling
Non-bypassable
Charges
Metering &
Billing Financing Costs Total Costs PG&E Charges Savings
Percentage Of
Total Bill
2005 - - - - - - - - 0.0 0%
2006 71.6 5.7 3.6 25.1 1.1 1.2 108.3 107.2 (1.0)-1%
2007 73.3 5.9 3.7 23.7 1.1 1.2 108.8 109.1 0.3 0%
2008 72.4 6.1 3.8 24.1 1.1 9.1 116.7 113.1 (3.5)-2%
2009 75.0 6.6 3.8 16.9 1.2 8.2 111.7 115.9 4.2 2%
2010 80.5 7.0 3.9 15.5 1.2 10.3 118.5 121.8 3.4 2%
2011 83.7 7.5 3.9 15.9 1.3 10.2 122.6 125.7 3.1 1%
2012 86.5 7.8 4.0 16.4 1.3 10.1 126.1 129.9 3.8 2%
2013 75.2 8.1 4.0 7.3 1.4 18.7 114.8 123.3 8.5 4%
2014 78.0 8.4 4.1 7.4 1.5 18.4 117.7 126.9 9.2 4%
2015 85.9 8.8 4.1 7.5 1.5 18.1 125.8 131.3 5.5 2%
2016 88.4 9.0 4.1 7.7 1.6 17.0 127.6 134.5 6.9 3%
2017 92.8 9.5 4.1 7.8 1.6 16.7 132.5 141.2 8.7 3%
2018 99.4 10.3 4.1 7.9 1.7 16.4 139.7 151.5 11.8 4%
2019 105.8 10.9 4.1 8.0 1.8 16.0 146.6 160.9 14.3 5%
2020 115.4 11.3 4.1 8.1 1.8 15.7 156.4 166.2 9.8 3%
2021 117.6 11.5 4.1 8.2 1.9 15.3 158.6 167.7 9.1 3%
2022 121.2 11.8 4.1 7.9 2.0 14.8 161.8 171.5 9.6 3%
2023 127.1 12.4 4.1 - 2.1 14.4 160.1 171.8 11.8 4%
2024 134.7 13.1 4.1 - 2.2 14.0 168.1 182.2 14.1 4%
Total 1,784.5 171.9 75.4 215.4 29.4 245.6 2,522.3 2,651.8 129.5 3%
PG&E CCA_Marin_Jan_05 Financial Summary 1
COUNTY OF MARIN
ELECTRIC SUPPLY RESOURCE MIX
51% RENEWABLE ENERGY
CATEGORY
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Spot Market Purchases 0% 18% 18% 15% 17% 20% 18% 15% 5% 6% 13% 11% 9% 9% 9% 10%
Contract Purchases 0% 68% 67% 64% 63% 34% 33% 33% 32% 32% 21% 21% 20% 20% 20% 20%
Power Production - Natural Gas 0% 0% 0% 0% 0% 25% 24% 24% 24% 23% 23% 23% 22% 22% 22% 21%
Renewable Energy Purchases 0% 14% 15% 0% 0% 1% 5% 9% 0% 1% 4% 8% 13% 14% 15% 16%
Power Production - Renewable Energy 0% 0% 0% 21% 21% 20% 20% 20% 42% 41% 40% 39% 38% 37% 36% 35%
Off System Sales 0% 0% 0% -1% 0% 0% 0% 0% -3% -3% 0% -1% -2% -2% -2% -1%
Total 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
PG&E CCA_Marin_Jan_05 Portfolio Summary 1
COUNTY OF MARIN
ELECTRIC SUPPLY RESOURCE MIX
51% RENEWABLE ENERGY
CATEGORY
Spot Market Purchases
Contract Purchases
Power Production - Natural Gas
Renewable Energy Purchases
Power Production - Renewable Energy
Off System Sales
Total
2021 2022 2023 2024
10% 10% 11% 11%
19% 19% 19% 18%
21% 21% 20% 20%
17% 18% 19% 19%
34% 33% 32% 32%
-1% -1% -1% 0%
100% 100% 100% 100%
PG&E CCA_Marin_Jan_05 Portfolio Summary 2
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012
I. PG&E PG&E'S UNBUNDLED GENERATION RATES ($/KWH)
RESIDENTIAL $0.06781 $0.06718 $0.06732 $0.06879 $0.06943 $0.07187 $0.07305 $0.07440
SMALL COMMERCIAL (A-1 & A6) $0.08194 $0.08116 $0.08133 $0.08313 $0.08392 $0.08690 $0.08835 $0.09000
MEDIUM COMMERCIAL (A-10) $0.10119 $0.10022 $0.10043 $0.10268 $0.10366 $0.10739 $0.10919 $0.11125
MEDIUM INDUSTRIAL (E-19) $0.09199 $0.09110 $0.09130 $0.09333 $0.09422 $0.09759 $0.09922 $0.10108
LARGE INDUSTRIAL (E-20) $0.08456 $0.08375 $0.08393 $0.08579 $0.08660 $0.08969 $0.09118 $0.09289
AGRICULTURAL PUMPING $0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453
STREET LIGHTING AND TRAFFIC CONTROL $0.06307 $0.06248 $0.06261 $0.06397 $0.06456 $0.06682 $0.06791 $0.06916
II. PG&E PG&E'S REVENUE REQUIREMENT FOR POWER SUPPLY ($)
RESIDENTIAL $0 $46,977,196 $47,782,012 $49,559,206 $50,770,262 $53,344,472 $55,032,545 $56,890,284
SMALL COMMERCIAL (A-1 & A6) $0 $18,261,645 $18,574,990 $19,270,991 $19,744,119 $20,753,703 $21,414,469 $22,141,957
MEDIUM COMMERCIAL (A-10) $0 $20,846,381 $21,204,583 $22,004,457 $22,547,001 $23,708,759 $24,467,797 $25,303,801
MEDIUM INDUSTRIAL (E-19)$0 $8,576,057 $8,723,330 $9,051,452 $9,274,222 $9,750,535 $10,061,966 $10,404,920
LARGE INDUSTRIAL (E-20)$0 $12,058,702 $12,265,661 $12,725,755 $13,038,407 $13,705,939 $14,142,709 $14,623,614
AGRICULTURAL PUMPING $0 $0 $0 $0 $0 $0 $0 $0
STREET LIGHTING AND TRAFFIC CONTROL $0 $516,567 $517,646 $528,903 $533,794 $552,472 $561,486 $571,810
TOTAL - POWER SUPPLY REVENUE REQUIREMENT $0 $107,236,548 $109,068,221 $113,140,765 $115,907,806 $121,815,879 $125,680,971 $129,936,386
AVERAGE RATE ($/KWH)$0.0000 $0.0778 $0.0779 $0.0797 $0.0804 $0.0833 $0.0847 $0.0862
III. OPERATING EXPENSES ($)
1. POWER SUPPLY COSTS:
(A) ANCILLARY SERVICES AND RESERVES $0 $4,330,492 $4,494,999 $4,681,290 $5,086,595 $5,428,282 $5,829,973 $6,084,355
(B) RENEWABLE PORTFOLIO STANDARD (RPS) $0 $14,057,186 $15,971,762 $0 $215,805 $1,165,107 $5,171,657 $10,979,329
(C) DWR POWER $0 $0 $0 $0 $0 $0 $0 $0
(D) POWER PRODUCTION $0 $0 $0 $8,704,720 $8,851,232 $25,451,014 $26,035,734 $26,690,970
(E) CONTRACT PURCHASES $0 $50,482,630 $50,482,630 $53,394,338 $53,394,338 $37,128,268 $37,128,268 $37,128,268
(F) MARKET PURCHASES $0 $11,865,485 $11,950,301 $10,852,846 $12,987,269 $17,077,922 $16,395,321 $13,803,105
SUBTOTAL POWER SUPPLY COSTS $0 $80,735,793 $82,899,692 $77,633,194 $80,535,239 $86,250,593 $90,560,954 $94,686,027
2. OTHER COSTS:
(A) CALIFORNIA ISO COSTS $0 $1,346,261 $1,399,768 $1,456,536 $1,531,016 $1,602,668 $1,680,580 $1,749,711
(B) NON-BYPASSABLE CHARGES $0 $25,092,355 $23,655,081 $24,066,327 $16,885,988 $15,501,960 $15,944,062 $16,435,934
(C) START UP COSTS AMORTIZATION $0 $475,426 $501,575 $529,161 $558,265 $588,970 $621,363 $655,538
(D) OPERATIONS & SCHEDULING COORDINATION $0 $3,646,823 $3,698,215 $3,750,379 $3,803,324 $3,857,064 $3,911,610 $3,966,974
SUBTOTAL - OTHER COSTS $0 $30,560,865 $29,254,639 $29,802,403 $22,778,593 $21,550,662 $22,157,614 $22,808,156
PG&E CCA_Marin_Jan_05 Load Aggregation 3 1
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012
3. UTILITY OPERATIONS:
(A) DISTRIBUTION O&M $0 $0 $0 $0 $0 $0 $0 $0
(B) CUSTOMER SERVICE $0 $0 $0 $0 $0 $0 $0 $0
(C) METERING & BILLING $0 $1,060,331 $1,103,057 $1,147,505 $1,193,746 $1,241,852 $1,291,898 $1,343,961
(D) ADMINISTRATIVE AND GENERAL $0 $0 $0 $0 $0 $0 $0 $0
SUBTOTAL - UTILITY OPERATIONS $0 $1,060,331 $1,103,057 $1,147,505 $1,193,746 $1,241,852 $1,291,898 $1,343,961
TOTAL OPERATING EXPENSES $0 $112,356,989 $113,257,388 $108,583,102 $104,507,579 $109,043,107 $114,010,465 $118,838,145
IV. INTEREST EXPENSE ($)
(A) INTEREST EXPENSE ($)$0 $336,670 $310,522 $7,361,144 $7,234,323 $9,303,044 $9,131,482 $8,950,484
(B) DEBT COVERAGE $0 $0 $0 $856,273 $0 $0 $0 $0
(C) WORKING CAPITAL EXPENSE $0 $342,680 $356,354 $373,290 $414,363 $443,347 $457,995 $475,075
SUBTOTAL - FINANCING EXPENSE $0 $679,351 $666,876 $8,590,708 $7,648,686 $9,746,391 $9,589,477 $9,425,559
V. REVENUES FROM MARKET SALES ($)
(A) EXCESS ENERGY SALES $0 $99,101 $111,815 $515,239 $425,243 $89,395 $181,946 $517,576
(B) EXCESS ANCILLARY SERVICE SALES $0 $0 $0 $0 $0 $0 $0 $0
(C) SUPPLEMENTAL ENERGY PAYMENTS $0 $4,661,821 $5,005,105 $0 $56,633 $239,532 $836,191 $1,597,307
$0 $0 $0 $0 $0 $0 $0 $0
SUBTOTAL - OTHER REVENUES $0 $4,760,922 $5,116,920 $515,239 $481,876 $328,927 $1,018,138 $2,114,883
VI. REVENUE REQUIREMENT - NET MARKET SALES ($) $0 $108,275,418 $108,807,344 $116,658,571 $111,674,388 $118,460,570 $122,581,805 $126,148,821
VII. CCA NET MARGIN $0 ($1,038,870)$260,877 ($3,517,806)$4,233,417 $3,355,308 $3,099,166 $3,787,565
NET PRESENT VALUE $38,300,581.11
NOMINAL MARGIN $129,471,017.21
PG&E CCA_Marin_Jan_05 Load Aggregation 3 2
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
CATEGORY
I. PG&E PG&E'S UNBUNDLED GENERATION RATES ($/KWH)
RESIDENTIAL
SMALL COMMERCIAL (A-1 & A6)
MEDIUM COMMERCIAL (A-10)
MEDIUM INDUSTRIAL (E-19)
LARGE INDUSTRIAL (E-20)
AGRICULTURAL PUMPING
STREET LIGHTING AND TRAFFIC CONTROL
II. PG&E PG&E'S REVENUE REQUIREMENT FOR POWER SUPPLY ($)
RESIDENTIAL
SMALL COMMERCIAL (A-1 & A6)
MEDIUM COMMERCIAL (A-10)
MEDIUM INDUSTRIAL (E-19)
LARGE INDUSTRIAL (E-20)
AGRICULTURAL PUMPING
STREET LIGHTING AND TRAFFIC CONTROL
TOTAL - POWER SUPPLY REVENUE REQUIREMENT
AVERAGE RATE ($/KWH)
III. OPERATING EXPENSES ($)
1. POWER SUPPLY COSTS:
(A) ANCILLARY SERVICES AND RESERVES
(B) RENEWABLE PORTFOLIO STANDARD (RPS)
(C) DWR POWER
(D) POWER PRODUCTION
(E) CONTRACT PURCHASES
(F) MARKET PURCHASES
SUBTOTAL POWER SUPPLY COSTS
2. OTHER COSTS:
(A) CALIFORNIA ISO COSTS
(B) NON-BYPASSABLE CHARGES
(C) START UP COSTS AMORTIZATION
(D) OPERATIONS & SCHEDULING COORDINATION
SUBTOTAL - OTHER COSTS
[9] [10] [11] [12] [13] [14] [15] [16]
2013 2014 2015 2016 2017 2018 2019 2020
$0.06960 $0.07055 $0.07194 $0.07259 $0.07509 $0.07932 $0.08296 $0.08444
$0.08412 $0.08528 $0.08699 $0.08778 $0.09084 $0.09602 $0.10047 $0.10228
$0.10391 $0.10536 $0.10749 $0.10848 $0.11230 $0.11877 $0.12433 $0.12658
$0.09445 $0.09576 $0.09768 $0.09858 $0.10204 $0.10789 $0.11292 $0.11496
$0.08682 $0.08802 $0.08978 $0.09060 $0.09376 $0.09912 $0.10372 $0.10558
$0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453 $0.00453
$0.06472 $0.06559 $0.06688 $0.06748 $0.06980 $0.07371 $0.07708 $0.07844
$54,017,205 $55,574,584 $57,520,764 $58,913,064 $61,855,446 $66,324,063 $70,407,299 $72,734,619
$21,007,444 $21,616,606 $22,378,735 $22,922,811 $24,076,907 $25,831,637 $27,434,628 $28,346,468
$23,990,310 $24,689,608 $25,565,427 $26,189,473 $27,517,649 $29,539,115 $31,385,358 $32,433,693
$9,867,783 $10,154,783 $10,514,070 $10,770,279 $11,314,800 $12,143,197 $12,899,860 $13,329,835
$13,872,728 $14,275,344 $14,779,149 $15,138,697 $15,901,791 $17,062,222 $18,122,265 $18,725,081
$0 $0 $0 $0 $0 $0 $0 $0
$535,090 $542,344 $552,985 $557,975 $577,088 $609,475 $637,307 $648,594
$123,290,560 $126,853,269 $131,311,130 $134,492,298 $141,243,681 $151,509,709 $160,886,718 $166,218,290
$0.0806 $0.0817 $0.0834 $0.0841 $0.0870 $0.0920 $0.0963 $0.0980
$6,305,470 $6,520,153 $6,788,644 $6,980,210 $7,397,730 $8,027,880 $8,592,955 $8,904,696
$0 $1,067,123 $4,941,101 $10,295,148 $18,121,829 $21,560,989 $24,937,475 $27,348,253
$0 $0 $0 $0 $0 $0 $0 $0
$36,922,015 $37,541,025 $38,351,715 $38,890,177 $40,211,944 $42,238,711 $44,012,559 $44,925,571
$37,128,268 $37,128,268 $30,607,467 $30,607,467 $30,607,467 $30,607,467 $30,607,467 $35,796,698
$4,836,144 $5,225,859 $13,065,554 $10,884,547 $9,134,414 $10,395,980 $11,598,355 $12,436,105
$85,191,897 $87,482,428 $93,754,481 $97,657,550 $105,473,383 $112,831,027 $119,748,811 $129,411,322
$1,818,456 $1,888,854 $1,965,382 $2,038,599 $2,130,680 $2,240,750 $2,348,662 $2,440,792
$7,329,636 $7,434,967 $7,541,858 $7,650,334 $7,760,417 $7,872,132 $7,985,503 $8,100,555
$691,593 $729,630 $769,760 $0 $0 $0 $0 $0
$4,023,169 $4,055,208 $4,057,524 $4,059,874 $4,062,260 $4,064,682 $4,067,139 $4,069,634
$13,862,853 $14,108,659 $14,334,524 $13,748,807 $13,953,357 $14,177,564 $14,401,305 $14,610,981
PG&E CCA_Marin_Jan_05 Load Aggregation 3 3
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
CATEGORY
3. UTILITY OPERATIONS:
(A) DISTRIBUTION O&M
(B) CUSTOMER SERVICE
(C) METERING & BILLING
(D) ADMINISTRATIVE AND GENERAL
SUBTOTAL - UTILITY OPERATIONS
TOTAL OPERATING EXPENSES
IV. INTEREST EXPENSE ($)
(A) INTEREST EXPENSE ($)
(B) DEBT COVERAGE
(C) WORKING CAPITAL EXPENSE
SUBTOTAL - FINANCING EXPENSE
V. REVENUES FROM MARKET SALES ($)
(A) EXCESS ENERGY SALES
(B) EXCESS ANCILLARY SERVICE SALES
(C) SUPPLEMENTAL ENERGY PAYMENTS
SUBTOTAL - OTHER REVENUES
VI. REVENUE REQUIREMENT - NET MARKET SALES ($)
VII. CCA NET MARGIN
NET PRESENT VALUE $38,300,581.11
NOMINAL MARGIN $129,471,017.21
[9] [10] [11] [12] [13] [14] [15] [16]
2013 2014 2015 2016 2017 2018 2019 2020
$0 $0 $0 $0 $0 $0 $0 $0
$0 $0 $0 $0 $0 $0 $0 $0
$1,398,125 $1,454,473 $1,513,093 $1,574,078 $1,637,522 $1,703,525 $1,772,191 $1,843,625
$0 $0 $0 $0 $0 $0 $0 $0
$1,398,125 $1,454,473 $1,513,093 $1,574,078 $1,637,522 $1,703,525 $1,772,191 $1,843,625
$100,452,875 $103,045,560 $109,602,099 $112,980,434 $121,064,262 $128,712,116 $135,922,307 $145,865,929
$17,465,409 $17,143,766 $16,804,433 $16,446,436 $16,113,415 $15,762,077 $15,391,416 $15,000,369
$0 $0 $0 $0 $0 $0 $0 $0
$498,404 $509,553 $517,794 $532,983 $569,545 $610,669 $647,601 $667,394
$17,963,813 $17,653,319 $17,322,227 $16,979,419 $16,682,959 $16,372,747 $16,039,017 $15,667,762
$3,655,932 $2,874,434 $501,389 $1,074,070 $3,207,524 $2,923,100 $2,523,059 $2,056,803
$0 $0 $0 $0 $0 $0 $0 $0
$0 $137,513 $582,274 $1,249,010 $2,045,296 $2,434,850 $2,817,508 $3,091,150
$0 $0 $0 $0 $0 $0 $0 $0
$3,655,932 $3,011,947 $1,083,663 $2,323,080 $5,252,820 $5,357,949 $5,340,566 $5,147,953
$114,760,757 $117,686,932 $125,840,663 $127,636,774 $132,494,402 $139,726,913 $146,620,758 $156,385,739
$8,529,804 $9,166,337 $5,470,467 $6,855,524 $8,749,279 $11,782,796 $14,265,960 $9,832,551
PG&E CCA_Marin_Jan_05 Load Aggregation 3 4
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
CATEGORY
I. PG&E PG&E'S UNBUNDLED GENERATION RATES ($/KWH)
RESIDENTIAL
SMALL COMMERCIAL (A-1 & A6)
MEDIUM COMMERCIAL (A-10)
MEDIUM INDUSTRIAL (E-19)
LARGE INDUSTRIAL (E-20)
AGRICULTURAL PUMPING
STREET LIGHTING AND TRAFFIC CONTROL
II. PG&E PG&E'S REVENUE REQUIREMENT FOR POWER SUPPLY ($)
RESIDENTIAL
SMALL COMMERCIAL (A-1 & A6)
MEDIUM COMMERCIAL (A-10)
MEDIUM INDUSTRIAL (E-19)
LARGE INDUSTRIAL (E-20)
AGRICULTURAL PUMPING
STREET LIGHTING AND TRAFFIC CONTROL
TOTAL - POWER SUPPLY REVENUE REQUIREMENT
AVERAGE RATE ($/KWH)
III. OPERATING EXPENSES ($)
1. POWER SUPPLY COSTS:
(A) ANCILLARY SERVICES AND RESERVES
(B) RENEWABLE PORTFOLIO STANDARD (RPS)
(C) DWR POWER
(D) POWER PRODUCTION
(E) CONTRACT PURCHASES
(F) MARKET PURCHASES
SUBTOTAL POWER SUPPLY COSTS
2. OTHER COSTS:
(A) CALIFORNIA ISO COSTS
(B) NON-BYPASSABLE CHARGES
(C) START UP COSTS AMORTIZATION
(D) OPERATIONS & SCHEDULING COORDINATION
SUBTOTAL - OTHER COSTS
[17] [18] [19] [20]
2021 2022 2023 2024
$0.08392 $0.08456 $0.08285 $0.08655
$0.10165 $0.10242 $0.10134 $0.10587
$0.12580 $0.12676 $0.12654 $0.13220
$0.11425 $0.11512 $0.11449 $0.11961
$0.10494 $0.10574 $0.10477 $0.10945
$0.00453 $0.00453 $0.00000 $0.00000
$0.07797 $0.07855 $0.07663 $0.08006
$73,376,420 $75,038,335 $74,623,534 $79,128,062
$28,594,863 $29,244,689 $29,370,196 $31,143,080
$32,716,103 $33,461,849 $33,904,064 $35,950,628
$13,446,217 $13,752,320 $13,881,849 $14,719,804
$18,888,995 $19,318,466 $19,429,498 $20,602,328
$0 $0 $0 $0
$644,664 $649,501 $633,613 $661,931
$167,667,262 $171,465,161 $171,842,753 $182,205,832
$0.0974 $0.0981 $0.0969 $0.1012
$8,981,915 $9,207,288 $9,670,834 $10,289,637
$28,682,853 $30,653,272 $33,822,236 $37,895,754
$0 $0 $0 $0
$45,077,702 $45,727,127 $47,137,608 $49,020,390
$35,796,698 $35,796,698 $35,796,698 $35,796,698
$12,875,899 $13,752,404 $15,243,433 $17,245,232
$131,415,067 $135,136,789 $141,670,809 $150,247,711
$2,518,620 $2,610,162 $2,722,100 $2,848,510
$8,217,313 $7,915,557 $0 $0
$0 $0 $0 $0
$4,072,166 $4,074,736 $4,077,345 $4,079,993
$14,808,099 $14,600,455 $6,799,445 $6,928,503
PG&E CCA_Marin_Jan_05 Load Aggregation 3 5
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
LOAD AGGREGATION SUMMARY
51% RENEWABLE ENERGY
CATEGORY
3. UTILITY OPERATIONS:
(A) DISTRIBUTION O&M
(B) CUSTOMER SERVICE
(C) METERING & BILLING
(D) ADMINISTRATIVE AND GENERAL
SUBTOTAL - UTILITY OPERATIONS
TOTAL OPERATING EXPENSES
IV. INTEREST EXPENSE ($)
(A) INTEREST EXPENSE ($)
(B) DEBT COVERAGE
(C) WORKING CAPITAL EXPENSE
SUBTOTAL - FINANCING EXPENSE
V. REVENUES FROM MARKET SALES ($)
(A) EXCESS ENERGY SALES
(B) EXCESS ANCILLARY SERVICE SALES
(C) SUPPLEMENTAL ENERGY PAYMENTS
SUBTOTAL - OTHER REVENUES
VI. REVENUE REQUIREMENT - NET MARKET SALES ($)
VII. CCA NET MARGIN
NET PRESENT VALUE $38,300,581.11
NOMINAL MARGIN $129,471,017.21
[17] [18] [19] [20]
2021 2022 2023 2024
$0 $0 $0 $0
$0 $0 $0 $0
$1,917,941 $1,995,255 $2,075,686 $2,159,363
$0 $0 $0 $0
$1,917,941 $1,995,255 $2,075,686 $2,159,363
$148,141,107 $151,732,498 $150,545,940 $159,335,577
$14,587,814 $14,152,568 $13,693,384 $13,208,945
$0 $0 $0 $0
$670,967 $686,797 $720,479 $763,091
$15,258,781 $14,839,365 $14,413,862 $13,972,036
$1,582,248 $1,281,589 $1,072,092 $935,963
$0 $0 $0 $0
$3,243,142 $3,466,998 $3,826,447 $4,288,320
$0 $0 $0 $0
$4,825,390 $4,748,586 $4,898,539 $5,224,283
$158,574,498 $161,823,277 $160,061,263 $168,083,329
$9,092,763 $9,641,884 $11,781,490 $14,122,503
PG&E CCA_Marin_Jan_05 Load Aggregation 3 6
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
DEBT SERVICE
51% RENEWABLE ENERGY
I. TOTAL DEBT ISSUANCES
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
(A) STARTUP COSTS $0 $6,121,281 $0 $0 $0 $0 $0 $0 $0 $0 $0
(B) GENERATION DEVELOPMENT $0 $0 $0 $128,694,710 $0 $40,045,767 $0 $0 $158,288,687 $0 $0
SUBTOTAL - DEBT ISSUANCE $0 $6,121,281 $0 $128,694,710 $0 $40,045,767 $0 $0 $158,288,687 $0 $0
II. TOTAL DEBT SERVICE
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
(A) STARTUP COSTS $0 $812,097 $812,097 $812,097 $812,097 $812,097 $812,097 $812,097 $812,097 $812,097 $812,097
(B) GENERATION DEVELOPMENT $0 $0 $0 $8,854,890 $8,854,890 $11,610,254 $11,610,254 $11,610,254 $22,501,369 $22,501,369 $22,501,369
SUBTOTAL - FINANCING COSTS $0 $812,097 $812,097 $9,666,986 $9,666,986 $12,422,351 $12,422,351 $12,422,351 $23,313,466 $23,313,466 $23,313,466
(D) DEBT COVERAGE ( 1.25 ) $0 $0 $0 $856,273 $0 $0 $0 $0 $0 $0 $0
TOTAL DEBT SERVICE $0 $812,097 $812,097 $10,523,259 $9,666,986 $12,422,351 $12,422,351 $12,422,351 $23,313,466 $23,313,466 $23,313,466
III. INTEREST PORTION OF DEBT SERVICE
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
(A) STARTUP COSTS $0 $336,670 $310,522 $282,935 $253,832 $223,127 $190,734 $156,559 $120,504 $82,466 $42,337
(B) GENERATION DEVELOPMENT $0 $0 $0 $7,078,209 $6,980,492 $9,079,917 $8,940,748 $8,793,926 $17,344,905 $17,061,300 $16,762,096
SUBTOTAL - FINANCING COSTS $0 $336,670 $310,522 $7,361,144 $7,234,323 $9,303,044 $9,131,482 $8,950,484 $17,465,409 $17,143,766 $16,804,433
TOTAL INTEREST $0 $336,670 $310,522 $7,361,144 $7,234,323 $9,303,044 $9,131,482 $8,950,484 $17,465,409 $17,143,766 $16,804,433
PG&E CCA_Marin_Jan_05 Debt Service 4 1
IV. PRINCIPAL PORTION OF DEBT SERVICE
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
(A) STARTUP COSTS $0 $475,426 $501,575 $529,161 $558,265 $588,970 $621,363 $655,538 $691,593 $729,630 $769,760
(B) GENERATION DEVELOPMENT $0 $0 $0 $1,776,681 $1,874,398 $2,530,337 $2,669,506 $2,816,329 $5,156,464 $5,440,069 $5,739,273
SUBTOTAL - FINANCING COSTS $0 $475,426 $501,575 $2,305,842 $2,432,663 $3,119,307 $3,290,869 $3,471,867 $5,848,057 $6,169,700 $6,509,033
TOTAL PRINCIPAL $0 $475,426 $501,575 $2,305,842 $2,432,663 $3,119,307 $3,290,869 $3,471,867 $5,848,057 $6,169,700 $6,509,033
V. RESERVES [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
CATEGORY
DEBT COVERAGE RESERVE ADDITIONS ($ B.O.Y.) $0 $0 $0 $0 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273
DEBT COVERAGE RESERVE ADDITIONS ($ E.O.Y.) $0 $0 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273
DEBT SERVICE RESERVE ($) $0 $612,128 $612,128 $13,481,599 $13,481,599 $17,486,176 $17,486,176 $17,486,176 $33,315,044 $33,315,044 $33,315,044
TOTAL DEBT SERVICE RESERVES $0 $612,128 $612,128 $14,337,872 $14,337,872 $18,342,449 $18,342,449 $18,342,449 $34,171,317 $34,171,317 $34,171,317
PG&E CCA_Marin_Jan_05 Debt Service 4 2
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
DEBT SERVICE
51% RENEWABLE ENERGY
I. TOTAL DEBT ISSUANCES
CATEGORY
(A) STARTUP COSTS
(B) GENERATION DEVELOPMENT
SUBTOTAL - DEBT ISSUANCE
II. TOTAL DEBT SERVICE
CATEGORY
(A) STARTUP COSTS
(B) GENERATION DEVELOPMENT
SUBTOTAL - FINANCING COSTS
(D) DEBT COVERAGE ( 1.25 )
TOTAL DEBT SERVICE
III. INTEREST PORTION OF DEBT SERVICE
CATEGORY
(A) STARTUP COSTS
(B) GENERATION DEVELOPMENT
SUBTOTAL - FINANCING COSTS
TOTAL INTEREST
[12] [13] [14] [15] [16] [17] [18] [19] [20]
2016 2017 2018 2019 2020 2021 2022 2023 2024
$0 $0 $0 $0 $0 $0 $0 $0 $0
$0 $0 $0 $0 $0 $0 $0 $0 $0
$0 $0 $0 $0 $0 $0 $0 $0 $0
[12] [13] [14] [15] [16] [17] [18] [19] [20]
2016 2017 2018 2019 2020 2021 2022 2023 2024
$0 $0 $0 $0 $0 $0 $0 $0 $0
$22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369
$22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369
$0 $0 $0 $0 $0 $0 $0 $0 $0
$22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369 $22,501,369
[12] [13] [14] [15] [16] [17] [18] [19] [20]
2016 2017 2018 2019 2020 2021 2022 2023 2024
$0 $0 $0 $0 $0 $0 $0 $0 $0
$16,446,436 $16,113,415 $15,762,077 $15,391,416 $15,000,369 $14,587,814 $14,152,568 $13,693,384 $13,208,945
$16,446,436 $16,113,415 $15,762,077 $15,391,416 $15,000,369 $14,587,814 $14,152,568 $13,693,384 $13,208,945
$16,446,436 $16,113,415 $15,762,077 $15,391,416 $15,000,369 $14,587,814 $14,152,568 $13,693,384 $13,208,945
PG&E CCA_Marin_Jan_05 Debt Service 4 3
IV. PRINCIPAL PORTION OF DEBT SERVICE
CATEGORY
(A) STARTUP COSTS
(B) GENERATION DEVELOPMENT
SUBTOTAL - FINANCING COSTS
TOTAL PRINCIPAL
V. RESERVES
CATEGORY
DEBT COVERAGE RESERVE ADDITIONS ($ B.O.Y.)
DEBT COVERAGE RESERVE ADDITIONS ($ E.O.Y.)
DEBT SERVICE RESERVE ($)
TOTAL DEBT SERVICE RESERVES
[12] [13] [14] [15] [16] [17] [18] [19] [20]
2016 2017 2018 2019 2020 2021 2022 2023 2024
$0 $0 $0 $0 $0 $0 $0 $0 $0
$6,054,933 $6,387,954 $6,739,292 $7,109,953 $7,501,000 $7,913,555 $8,348,801 $8,807,985 $9,292,424
$6,054,933 $6,387,954 $6,739,292 $7,109,953 $7,501,000 $7,913,555 $8,348,801 $8,807,985 $9,292,424
$6,054,933 $6,387,954 $6,739,292 $7,109,953 $7,501,000 $7,913,555 $8,348,801 $8,807,985 $9,292,424
[12] [13] [14] [15] [16] [17] [18] [19] [20]
2016 2017 2018 2019 2020 2021 2022 2023 2024
$856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273
$856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273 $856,273
$33,315,044 $33,315,044 $33,315,044 $33,315,044 $33,315,044 $33,315,044 $33,315,044 $33,315,044 $33,315,044
$34,171,317 $34,171,317 $34,171,317 $34,171,317 $34,171,317 $34,171,317 $34,171,317 $34,171,317 $34,171,317
PG&E CCA_Marin_Jan_05 Debt Service 4 4
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOURCES
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
SECTION I - PROJECTED MARKET PRICES:
(A) MARKET ENERGY ($/MWH):
AVERAGE ENERGY PRICE $48.30 $45.27 $46.24 $47.48 $52.08 $55.51 $59.70 $61.48 $62.66 $63.65 $65.33 $65.80 $69.35 $75.66
ON-PEAK ENERGY PRICE $55.54 $52.06 $53.18 $54.60 $59.90 $63.83 $68.65 $70.70 $72.06 $73.20 $75.13 $75.67 $79.75 $87.01
OFF-PEAK ENERGY PRICE $41.05 $38.48 $39.30 $40.36 $44.27 $47.18 $50.74 $52.26 $53.26 $54.11 $55.53 $55.93 $58.95 $64.31
REAL-TIME PREMIUM $4.83 $4.53 $4.62 $4.75 $5.21 $5.55 $5.97 $6.15 $6.27 $6.37 $6.53 $6.58 $6.93 $7.57
(B) CDWR CONTRACT ENERGY ($/MWH):
AVERAGE CDWR CONTRACT PRICE $74.87 $71.61 $71.95 $70.26 $67.04 $97.01 $76.44 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
(C) RENEWABLE PORTFOLIO STANDARD (RPS):
RPS REQUIREMENTS (%) 13.0% 14.0% 15.5% 17.0% 18.5% 20.0% 24.4% 28.9% 33.3% 37.7% 42.1% 46.6% 51.0% 51.0%
RPS ENERGY PRICE ($/MWH) $67.21 $67.88 $68.56 $69.25 $69.94 $70.64 $71.35 $72.06 $72.78 $73.51 $74.24 $74.99 $78.28 $85.40
RPS CONTRACT CAPACITY (MW) - 24 26 - 0 2 8 17 - 2 7 16 26 29
TOTAL RENEWABLE CAPACITY (MW) - 24 26 37 37 38 44 53 79 80 84 92 101 103
(D) ANCILLARY SERVICE PRICES ($/MWH):
SPINNING RESERVE $10.92 $10.23 $10.45 $10.73 $11.77 $12.54 $13.49 $13.90 $14.16 $14.39 $14.76 $14.87 $15.67 $17.10
NON-SPINNING RESERVE $6.81 $6.38 $6.52 $6.69 $7.34 $7.83 $8.42 $8.67 $8.84 $8.98 $9.21 $9.28 $9.78 $10.67
REPLACEMENT RESERVE $10.00 $9.37 $9.57 $9.83 $10.78 $11.49 $12.36 $12.73 $12.97 $13.18 $13.52 $13.62 $14.36 $15.66
REGULATION - UP $31.93 $29.92 $30.57 $31.38 $34.43 $36.69 $39.46 $40.64 $41.42 $42.07 $43.18 $43.49 $45.84 $50.01
REGULATION - DOWN $31.93 $29.92 $30.57 $31.38 $34.43 $36.69 $39.46 $40.64 $41.42 $42.07 $43.18 $43.49 $45.84 $50.01
(E) NATURAL GAS PRICE ($/MMBtu):
AVERAGE NATURAL GAS PRICE $6.04 $5.49 $5.32 $5.28 $5.21 $5.29 $5.43 $5.59 $5.70 $5.79 $5.94 $5.98 $6.30 $6.88
REFEENCE GAS PRICE - HIGH $7.55 $6.86 $6.64 $6.59 $6.51 $6.61 $6.78 $6.99 $7.12 $7.23 $7.42 $7.48 $7.88 $8.60
REFEENCE GAS PRICE - MID $6.04 $5.49 $5.32 $5.28 $5.21 $5.29 $5.43 $5.59 $5.70 $5.79 $5.94 $5.98 $6.30 $6.88
REFEENCE GAS PRICE - LOW $4.53 $4.12 $3.99 $3.96 $3.91 $3.96 $4.07 $4.19 $4.27 $4.34 $4.45 $4.49 $4.73 $5.16
(F) EMISSIONS CREDIT PRICE ($/LB): $10.00 $10.25 $10.51 $10.77 $11.04 $11.31 $11.60 $11.89 $12.18 $12.49 $12.80 $13.12 $13.45 $13.79
(G) CAPACITY ($/MW): $100,000 $102,500 $105,063 $107,689 $110,381 $113,141 $115,969 $118,869 $121,840 $124,886 $128,008 $131,209 $134,489 $137,851
PG&E CCA_Marin_Jan_05 Annual Summary 13 1
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOU
51% RENEWABLE ENERGY
CATEGORY
SECTION I - PROJECTED MARKET PRICES:
(A) MARKET ENERGY ($/MWH):
AVERAGE ENERGY PRICE
ON-PEAK ENERGY PRICE
OFF-PEAK ENERGY PRICE
REAL-TIME PREMIUM
(B) CDWR CONTRACT ENERGY ($/MWH):
AVERAGE CDWR CONTRACT PRICE
(C) RENEWABLE PORTFOLIO STANDARD (RP
RPS REQUIREMENTS (%)
RPS ENERGY PRICE ($/MWH)
RPS CONTRACT CAPACITY (MW)
TOTAL RENEWABLE CAPACITY (MW)
(D) ANCILLARY SERVICE PRICES ($/MWH):
SPINNING RESERVE
NON-SPINNING RESERVE
REPLACEMENT RESERVE
REGULATION - UP
REGULATION - DOWN
(E) NATURAL GAS PRICE ($/MMBtu):
AVERAGE NATURAL GAS PRICE
REFEENCE GAS PRICE - HIGH
REFEENCE GAS PRICE - MID
REFEENCE GAS PRICE - LOW
(F) EMISSIONS CREDIT PRICE ($/LB):
(G) CAPACITY ($/MW):
[15] [16] [17] [18] [19] [20]
2019 2020 2021 2022 2023 2024
$80.84 $82.40 $80.74 $80.98 $84.19 $89.19
$92.96 $94.75 $92.85 $93.13 $96.82 $102.56
$68.71 $70.04 $68.63 $68.83 $71.56 $75.81
$8.08 $8.24 $8.07 $8.10 $8.42 $8.92
$0.00 $0.00 $0.00 $0.00 $0.00 $0.00
51.0% 51.0% 51.0% 51.0% 51.0% 51.0%
$91.24 $93.00 $91.13 $91.41 $95.03 $100.67
31 33 36 38 40 43
104 106 107 109 111 112
$18.27 $18.62 $18.25 $18.30 $19.03 $20.16
$11.40 $11.62 $11.38 $11.42 $11.87 $12.58
$16.73 $17.06 $16.71 $16.76 $17.43 $18.46
$53.43 $54.46 $53.37 $53.53 $55.65 $58.95
$53.43 $54.46 $53.37 $53.53 $55.65 $58.95
$7.35 $7.49 $7.34 $7.36 $7.65 $8.11
$9.19 $9.36 $9.17 $9.20 $9.57 $10.13
$7.35 $7.49 $7.34 $7.36 $7.65 $8.11
$5.51 $5.62 $5.50 $5.52 $5.74 $6.08
$14.13 $14.48 $14.85 $15.22 $15.60 $15.99
$141,297 $144,830 $148,451 $152,162 $155,966 $159,865
PG&E CCA_Marin_Jan_05 Annual Summary 13 2
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOURCES
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
SECTION II - PROJECTED LOADS AND ANCILLARY SERVICES:
(A) PROJECTED LOADS (KWH):
PROJECTED LOADS INCLUDING LOSSES
ON-PEAK 0 940,872,421 954,900,872 969,139,749 983,592,209 998,261,457 1,013,150,743 1,028,263,368 1,043,602,683 1,059,172,087 1,074,975,033 1,091,015,022 1,107,295,612 1,123,820,410
OFF-PEAK 0 536,940,681 544,946,491 553,072,388 561,320,174 569,691,676 578,188,751 586,813,282 595,567,181 604,452,388 613,470,874 622,624,637 631,915,706 641,346,141
TOTAL 0 1,477,813,103 1,499,847,363 1,522,212,137 1,544,912,383 1,567,953,133 1,591,339,494 1,615,076,650 1,639,169,864 1,663,624,476 1,688,445,907 1,713,639,659 1,739,211,318 1,765,166,552
PROJECTED LOADS EXCLUDING LOSSES
ON-PEAK 0 879,320,020 892,430,721 905,738,083 919,245,056 932,954,632 946,869,853 960,993,802 975,329,610 989,880,455 1,004,649,563 1,019,640,208 1,034,855,712 1,050,299,449
OFF-PEAK 0 501,813,721 509,295,786 516,890,083 524,598,293 532,422,127 540,363,319 548,423,628 556,604,842 564,908,774 573,337,265 581,892,184 590,575,426 599,388,917
TOTAL 0 1,381,133,741 1,401,726,508 1,422,628,166 1,443,843,349 1,465,376,760 1,487,233,172 1,509,417,430 1,531,934,452 1,554,789,230 1,577,986,829 1,601,532,392 1,625,431,138 1,649,688,366
(B) ANCILLARY SERVICES:
ANCILLARY SERVICE REQUIREMENTS (KWH):
SPINNING RESERVE 0 48,615,908 49,340,773 50,076,511 50,823,286 51,581,262 52,350,608 53,131,494 53,924,093 54,728,581 55,545,136 56,373,940 57,215,176 58,069,030
NON-SPINNING RESERVE 0 34,528,344 35,043,163 35,565,704 36,096,084 36,634,419 37,180,829 37,735,436 38,298,361 38,869,731 39,449,671 40,038,310 40,635,778 41,242,209
REPLACEMENT RESERVE 0 16,849,832 17,101,063 17,356,064 17,614,889 17,877,596 18,144,245 18,414,893 18,689,600 18,968,429 19,251,439 19,538,695 19,830,260 20,126,198
REGULATION - UP 0 31,075,509 31,538,846 32,009,134 32,486,475 32,970,977 33,462,746 33,961,892 34,468,525 34,982,758 35,504,704 36,034,479 36,572,201 37,117,988
REGULATION - DOWN 0 31,075,509 31,538,846 32,009,134 32,486,475 32,970,977 33,462,746 33,961,892 34,468,525 34,982,758 35,504,704 36,034,479 36,572,201 37,117,988
TOTAL - ANCILLARY SERVICES REQ. 0 162,145,101 164,562,692 167,016,547 169,507,209 172,035,232 174,601,174 177,205,606 179,849,105 182,532,256 185,255,654 188,019,903 190,825,616 193,673,414
ANCILLARY SERVICE COSTS ($)
SPINNING RESERVE $0 $499,622 $517,941 $539,754 $600,904 $649,981 $709,441 $741,569 $767,078 $790,826 $823,740 $842,026 $900,730 $997,403
NON-SPINNING RESERVE $0 $221,386 $229,503 $239,168 $266,264 $288,011 $314,358 $328,594 $339,897 $350,420 $365,005 $373,107 $399,119 $441,956
REPLACEMENT RESERVE $0 $158,606 $164,422 $171,346 $190,759 $206,338 $225,214 $235,413 $243,511 $251,050 $261,499 $267,304 $285,939 $316,628
REGULATION - UP $0 $934,059 $968,308 $1,009,087 $1,123,409 $1,215,159 $1,326,323 $1,386,387 $1,434,078 $1,478,474 $1,540,009 $1,574,195 $1,683,944 $1,864,677
REGULATION - DOWN $0 $934,059 $968,308 $1,009,087 $1,123,409 $1,215,159 $1,326,323 $1,386,387 $1,434,078 $1,478,474 $1,540,009 $1,574,195 $1,683,944 $1,864,677
TOTAL - ANCILLARY SERVICES COSTS $0 $2,747,732 $2,848,481 $2,968,443 $3,304,746 $3,574,648 $3,901,659 $4,078,351 $4,218,642 $4,349,244 $4,530,261 $4,630,827 $4,953,678 $5,485,341
(C) PLANNING RESERVES:
PLANNING RESERVES REQUIREMENTS (K - 15,442 15,672 15,905 16,143 16,383 16,628 16,876 17,128 17,383 17,642 17,906 18,173 18,444
PLANNING RESERVES COSTS ($) $0 $1,582,760 $1,646,518 $1,712,847 $1,781,850 $1,853,635 $1,928,314 $2,006,004 $2,086,828 $2,170,910 $2,258,383 $2,349,382 $2,444,052 $2,542,539
PG&E CCA_Marin_Jan_05 Annual Summary 13 3
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOU
51% RENEWABLE ENERGY
CATEGORY
SECTION II - PROJECTED LOADS AND ANCILLAR
(A) PROJECTED LOADS (KWH):
PROJECTED LOADS INCLUDING LOSSES
ON-PEAK
OFF-PEAK
TOTAL
PROJECTED LOADS EXCLUDING LOSSES
ON-PEAK
OFF-PEAK
TOTAL
(B) ANCILLARY SERVICES:
ANCILLARY SERVICE REQUIREMENTS (K
SPINNING RESERVE
NON-SPINNING RESERVE
REPLACEMENT RESERVE
REGULATION - UP
REGULATION - DOWN
TOTAL - ANCILLARY SERVICES REQ.
ANCILLARY SERVICE COSTS ($)
SPINNING RESERVE
NON-SPINNING RESERVE
REPLACEMENT RESERVE
REGULATION - UP
REGULATION - DOWN
TOTAL - ANCILLARY SERVICES COSTS
(C) PLANNING RESERVES:
PLANNING RESERVES REQUIREMENTS (K
PLANNING RESERVES COSTS ($)
[15] [16] [17] [18] [19] [20]
2019 2020 2021 2022 2023 2024
1,140,593,081 1,157,617,341 1,174,896,965 1,192,435,784 1,210,237,685 1,228,306,614
650,918,033 660,633,503 670,494,706 680,503,826 690,663,083 700,974,729
1,791,511,114 1,818,250,845 1,845,391,671 1,872,939,610 1,900,900,768 1,929,281,344
1,065,974,842 1,081,885,365 1,098,034,547 1,114,425,966 1,131,063,257 1,147,950,107
608,334,611 617,414,489 626,630,566 635,984,884 645,479,517 655,116,569
1,674,309,452 1,699,299,855 1,724,665,113 1,750,410,851 1,776,542,774 1,803,066,676
58,935,693 59,815,355 60,708,212 61,614,462 62,534,306 63,467,947
41,857,736 42,482,496 43,116,628 43,760,271 44,413,569 45,076,667
20,426,575 20,731,458 21,040,914 21,355,012 21,673,822 21,997,413
37,671,963 38,234,247 38,804,965 39,384,244 39,972,212 40,569,000
37,671,963 38,234,247 38,804,965 39,384,244 39,972,212 40,569,000
196,563,930 199,497,803 202,475,684 205,498,234 208,566,122 211,680,028
$1,081,521 $1,118,823 $1,112,701 $1,132,705 $1,195,169 $1,284,985
$479,229 $495,758 $493,045 $501,909 $529,587 $569,385
$343,332 $355,174 $353,230 $359,580 $379,410 $407,922
$2,021,938 $2,091,676 $2,080,230 $2,117,628 $2,234,407 $2,402,320
$2,021,938 $2,091,676 $2,080,230 $2,117,628 $2,234,407 $2,402,320
$5,947,957 $6,153,107 $6,119,437 $6,229,449 $6,572,981 $7,066,931
18,719 18,999 19,282 19,570 19,862 20,159
$2,644,998 $2,751,588 $2,862,478 $2,977,839 $3,097,852 $3,222,706
PG&E CCA_Marin_Jan_05 Annual Summary 13 4
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOURCES
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
SECTION III - PROJECTED RESOURCES:
(A) RENEWABLE PORTFOLIO STANDARD (KWH):
ON-PEAK 0 131,251,703 147,651,547 0 3,171,316 15,830,166 63,448,135 114,313,230 0 13,953,193 63,000,500 122,559,732 183,784,936 196,634,078
OFF-PEAK 0 74,903,225 84,262,351 0 0 0 8,326,725 36,698,832 0 0 2,307,499 13,352,732 45,287,395 53,311,916
TOTAL 0 206,154,928 231,913,899 0 3,171,316 15,830,166 71,774,860 151,012,062 0 13,953,193 65,307,999 135,912,464 229,072,331 249,945,993
COSTS ($):
ON-PEAK 0 8,957,849 10,177,900 0 215,805 1,165,107 4,586,708 8,317,336 0 1,067,123 4,785,510 9,317,960 14,544,284 16,970,716
OFF-PEAK 0 5,099,337 5,793,861 0 0 0 584,949 2,661,993 0 0 155,592 977,188 3,577,546 4,590,273
TOTAL 0 14,057,186 15,971,762 0 215,805 1,165,107 5,171,657 10,979,329 0 1,067,123 4,941,101 10,295,148 18,121,829 21,560,989
(B) CDWR CONTRACT ENERGY (KWH):
ON-PEAK 00000000000000
OFF-PEAK 00000000000000
TOTAL 00000000000000
COSTS ($):
ON-PEAK 00000000000000
OFF-PEAK 00000000000000
TOTAL 00000000000000
BALANCE (KWH):
ON-PEAK 0 809,620,718 807,249,324 969,139,749 980,420,893 982,431,291 949,702,608 913,950,138 1,043,602,683 1,045,218,894 1,011,974,533 968,455,290 923,510,676 927,186,333
OFF-PEAK 0 462,037,456 460,684,140 553,072,388 561,320,174 569,691,676 569,862,026 550,114,450 595,567,181 604,452,388 611,163,375 609,271,905 586,628,311 588,034,226
TOTAL 0 1,271,658,175 1,267,933,465 1,522,212,137 1,541,741,067 1,552,122,967 1,519,564,634 1,464,064,588 1,639,169,864 1,649,671,283 1,623,137,908 1,577,727,195 1,510,138,987 1,515,220,558
(C) POWER PRODUCTION (KWH):
ON-PEAK 0 0 0 189,378,336 187,529,288 409,429,401 407,725,318 406,089,399 624,217,668 619,011,908 614,014,378 609,216,749 604,611,026 600,189,532
OFF-PEAK 0 0 0 137,702,544 136,358,047 297,708,129 296,469,041 295,279,515 453,886,979 450,101,718 446,467,868 442,979,371 439,630,415 436,415,416
TOTAL 0 0 0 327,080,880 323,887,334 707,137,531 704,194,359 701,368,914 1,078,104,647 1,069,113,626 1,060,482,246 1,052,196,121 1,044,241,441 1,036,604,948
COSTS ($):
ON-PEAK 0 0 0 5,039,993 5,124,823 14,736,021 15,074,571 15,453,950 21,377,678 21,736,082 22,205,468 22,517,235 23,282,532 24,456,021
OFF-PEAK 0 0 0 3,664,727 3,726,409 10,714,993 10,961,163 11,237,020 15,544,337 15,804,943 16,146,247 16,372,942 16,929,412 17,782,690
TOTAL 0 0 0 8,704,720 8,851,232 25,451,014 26,035,734 26,690,970 36,922,015 37,541,025 38,351,715 38,890,177 40,211,944 42,238,711
BALANCE (KWH):
ON-PEAK 0 809,620,718 807,249,324 779,761,413 792,891,605 573,001,889 541,977,290 507,860,739 419,385,015 426,206,986 397,960,155 359,238,541 318,899,650 326,996,801
OFF-PEAK 0 462,037,456 460,684,140 415,369,844 424,962,127 271,983,547 273,392,985 254,834,935 141,680,202 154,350,670 164,695,507 166,292,534 146,997,896 151,618,809
TOTAL 0 1,271,658,175 1,267,933,465 1,195,131,257 1,217,853,733 844,985,436 815,370,275 762,695,674 561,065,217 580,557,656 562,655,662 525,531,074 465,897,546 478,615,610
PG&E CCA_Marin_Jan_05 Annual Summary 13 5
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOU
51% RENEWABLE ENERGY
CATEGORY
SECTION III - PROJECTED RESOURCES:
(A) RENEWABLE PORTFOLIO STANDARD (KW
ON-PEAK
OFF-PEAK
TOTAL
COSTS ($):
ON-PEAK
OFF-PEAK
TOTAL
(B) CDWR CONTRACT ENERGY (KWH):
ON-PEAK
OFF-PEAK
TOTAL
COSTS ($):
ON-PEAK
OFF-PEAK
TOTAL
BALANCE (KWH):
ON-PEAK
OFF-PEAK
TOTAL
(C) POWER PRODUCTION (KWH):
ON-PEAK
OFF-PEAK
TOTAL
COSTS ($):
ON-PEAK
OFF-PEAK
TOTAL
BALANCE (KWH):
ON-PEAK
OFF-PEAK
TOTAL
[15] [16] [17] [18] [19] [20]
2019 2020 2021 2022 2023 2024
209,432,774 222,189,996 234,914,460 247,614,639 260,298,774 272,974,887
61,279,979 69,197,811 77,071,449 84,906,748 92,709,391 100,484,896
270,712,753 291,387,808 311,985,909 332,521,387 353,008,165 373,459,783
19,304,423 20,868,392 21,613,876 22,845,042 24,961,237 27,724,270
5,633,052 6,479,861 7,068,978 7,808,230 8,860,999 10,171,484
24,937,475 27,348,253 28,682,853 30,653,272 33,822,236 37,895,754
$101
000000
000000
000000
000000
000000
000000
931,160,306 935,427,345 939,982,505 944,821,145 949,938,911 955,331,727
589,638,054 591,435,692 593,423,257 595,597,078 597,953,692 600,489,833
1,520,798,361 1,526,863,037 1,533,405,762 1,540,418,223 1,547,892,603 1,555,821,560
595,944,897 591,870,048 587,958,192 584,202,811 580,597,645 577,136,686
433,329,018 430,366,076 427,521,651 424,791,003 422,169,581 419,653,016
1,029,273,915 1,022,236,123 1,015,479,843 1,008,993,814 1,002,767,226 996,789,702
25,483,070 26,011,700 26,099,784 26,475,798 27,292,460 28,382,582
18,529,488 18,913,870 18,977,918 19,251,329 19,845,148 20,637,808
44,012,559 44,925,571 45,077,702 45,727,127 47,137,608 49,020,390
335,215,410 343,557,297 352,024,313 360,618,334 369,341,266 378,195,041
156,309,036 161,069,617 165,901,606 170,806,075 175,784,111 180,836,817
491,524,446 504,626,914 517,925,919 531,424,409 545,125,376 559,031,858
PG&E CCA_Marin_Jan_05 Annual Summary 13 6
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOURCES
51% RENEWABLE ENERGY
[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]
CATEGORY 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
(D) LONG-TERM CONTRACT PURCHASES (KWH):
ON-PEAK 0 710,080,000 710,080,000 710,080,000 710,080,000 456,480,000 456,480,000 456,480,000 456,480,000 456,480,000 355,040,000 355,040,000 355,040,000 355,040,000
OFF-PEAK 0 295,040,000 295,040,000 258,160,000 258,160,000 73,760,000 73,760,000 73,760,000 73,760,000 73,760,000 0000
TOTAL 0 1,005,120,000 1,005,120,000 968,240,000 968,240,000 530,240,000 530,240,000 530,240,000 530,240,000 530,240,000 355,040,000 355,040,000 355,040,000 355,040,000
COSTS ($):
ON-PEAK 0 50,482,630 50,482,630 53,394,338 53,394,338 37,128,268 37,128,268 37,128,268 37,128,268 37,128,268 30,607,467 30,607,467 30,607,467 30,607,467
OFF-PEAK 00000000000000
TOTAL 0 50,482,630 50,482,630 53,394,338 53,394,338 37,128,268 37,128,268 37,128,268 37,128,268 37,128,268 30,607,467 30,607,467 30,607,467 30,607,467
BALANCE (KWH):
ON-PEAK 0 99,540,718 97,169,324 69,681,413 82,811,605 116,521,889 85,497,290 51,380,739 (37,094,985) (30,273,014) 42,920,155 4,198,541 (36,140,350) (28,043,199)
OFF-PEAK 0 166,997,456 165,644,140 157,209,844 166,802,127 198,223,547 199,632,985 181,074,935 67,920,202 80,590,670 164,695,507 166,292,534 146,997,896 151,618,809
TOTAL 0 266,538,175 262,813,465 226,891,257 249,613,733 314,745,436 285,130,275 232,455,674 30,825,217 50,317,656 207,615,662 170,491,074 110,857,546 123,575,610
(E) SHORT-TERM CONTRACT PURCHASES (KWH):
ON-PEAK 00000000000000
OFF-PEAK 00000000000000
TOTAL 00000000000000
COSTS ($):
ON-PEAK 00000000000000
OFF-PEAK 00000000000000
TOTAL 00000000000000
BALANCE (KWH):
ON-PEAK 0 99,540,718 97,169,324 69,681,413 82,811,605 116,521,889 85,497,290 51,380,739 (37,094,985) (30,273,014) 42,920,155 4,198,541 (36,140,350) (28,043,199)
OFF-PEAK 0 166,997,456 165,644,140 157,209,844 166,802,127 198,223,547 199,632,985 181,074,935 67,920,202 80,590,670 164,695,507 166,292,534 146,997,896 151,618,809
TOTAL 0 266,538,175 262,813,465 226,891,257 249,613,733 314,745,436 285,130,275 232,455,674 30,825,217 50,317,656 207,615,662 170,491,074 110,857,546 123,575,610
PG&E CCA_Marin_Jan_05 Annual Summary 13 7
COUNTY OF MARIN
FINANCIAL PRO FORMA ANALYSIS
ANNUAL LOADS AND COMPOSITION OF RESOU
51% RENEWABLE ENERGY
CATEGORY
(D) LONG-TERM CONTRACT PURCHASES (KW
ON-PEAK
OFF-PEAK
TOTAL
COSTS ($):
ON-PEAK
OFF-PEAK
TOTAL
BALANCE (KWH):
ON-PEAK
OFF-PEAK
TOTAL
(E) SHORT-TERM CONTRACT PURCHASES (KW
ON-PEAK
OFF-PEAK
TOTAL
COSTS ($):
ON-PEAK
OFF-PEAK
TOTAL
BALANCE (KWH):
ON-PEAK
OFF-PEAK
TOTAL
[15] [16] [17] [18] [19] [20]
2019 2020 2021 2022 2023 2024
355,040,000 355,040,000 355,040,000 355,040,000 355,040,000 355,040,000
000000
355,040,000 355,040,000 355,040,000 355,040,000 355,040,000 355,040,000
30,607,467 35,796,698 35,796,698 35,796,698 35,796,698 35,796,698
000000
30,607,467 35,796,698 35,796,698 35,796,698 35,796,698 35,796,698
(19,824,590) (11,482,703) (3,015,687) 5,578,334 14,301,266 23,155,041
156,309,036 161,069,617 165,901,606 170,806,075 175,784,111 180,836,817
136,484,446 149,586,914 162,885,919 176,384,409 190,085,376 203,991,858
000000
000000
000000
000000
000000
000000
(19,824,590) (11,482,703) (3,015,687) 5,578,334 14,301,266 23,155,041
156,309,036 161,069,617 165,901,606 170,806,075 175,784,111 180,836,817
136,484,446 149,586,914 162,885,919 176,384,409 190,085,376 203,991,858
PG&E CCA_Marin_Jan_05 Annual Summary 13 8
101
Appendix F – Pro Forma Summary With Alternative Supply Portfolios
Alternative Scenario 1 – Millions of Dollars
Year
Commodity
Costs
Reserves
and ISO
Charges
Operations
&
Scheduling
Non-
bypassable
Charges
Metering
& Billing
Financing
Costs
Total
Costs
PG&E
Charges Savings
Percentage
Of Total
Bill
2005 - - - - - - - - 0.0 0%
2006 77.6 5.7 3.6 25.1 1.1 1.4 114.4 107.2 (7.2) -4%
2007 79.5 5.9 3.7 23.7 1.1 1.2 115.0 109.1 (5.9) -3%
2008 81.6 6.1 3.8 24.1 1.1 1.2 117.9 113.1 (4.7) -2%
2009 85.1 6.6 3.8 16.9 1.2 1.2 114.9 115.9 1.1 1%
2010 99.9 7.0 3.9 15.5 1.2 1.3 128.8 121.8 (7.0) -3%
2011 103.7 7.5 3.9 15.9 1.3 1.3 133.7 125.7 (8.0) -4%
2012 106.5 7.8 4.0 16.4 1.3 1.3 137.3 129.9 (7.4) -3%
2013 108.9 8.1 4.0 7.3 1.4 1.3 131.1 123.3 (7.8) -3%
2014 111.3 8.4 4.1 7.4 1.5 1.3 134.0 126.9 (7.1) -3%
2015 124.1 8.8 4.1 7.5 1.5 1.3 147.3 131.3 (16.0) -7%
2016 126.4 9.0 4.1 7.7 1.6 0.3 149.0 134.5 (14.5) -6%
2017 131.2 9.5 4.1 7.8 1.6 0.6 154.7 141.2 (13.5) -5%
2018 139.1 10.3 4.1 7.9 1.7 0.6 163.6 151.5 (12.1) -4%
2019 146.3 10.9 4.1 8.0 1.8 0.6 171.7 160.9 (10.8) -4%
2020 161.8 11.3 4.1 8.1 1.8 0.7 187.8 166.2 (21.6) -7%
2021 162.5 11.5 4.1 8.2 1.9 0.7 188.9 167.7 (21.2) -7%
2022 165.1 11.8 4.1 7.9 2.0 0.7 191.6 171.5 (20.1) -7%
2023 170.8 12.4 4.1 - 2.1 0.7 190.1 171.8 (18.2) -6%
2024 178.6 13.1 4.1 - 2.2 0.8 198.7 182.2 (16.5) -5%
Total 2,360.1 171.9 75.4 215.4 29.4 18.3 2,870.5 2,651.8 (218.7) -5%
Alternative Scenario 2 – Millions of Dollars
Year
Commodity
Costs
Reserves
and ISO
Charges
Operations
&
Scheduling
Non-
bypassable
Charges
Metering
& Billing
Financing
Costs
Total
Costs
PG&E
Charges Savings
Percentage Of
Total Bill
2005 - - - - - - - - 0.0 0%
2006 74.2 5.7 3.6 25.1 1.1 1.2 110.8 107.2 (3.6) -2%
2007 75.6 5.9 3.7 23.7 1.1 1.4 111.3 109.1 (2.2) -1%
2008 77.2 6.1 3.8 24.1 1.1 1.2 113.4 113.1 (0.3) 0%
2009 80.3 6.6 3.8 16.9 1.2 1.2 110.0 115.9 5.9 3%
2010 98.4 7.0 3.9 15.5 1.2 1.3 127.3 121.8 (5.5) -3%
2011 101.8 7.5 3.9 15.9 1.3 1.3 131.7 125.7 (6.1) -3%
2012 104.2 7.8 4.0 16.4 1.3 1.3 135.0 129.9 (5.1) -2%
2013 106.3 8.1 4.0 7.3 1.4 1.3 128.5 123.3 (5.2) -2%
2014 108.5 8.4 4.1 7.4 1.5 1.3 131.2 126.9 (4.3) -2%
2015 124.6 8.8 4.1 7.5 1.5 1.3 147.8 131.3 (16.5) -7%
2016 126.6 9.0 4.1 7.7 1.6 0.3 149.2 134.5 (14.7) -6%
2017 130.4 9.5 4.1 7.8 1.6 0.6 153.9 141.2 (12.7) -5%
2018 136.0 10.3 4.1 7.9 1.7 0.6 160.5 151.5 (9.0) -3%
2019 141.3 10.9 4.1 8.0 1.8 0.6 166.7 160.9 (5.8) -2%
2020 160.4 11.3 4.1 8.1 1.8 0.7 186.4 166.2 (20.2) -7%
2021 161.8 11.5 4.1 8.2 1.9 0.7 188.2 167.7 (20.5) -7%
2022 164.2 11.8 4.1 7.9 2.0 0.7 190.7 171.5 (19.3) -6%
2023 168.6 12.4 4.1 - 2.1 0.7 187.8 171.8 (16.0) -5%
2024 174.3 13.1 4.1 - 2.2 0.8 194.4 182.2 (12.2) -4%
Total 2,314.8 171.9 75.4 215.4 29.4 18.3 2,825.2 2,651.8 (173.4) -4%
102
Alternative Scenario 3 – Millions of Dollars
Year
Commodity
Costs
Reserves
and ISO
Charges
Operations
&
Scheduling
Non-
bypassable
Charges
Metering
& Billing
Financing
Costs
Total
Costs
PG&E
Charges Savings
Percentage
Of Total Bill
2005 - - - - - - - - 0.0 0%
2006 77.6 5.7 3.6 25.1 1.1 1.4 114.4 107.2 (7.2) -4%
2007 79.5 5.9 3.7 23.7 1.1 1.2 115.0 109.1 (5.9) -3%
2008 65.4 6.1 3.8 24.1 1.1 20.7 121.1 113.1 (8.0) -4%
2009 67.0 6.6 3.8 16.9 1.2 15.9 111.3 115.9 4.6 2%
2010 73.0 7.0 3.9 15.5 1.2 18.3 118.9 121.8 2.9 1%
2011 75.9 7.5 3.9 15.9 1.3 17.4 122.0 125.7 3.7 2%
2012 78.5 7.8 4.0 16.4 1.3 17.2 125.3 129.9 4.7 2%
2013 81.1 8.1 4.0 7.3 1.4 16.9 118.8 123.3 4.5 2%
2014 83.7 8.4 4.1 7.4 1.5 16.6 121.6 126.9 5.3 2%
2015 92.3 8.8 4.1 7.5 1.5 16.3 130.5 131.3 0.8 0%
2016 94.8 9.0 4.1 7.7 1.6 15.2 132.3 134.5 2.2 1%
2017 98.8 9.5 4.1 7.8 1.6 14.8 136.6 141.2 4.6 2%
2018 104.4 10.3 4.1 7.9 1.7 14.5 142.8 151.5 8.7 3%
2019 109.8 10.9 4.1 8.0 1.8 14.2 148.7 160.9 12.2 4%
2020 120.5 11.3 4.1 8.1 1.8 13.8 159.6 166.2 6.6 2%
2021 122.6 11.5 4.1 8.2 1.9 13.3 161.7 167.7 6.0 2%
2022 125.8 11.8 4.1 7.9 2.0 12.9 164.5 171.5 7.0 2%
2023 130.6 12.4 4.1 - 2.1 12.4 161.6 171.8 10.2 3%
2024 136.8 13.1 4.1 - 2.2 12.0 168.2 182.2 14.0 4%
Total 1,818.0 171.9 75.4 215.4 29.4 264.7 2,574.9 2,651.8 76.9 2%
Alternative Scenario 4 – Millions of Dollars
Year
Commodity
Costs
Reserves
and ISO
Charges
Operations &
Scheduling
Non-
bypassable
Charges
Metering
& Billing
Financing
Costs
Total
Costs
PG&E
Charges Savings
Percentage
Of Total Bill
2005 - - - - - - - - 0.0 0%
2006 74.2 5.7 3.6 25.1 1.1 1.2 110.8 107.2 (3.6) -2%
2007 75.6 5.9 3.7 23.7 1.1 1.4 111.3 109.1 (2.2) -1%
2008 71.7 6.1 3.8 24.1 1.1 10.9 117.7 113.1 (4.6) -2%
2009 73.6 6.6 3.8 16.9 1.2 8.5 110.6 115.9 5.3 3%
2010 77.1 7.0 3.9 15.5 1.2 12.2 117.0 121.8 4.9 2%
2011 80.1 7.5 3.9 15.9 1.3 12.1 120.8 125.7 4.9 2%
2012 82.9 7.8 4.0 16.4 1.3 11.9 124.3 129.9 5.6 2%
2013 85.5 8.1 4.0 7.3 1.4 11.7 118.0 123.3 5.2 2%
2014 88.0 8.4 4.1 7.4 1.5 11.5 120.9 126.9 5.9 3%
2015 97.6 8.8 4.1 7.5 1.5 11.4 130.8 131.3 0.5 0%
2016 99.9 9.0 4.1 7.7 1.6 10.3 132.5 134.5 2.0 1%
2017 104.2 9.5 4.1 7.8 1.6 10.1 137.3 141.2 3.9 2%
2018 110.5 10.3 4.1 7.9 1.7 9.9 144.4 151.5 7.2 3%
2019 116.4 10.9 4.1 8.0 1.8 9.7 150.9 160.9 10.0 3%
2020 128.1 11.3 4.1 8.1 1.8 9.5 162.9 166.2 3.3 1%
2021 129.7 11.5 4.1 8.2 1.9 9.2 164.6 167.7 3.0 1%
2022 132.6 11.8 4.1 7.9 2.0 8.9 167.4 171.5 4.1 1%
2023 137.7 12.4 4.1 - 2.1 8.6 164.9 171.8 6.9 2%
2024 144.4 13.1 4.1 - 2.2 8.3 172.1 182.2 10.1 3%
Total 1,909.7 171.9 75.4 215.4 29.4 177.5 2,579.4 2,651.8 72.4 2%
103
Appendix G – Electric Customers and Load Analysis
County of Marin
Electric Demand and Energy Consumption
3
Peak Day Load
0
50
100
150
200
2501:003:005:007:009:0011:0013:0015:0017:0019:0021:0023:00MWStreet Lights Industrial Large Commercial
Medium Commercial Small Commercial Residential
Annual Energy Consumption
51%
16%
15%
7%
10%1%
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
300,000.0
kWCounty of Marin
Maximum & Minimum Weeks
6
County of Marin Load Plots and Power Blocks
9
Second Quarter
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
11223344556677889100111122133144155166kWThird Quarter
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
110192837465564738291100109118127136145154163kWFourth Quarter
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
110192837465564738291100109118127136145154163kWQuarter 7X24 6X16 Dumped kWh Req. kWh Qtr % kWk
1 100000 65000 3,849,312 355,355,346 1.08%
2 100000 70000 10,773,882 324,932,964 3.32%
3 100000 75000 8,856,809 349,194,085 2.54%
4 90000 65000 2,958,093 349,246,878 0.85%
26,438,095 1,378,729,272 1.92%
Energy Purchases (kWh)
7X24 853,920,000 60.8%
6X16 338,960,000 24.1%
Spot On-Peak 93,688,355 6.7%
Spot Off-Peak 118,599,012 8.4%
Total 1,405,167,367 100.0%
Total Energy Spot Purchases
1,378,729,272 15.1%
First Quarter
0.0
50,000.0
100,000.0
150,000.0
200,000.0
250,000.0
11325374961738597109121133145157kW
104
Appendix H – Implementation Schedule
The County could begin providing electric service to customers in the
community as early as 2006 by following the timeline shown below:
COMMUNITY CHOICE AGGREGATION IMPLEMENTATION PROCESS
AND TIMELINE
TASK ESTIMATED START
DATE
1 Feasibility Assessment and Evaluation 3/10/05 – 5/7/05
1.1 Review Final Feasibility Report 3/10/05
1.2 Conduct Public Workshop(s) and council
sessions to consider proceeding to
implementation
4/14/05
1.3 Decision to Develop CCA Implementation
Plan
5/7/05
2 Implementation Plan Development 5/14/05 – 7/30/05
2.1 Obtain Billing Data From Utility 5/28/05
2.2 Issue Request For Qualifications/Offers To
Suppliers
6/4/05
2.3 Identify uncommitted generation projects
and negotiate participation, if applicable
6//4/05
2.4 Develop program structure, organization,
operations plans and funding
6/11/06
2.5 Document participant rights and
responsibilities
6/11/05
2.6 Select Preferred electric supplier(s) and 6/25/05
105
TASK ESTIMATED START
DATE
partners; Evaluate and document their
financial, technical and operational
capabilities
2.7 Develop preliminary energy supply
resource portfolio
6/25/05
2.8 Perform Rate Design (cost allocation
methodology and disclosure)
7/2/05
2.9 Complete Draft Implementation Plan 7/9/05
2.10 Conduct Public Workshop(s) on Draft
Implementation Plan
7/16/05
2.11 Issue Resolution Adopting Implementation
Plan
7/30/05
3 CPUC Implementation Plan Filing 8/6/05 – 11/5/05
3.1 File Implementation Plan and Statement of
Intent with CPUC
8/6/05
3.2 Respond to information requests from
CPUC or intervenors
8/13/05
3.3 Participate as required in CPUC process to
support implementation plan
8/13/05
3.4 Monitor CPUC decisions 11/5/05
4 Initiate CCA Startup Activities 8/13/05 – 12/10/05
4.1 Conduct Recruiting and Staffing
106
TASK ESTIMATED START
DATE
4.2 Develop informational and program
marketing materials
8/13/05
4.3 Establish call center for customer inquiries 8/20/05
4.4 Develop in house capabilities or execute
contracts for performance of operational
services:
8/20/05
- Electronic data interchange with utility -
- Customer bill calculations -
- Scheduling coordinator services -
- Application of statistical load profiles
and submittal of hourly usage data for
CAISO settlements
-
- Resource planning, portfolio and risk
management
-
- Ratemaking -
- Load forecasting -
- Wholesale settlements -
- Credit and finance -
- Information Technology -
- Legal and regulatory support -
4.5 Contact key customers to explain program,
obtain commitment, and release customer
information
8/27/05
4.6 Execute contracts for electric supply 11/12/05
4.7 Update program rates 11/12/05
4.8 Obtain financing for program capital 11/12/05
107
TASK ESTIMATED START
DATE
requirements
4.9 Execute service agreement with utility16 11/19/05
4.10 Complete utility technical testing 11/26/05
4.11 Establish account with utility 12/3/05
4.12 Register with CPUC, post bond or
demonstrate insurance
12/10/05
5 Customer Notification and Enrollment 12/17/05 – 2/19/06
5.1 Send first opt-out notice to eligible and
ineligible customers
12/17/05
5.2 Send second opt-out notice to eligible and
ineligible customers
1/21/06
5.3 Process customer opt-out requests and
enroll customers
1/28/06
5.4 Submit notification certification to CPUC 2/5/06
5.5 Notify utility when CCA service will begin
to initiate account transfer
2/5/06
5.6 Obtain updated billing data from utility 2/12/06
5.7 Update load forecasts and supply plan 2/19/06
6 CCA Operations 3/2/06 – Ongoing
6.1 Activate energy supply resource plan 2/2/06
6.2 Commence mass account transfer 3/3/06
16 The City, as a CCA operator, will need to establish a legal relationship with PG&E. It is
anticipated that a service agreement will include processes for information exchange including
electronic data interchange, procedures for settling financial transactions, treatment of customer
bill payment funds transfer, credit terms, access to confidential customer information, audit
provisions, and regulatory oversight and complaint processes.
108
TASK ESTIMATED START
DATE
6.3 Manage supply portfolio and risk
management (ongoing)
3/3/06
- Prepare daily load forecasts 3/3/06
- Balance portfolio with purchases and
sales
3/3/06
- Schedule loads and resources 3/3/06
- Monitor credit of suppliers and mark to
market exposure
3/3/06
- Maintain risk controls on supply
portfolio
3/3/06
6.4 Perform Account Management, Billing and
Settlements (ongoing)
3/3/06
- Process customer transfers into and out
of program
3/4/06
- Receive and respond to customer
inquiries
3/4/06/
- Pay electric suppliers 3/19/06
- Obtain customer meter data from IOU 4/2/06
- Prepare bill calculations 4/2/06
- Provide bill amounts to IOU 4/2/06
- Apply statistical load profiles to meter
data and submit to ISO for settlement
4/2/06
- Pay IOU transaction fees 4/2/06
- Receive remittances from IOU from
customer collections
4/19/06
- Verify ISO settlement statements and 5/6/06
109
TASK ESTIMATED START
DATE
pay ISO charges
6.5 Distribute third opt-out notice 4/2/06
6.6 Complete mass account transfer 4/2/06
6.7 Process opt-outs 4/3/06
6.8 Prepare operating statements and financial
reports (ongoing)
4/19/06
6.9 Distribute fourth opt-out notice 5/6/06
6.10 Process opt-outs 5/7/06