HomeMy WebLinkAboutCCA Pilot Project Appendix G Guidebook (4f. )1!
6 #'• ,
Arnold Schwarzenegger
Governor
COMMUNITY CHOICE AGGREGATION
PILOT PROJECT
APPENDIX G
GUIDEBOOK
I
oC
0
a
w
GC
0
w
0
la-
J
LL
Prepared For: w
California Energy Commission
Public Interest Energy Research Program
Prepared By:
Local Government Commission
Navigant Consulting, Inc.
September 2009
CEC-500-2009-003
Prepared By:
Local Government Commission
G. Patrick Stoner
Sacramento, California 95814
Navigant Consulting, Inc.
John Dalessi
Rancho Cordova, California 95670
Contract No. 500-03-004
Prepared For:
Public Interest Energy Research (PIER) Program
California Energy Commission
Hassan Mohammed
Contract Manager
Kenneth Koyama
Office Manager
Energy Generation Research
Thom Kelly, Ph.D.
Deputy Director
ENERGY RESEARCH& DEVELOPMENT DIVISION
EJ e i Melissa Jones
"""�"" "DOW"�"`" Executive Director
"Research Powers the future"
DISCLAIMER
This report was prepared as the result of work sponsored by the California Energy Commission. It does not necessarily represent the views of the
Energy Commission, its employees or the State of California. The Energy Commission, the State of California, its employees, contractors and
subcontractors make no warrant, express or implied, and assume no legal liability for the information in this report; nor does any party represent
that the uses of this information will not infringe upon privately owned rights. This report has not been approved or disapproved by the California
Energy Commission nor has the California Energy Commission passed upon the accuracy or adequacy of the information in this report.
Preface
The California Energy Commission's Public Interest Energy Research (PIER) Program
supports public interest energy research and development that will help improve the
quality of life in California by bringing environmentally safe, affordable, and reliable
energy services and products to the marketplace.
The PIER Program conducts public interest research, development, and demonstration
(RD&D) projects to benefit California.
The PIER Program strives to conduct the most promising public interest energy research
by partnering with RD&D entities, including individuals,businesses, utilities, and
public or private research institutions.
• PIER funding efforts are focused on the following RD&D program areas:
• Buildings End-Use Energy Efficiency
• Energy Innovations Small Grants
• Energy-Related Environmental Research
• Energy Systems Integration
• Environmentally Preferred Advanced Generation
• Industrial/Agricultural/Water End-Use Energy Efficiency
• Renewable Energy Technologies
• Transportation
California Community Choice Aggregation Guide is the interim report for the Community
Choice Aggregation Pilot Program project (Contract Number 500-03-004) conducted by
the Local Government Commission. The information from this project contributes to
PIER's Renewable Energy Technologies Program.
For more information about the PIER Program, please visit the Energy Commission's
website at www.energy.ca.gov/pier or contact the Energy Commission at 916-654-5164.
Please cite this report as follows:
Stoner, G. Patrick,John Dalessi, 2009. California Community Choice Aggregation Guide.
California Energy Commission, PIER Renewable Energy Technologies Program. CEC-
500-2009-003.
Table of Contents
Preface i
Abstract v
1.0 Introduction to Community Choice Aggregation 1
1.1. Purpose 1
1.2. Community Choice Aggregation Program Overview 1
1.3. Section Summary 1
1.4. What Is Community Choice Aggregation? 2
1.5. Why Are Cities and Counties Investigating Community Choice Aggregation
in California? 2
1.6. Responsibilities of Community Choice Aggregators and Investor-Owned
Utilities 3
1.7. Community Choice Aggregation Is Not Municipalization 4
1.8. Aggregation in Other States 5
1.9. Why Was AB 117 Enacted? 5
1.10. What Are the Rules for Implementing Community Choice Aggregation? 6
1.11. California Public Utilities Commission's Decision on Community Choice
Aggregation Implementation 7
1.12. What Is the Legal Process for Becoming a Community Choice Aggregator? 9
2.0 Investigating Community Choice Aggregation Feasibility 11
2.1. Section Summary 11
.1111131011 2.2. What are the Potential Benefits of Community Choice Aggregation? 12
2.3. What are the Potential Risks of CCA? 18
2.4. What are the Elements of a Community Choice Aggregation Program? 25
2.5. Deciding Community Procurement Objectives 30
2.6. Getting the Necessary Data 31
2.7. Evaluating the Data 32
2.8. To Build or Not to Build? 46
2.9. Sample Feasibility Study 47
3.0 Developing a Community Choice Aggregation Implementation Plan 49
3.1. Section Summary 49
3.2. Implementation Plan and Statement of Intent Requirements.. 50
3.3. Deciding Whether to Join With Other Communities 50
iii
3.4. Implementation Models 56
3.5. Getting Quotes from Suppliers and Operators 57
3.6. Phasing? 58
3.7. Developing a Marketing Campaign 58
3.8. Requirements After Filing the Implementation Plan 60
3.9. Model Implementation Plan 60
4.0 Glossary of Terms 61
Appendix A Sample Data Request Letters
Appendix B Key Assumptions Used in CCA Feasibility Analysis and Modeling for the
California Energy Commission Pilot Project Feasibility Studies
Appendix C Alternative Financing Methods
List of Figures
Figure 2.1: Supply portfolio matched to load shape 26
Figure 2-2. Prototypical annual load profile 39
Fig 2-3. Northern California market price projections for renewable and conventional
electricity 44
List of Tables
Table 2-1. Risk management strategies 23
Table 2-2. Rate Schedule to Customer Sector Assignment 37
Table 2-3. Static Load Profile Assignment 38
Table 2-4. Forecast number of accounts and annual energy sales 38
Table 2-5. Renewable resource technologies expected to fulfill the California Renewables
Portfolio Standard (2003 Dollars) 43
Table 2-6. Cost comparison—IOU vs. CCA ownership of a 100 MW wind resource
(Thousand of Dollars) 45
Table 2-7. Sample summary of electric cost savings from community choice aggregation
(Millions of Dollars) 47
iv
Abstract
Community choice aggregation (CCA) is authorized in California by Assembly Bill AB
117(Migden, Chapter 836, Statutes of 2002), which allows cities, counties, and groups of
cities and counties to aggregate the electric load of the residents,businesses, and
institutions within their jurisdictions to provide them electricity. The California Public
Utilities Commission has developed rules for implementing community choice
aggregation. Communities wishing to form a community choice aggregation program
must file an implementation plan with the California Public Utilities Commission. A
feasibility study will help determine whether community choice aggregation is a viable
option for achieving community goals such as lower electric rates or higher renewable
energy generation. This guidebook will assist local governments interested in
establishing community choice aggregation programs. The guidebook provides
information on meeting the requirements of the California Public Utilities Commission
for community choice aggregation formation, undertaking feasibility studies and filing
an implementation plan.
Keywords: community choice aggregation, CCA, electricity generation, renewable
energy, AB 117, implementation plan
V
1.0 Introduction to Community Choice Aggregation
1.1. Purpose
This guidebook was developed to assist local governments interested in establishing a
community choice aggregation (CCA) program. CCA allows a city or county or group of
cities and counties to provide electricity for their constituents.
The book is funded by the U.S. Department of Energy and the California Energy
Commission's Public Interest Energy Research (PIER) Program under a contract to
investigate CCA feasibility and increased renewable energy development in California.
The Local Government Commission is the main contractor and Navigant Consulting,
Inc., is the technical consultant to the project.
The guidebook is divided into three sections, followed by appendices.
The first section includes provisions of the legislation enabling CCA and the California
Public Utilities Commission's (CPUC) decisions implementing the law.
The second section provides information on what a community needs to do to
investigate CCA.
The third section helps communities develop a CCA implementation plan.
The appendices include sample data request letters, the list of key assumptions used in
the preliminary feasibility studies completed under this contract, and a table of CCA
financing options.
1.2. Community Choice Aggregation Program Overview
Community choice aggregation includes electric power generation services only.The
investor-owned utilities (IOUs) will continue to deliver the power over their
transmission and distribution lines. All IOU customers within a CCA's territory have the
option of buying electricity from the CCA or remaining as generation customers of the
IOU by exercising their rights to opt out of the program.
1.3. Section Summary
Legislation was passed in 2002 that allows cities, counties, or groups of them to provide
electricity to all of the customers within their jurisdictions by becoming community
choice aggregators. Local governments can combine (aggregate) the electric loads of
their constituents in order to produce or purchase electricity in bulk at a lower cost. All
constituents are automatically customers of the CCA unless they opt out of the program
and remain customers of their utility, Pacific Gas and Electric (PG&E), Southern
California Edison (SCE), or San Diego Gas & Electric (SDG&E).
Local governments are interested in forming CCAs to have more control over the
electricity consumed in their communities. They want to decide the type of electricity
generated (many are interested in increasing the amount of renewable energy), and they
1
want to control electric rates (most expect to charge less than the utilities). Other
potential benefits include increased reliability and greater emphasis on energy
efficiency.
CCAs will not be municipal utilities. They will not own the poles and wires; they will
only provide the electricity itself. The investor-owned utilities will continue to deliver
the electricity over their poles and wires. The IOUs will also provide customer service,
meter reading, and billing.
Community choice programs exist in Ohio, Massachusetts, and Rhode Island. None is
exactly like California's program. However, they all have been able to reduce rates for
their customers.
CCA legislation has specific requirements for communities seeking to establish CCA
programs, and the CPUC has developed procedures for doing so. A local government
wishing to establish a CCA program must adopt a resolution stating that intent, and file
an Implementation Plan with the CPUC.
1.4. What Is Community Choice Aggregation?
Assembly Bill 117 (Migden, Chapter 838, Statutes of 2002) grants cities and counties the
authority to provide electricity for customers within their communities. They are
permitted to aggregate (that is, combine) the loads of retail customers of the IOUs within
their boundaries for the purchase and sale of electricity. A CCA will choose the electric
power generation supply that will serve the community and set its own rates for that
power.
All customers, including residential, commercial, and industrial, currently receiving
electric service from an IOU, will be automatically enrolled in a CCA program, unless
the customer notifies the CCA of its desire to opt out. Customers who chose to opt out
remain generation customers of the IOU.
The CPUC was designated to decide how to implement AB 117 and established a
rulemaking proceeding to do so.
1.5. Why Are Cities and Counties Investigating Community
Choice Aggregation in California?
There are numerous benefits offered by CCA, primarily local control over the energy
resources used by the community and the potential to provide electricity to customers at
a lower overall cost.
Through CCA, a local government can develop a generation portfolio that diversifies
fuel and technology types, improves the environment, and is more stable in cost. The
CCA can choose to develop its own energy resources and thereby decide which
resources will be developed and where.
2
A CCA can implement an aggressive program to increase the use of renewable energy
and to promote energy efficiency. A CCA's local perspective and its primary mission to
serve its constituents rather than maximize profits for shareholders places it in a position
to implement energy efficiency programs in order to lower overall energy costs for the
community, and/or develop potentially more expensive renewable energy projects to
meet local demand.
Electricity suppliers will compete for the right to serve a CCA's load. California's
experience with electric choice showed that suppliers were willing to offer discounts to
large customers. For the most part, however, discounted rates were not offered to
residential customers because of their relatively small loads compared to high marketing
and transactions costs. The opt out feature of CCA eliminates most of the high
marketing and transaction costs, which limited opportunities for residential and small
commercial customers in the earlier de-regulated market that required opting into an
aggregation plan.
Through community aggregation, small customers can obtain competitive electricity
supplies directly from the wholesale market on a scale that was not feasible under
previous direct access rules. Combining their individual loads makes small customers
more attractive to electricity suppliers, especially when commercial and industrial loads
are added. Cost savings can be passed on to customers through lower electric bills or can
be used by the local governments to provide enhanced services to their constituents.
Other potential benefits include:
• Increased reliability of power supply.
• Customer access to democratically elected or appointed representatives and
fiscal accountability.
• Development of energy rates for small business and incentives for community
business retention and expansion.
• New revenue stream to the General Fund.
• Access to electric public good funds programs available to implement energy
efficiency and conservation, which can create new local jobs and support the
local economy.
For a more detailed discussion of benefits see Section 2.2.
1.6. Responsibilities of Community Choice Aggregators and
Investor-Owned Utilities
A CCA will secure electricity for its customers under contracts for power or from its
own power generation plants. The local IOU is required to provide delivery services
over its existing transmission and distribution systems and to provide metering,billing,
collection, and all traditional retail customer services (i.e., call centers, outage
restoration, extension of new service). The IOUs will also continue to be responsible for
3
the operation and maintenance of the transmission and distribution system that delivers
electricity to residences and businesses.
The IOUs must deliver electricity to CCA customers under the same terms and
conditions that they provide to their other customers. Customers of a CCA will pay the
same charges for delivery services as customers that remain as full service, or bundled
customers of the IOU. These delivery charges represent approximately one half of a
typical household monthly electric bill.
A CCA customer will see no difference in service and will continue to receive a single
bill for electricity, issued by and paid to the IOU. The IOU will collect the CCA's charges
from its customers and transfer the collected funds to the CCA.
The IOU is authorized to assess a surcharge for some of its generation-related costs that
were incurred on behalf of CCA customers prior to its creation and that might otherwise
be shifted to the IOU's remaining customers. This surcharge is known as the cost
responsibility surcharge, or CRS, and will be regulated by the CPUC. The CRS is
discussed in greater detail in Section 1.11.
1.7. Community Choice Aggregation Is Not Municipalization
It is important to distinguish a CCA from a municipal utility and from an energy service
provider. Each of these entities provides different services, has different responsibilities,
and operates under different regulatory frameworks.
Forming a municipal electric utility, or municipalization, means replacing the existing
IOU with a locally owned utility that provides both generation and delivery services.
This includes the distribution system (i.e., the poles and wires) to deliver the power. A
new municipal utility, or one expanding its territory, must either build this distribution
system or acquire it through condemnation by eminent domain of the wires and poles of
the IOU. This is an expensive and time-consuming process.
CCA allows local governments to provide generation services, control the content of the
power supply, and set rates without having to provide delivery services or taking on the
burden of managing a transmission and distribution system. A local government that
implements a CCA program will procure electric power from wholesale markets or its
own generation facilities. The local IOU will deliver that power to the CCA end-use
customer across its transmission and distribution facilities.
An energy service provider (ESP) is a third party contractor that specializes in the
business of energy purchases and sales and energy efficiency programs in a competitive
market. An ESP must be registered with the CPUC as an authorized dealer of energy
services. ESPs were authorized to sell electricity directly to customers after California
deregulation instituted direct access. Direct access is the term used for electric customers
who choose to purchase their electric commodity from a supplier other than their local
investor-owned utility. Aggregating smaller customers was difficult for ESPs under the
original deregulation scheme as each one had to choose to join the aggregation.
4
With the energy crisis of 2000-2001, new direct access service was suspended. Although
no new direct access customers can be established and served by ESPs at this time, ESPs
continue to operate in California for the customers they already had. ESPs are expected
to be available as third-party contractors who could provide operations services for a
CCA if they so choose.
1.8. Aggregation in Other States
Community choice programs currently operate in Ohio, Massachusetts, and Rhode
Island. Following energy deregulation in Ohio, for example, around 90% of the
residential and commercial customers who switched from their resident utilities did so
to join a community choice program. The Northeast Ohio Public Energy Council
(NOPEC) is the largest public aggregation program in the state with 118 member cities
serving over 600,000 customers. Benefits to CCA customers are significant in this
instance, as NOPEC's energy supply contract guarantees a discount ranging from 4-6%
when compared with IOU rates. (www.nopecinfo.org)
In Massachusetts, the Cape Light Compact is a regional services organization made up
of Barnstable and Dukes counties and all 21 towns of Cape Cod and Martha's Vineyard.
The purpose of the compact is to represent and protect the interests of the nearly 200,000
customers in the region, and to negotiate lower cost electricity and other public benefits.
(www.capelightcompact.org)
The Rhode Island Energy Aggregation Program is a consortium of 36 Rhode Island
communities, which are organized under the auspices of the Rhode Island League of
Cities and Towns for the purpose of purchasing the lowest cost electricity and other
services from power suppliers. While currently only available for municipal facilities,
the program saved its member cities and towns $2.685 million in the first four months of
2006. (www.rileague.org)
1.9. Why Was AB 117 Enacted?
Electric consumers were given a choice of electricity providers when the state
deregulated its power market in 1998. At that time, a local government could choose the
power supplier for its own operations. A few local governments chose renewable or
green power supplies. Overall, less than 3 percent of California customers switched
suppliers under this new deregulated market, largely because customers had to figure
out for themselves which service provider was best for them. And while local
governments could have aggregated their communities' loads, it would have been a
difficult process, as each customer would have had to opt in one by one.
The energy crisis of 2000-2001 changed the rules again. The state stepped in to purchase
power because California's two largest IOUs were on the verge of bankruptcy. Direct
access was suspended and California consumers were no longer allowed to choose
green power or any electricity provider other than their local, historical IOU. The only
way to exercise any choice was to install on-site resources, such as solar systems.
5
Now under AB 117, local governments can combine the electric loads of their
communities in a much more workable opt-out manner. They can have far greater
authority over the source of the electricity that serves not only their own operations, but
also the residents and businesses in their jurisdiction as well.
1.10. What Are the Rules for Implementing Community Choice
Aggregation?
AB 117 requires that:
• Cities, counties, or groups of cities and counties wishing to establish CCA
programs must do so by ordinance.
• CCA programs must offer electric service to all of their residential customers
(Commercial and industrial customers may be offered service, but a CCA is not
required to offer service to them).
• All CCA programs must offer a chance for their potential customers to opt out of
the program and remain IOU generation customers.
• CCAs must develop implementation plans detailing the process and
consequences of aggregation; the plans must contain all of the following:
o An organizational structure of the program, its operations, and funding.
c Rate-setting and other costs to participants.
o Provisions for disclosure and due process in setting rates and allocating
costs among participant.
o The methods for entering and terminating agreements with other entities.
o The rights and responsibilities of program participants, including
consumer protection procedures, credit issues, and shutoff procedures.
o Termination of the program.
o A description of the third parties supplying electricity including financial,
technical, and operational capabilities.
• A Statement of Intent must be filed with the implementation plan that addresses:
o Universal access.
o Reliability.
o Equitable treatment of all classes of customers.
c Any requirements established by state law or by the CPUC concerning
aggregated service.
• The CPUC must develop a cost-recovery mechanism paid by customers of the
CCA that will prevent shifting of costs to remaining IOU customers.
• The CPUC must set a date when a CCA program can commence.
• The IOUs must fully cooperate with any local governments that investigate,
pursue, or implement CCA programs.
6
The CPUC was tasked with developing the rules for CCA implementation. It initiated
Rulemaking 03-10-003 to do so. The rulemaking was split into two phases that were
decided in December 2004 (D.04-12-046) and December 2005 (D.05-12-041). The
decisions can be accessed at http://www.cpuc.ca.gov/ (click on "Online Documents,"
then "Final Decisions" and input the decision numbers above). Relevant portions of the
decisions are cited throughout this guidebook. For a more detailed summary of the
decisions, visit www.lgc.org/community/.
1.11. California Public Utilities Commission's Decision on
Community Choice Aggregation Implementation
One of the most significant outcomes of the Rulemaking is the limited jurisdiction the
CPUC has over the operations of CCAs. The CPUC's primary role is to regulate the
service the IOUs provide to CCAs and their customers. The decision states: "Nothing in
the statute directs the Commission [CPUC] to regulate the CCA's program except to the
extent that its program elements may affect utility [IOU] operations and the rates and
services to other customers."'
The CPUC has responsibility to ensure that a CCA's operations will not negatively
impact, financially or otherwise, the service provided to customers who remain with
IOUs. To that end, the CPUC will establish a cost responsibility surcharge for CCA
customers to protect the remaining IOU customers. CCAs will have to file
Implementation Plans and any other information requested by the CPUC to determine
the CRS.
The CPUC will also:
• Certify that a CCA has filed an implementation plan.
• Set a start date for when customers can be transferred to CCA service.
• Oversee the relationship between the IOU and the CCA.
Other significant CPUC decisions include:
• Access to Utility Data
Local governments investigating CCA have the right to detailed electric billing and load
data without it being masked in any way. The local government may be required to sign
confidentiality agreements with the IOU for certain data.
• Cost Responsibility Surcharge
Customers of a CCA program cannot escape paying for past costs incurred by the IOUs
or the Department of Water Resources (DWR) on behalf of the IOUs during the energy
crisis of 2000 and 2001. All customers of the IOUs during that time will continue to be
held responsible for those costs until they are paid off. Current IOU customers are
' California Public Utilities Commission Decision D.05-12-041,page 8.
7
paying for those costs as a part of their rates. As CCAs arc established, their share of
these costs will be collected in what is called the cost responsibility surcharge, or CRS.
The CRS will reflect the difference between the average portfolio price of electricity for
each of the IOUs (including DWR contracts, DWR bond costs, and IOU higher priced
contracts) and the market rate of electricity. As the market rate rises, the CRS declines.
The average portfolio price is figured with all IOU customers, including those leaving
for CCA service, and then compared to a market price formula using published
electricity prices. The difference in costs can be attributable to CCA formation and is
charged to CCA customers in the form of the CRS.
The CRS will be charged directly to customers, not to the CCA.
• Vintaging/Open Season
A CCA will be responsible for only those DWR and IOU liabilities that were current at
the time the CCA began its operations. There will be different CRS charges applicable to
CCAs depending on the year that a CCA begins serving customers. Thus, there will be
different vintages of CCA charges.
The CPUC has stated that IOUs should incorporate CCA load losses into their planning
efforts,just as they include any other forecast variable related to changes in supply or
demand.
The open season process is meant to mitigate costs incurred by CCAs and the IOUs, and
to provide a mechanism for coordinating the switching of customers. During the Open
Season, a CCA can commit to a date on which responsibility for customer power
purchases will switch from the IOU to the CCA. The CCA and the IOU will work jointly
to forecast the amount of load that will switch on that date.
If an open season collaborative forecasting process fails, the CPUC has developed
default opt out percentages for the first year of a CCA's operations of 5% for residential
customers and 20% for non-residential customers. The purpose of the default opt out
percentages is to estimate the cost to the IOU in the event a CCA misses its customer
transfer date.
Participating in the open season is strictly voluntary and will occur annually. The
decision permits negotiated agreements between a CCA and an IOU to assume some
liability for power purchase strategies in exchange for relief from other risks.
The CRS will be determined based on the IOU power supply portfolio that exists at
either the time the CCA begins serving customers or the date stated in a binding notice
of intent provided by a CCA in an open season process.
• Phase In
A CCA may want to consider phasing in service to its customers for various reasons.
First, phasing service can significantly reduce implementation risk by enabling a pilot
program to work out any glitches before rolling the program out to all customers.
8
Secondly, a phase in program can help eliminate potential cash flow problems that
might otherwise occur in the early years of CCA implementation.
The CPUC has stated that CCAs can legally phase in their programs. It also found that a
phase in or pilot program may impose additional costs on an IOU that can be recovered
in tariffs from the CCA. On the other hand, some phase in plans may reduce costs.
AB 117 does not prohibit a CCA from offering service to only a portion of the customers
in its jurisdiction, with the exception that it must offer service to all residential customers.
Presumably, the transfer of residential accounts could be phased in over time without
violating the residential must offer requirement.
• Implementation Plan
The CPUC will use the Implementation Plan in its determination of the CRS for each
CCA customer. The CPUC found nothing in the statute that directs it to approve or
disapprove an Implementation Plan or modifications to it. Nor does the statute provide
CPUC authority to de-certify a CCA or its Implementation Plan.
• Adding or Subtracting Communities in a CCA
Additions or deletions of cities or counties in a CCA program are permitted, but they
could affect IOU operations and costs that would affect the CRS.
• California Alternative Rate for Energy (CARE) Discount
The California Alternative Rate for Energy (CARE) discount provides reduced rates for
qualifying low-income customers. IOUs will continue to apply the CARE discount to all
qualifying CCA customers. The discount will be calculated using all elements of a
customer's bill, but the discount will be applied only to the delivery service rate. The
discount will not be reflected in the CRS. CCAs can design rates that provide additional
discounts if they choose.
• Future CCA Issues
Because CCA is a new program, the CPUC intends to initiate a new rulemaking
proceeding to review the program within a year of the initiation of the first CCA's
operation. In the meantime, CCAs and IOUs are encouraged to bring to the CPUC's
attention problems with existing tariffs, rules, or policies adopted in the Decisions. This
may be accomplished by consulting with the CPUC's technical staff or by filing petitions
to modify orders issued in this proceeding.
1.12. What Is the Legal Process for Becoming a Community
Choice Aggregator?
The process for becoming a CCA requires that the local government governing body(ies)
adopt an ordinance proclaiming their decision to become a CCA, and they must file an
Implementation Plan with the CPUC. A lot of time and effort should be spent before
making these decisions, and after they are made, before commencing operations.
9
The San Joaquin Valley Power Authority (SJVPA) is a joint powers agency of 14 cities
and counties in the Fresno Area. The SJVPA is the first entity in the state to file an
Implementation Plan with the CPUC. To see the SJVPA's implementation plan visit:
http://www.communitvchoice.info/sjvpa/documents.php
10
2.0 Investigating Community Choice Aggregation
Feasibility
2.1. Section Summary
Before undertaking the major steps associated with establishing a CCA program, a local
government must define its objectives and determine whether or not the CCA program
will help meet those objectives. It must also identify the expected benefits and risks of
CCA and balance them within the context of CCA. If the local government, after
carefully analyzing these considerations, finds that CCA will meet its objectives and will
result in benefits that outweigh risks, the potential CCA must gather and analyze the
necessary data to decide the financial and physical feasibility of the program. All this
should be done in the public eye to ensure community support behind whatever
decision is made.
This section of the guidebook kvi11 help communities navigate through and, ultimately,
complete this process.
Community choice aggregation can provide many potential benefits including customer
choice (CCA is currently the only way for a customer to choose any provider other than
the utilities), local accountability, reduced energy costs, price stability, increased use of
renewable energy, and increased energy efficiency.
CCA programs bear risks that are financial, political, administrative, and regulatory.
These risks can be mitigated, but not entirely eliminated, by sound management
practices. The major risk for a CCA program is the possibility that its rates will be higher
than the utility's. Utility rates are unpredictable, and it is not feasible for a CCA to
guarantee that at all times in the future its rates would be lower than the utility's. Higher
rates may cause many customers to opt out of the CCA program and return to the IOU.
Should that happen, the cost to the remaining CCA customers would rise, potentially
causing them to want to leave as well.
A CCA program will need to perform energy supply management functions(produce or
purchase electricity, forecast load, collect and process load information, coordinate
scheduling with the grid operator), set rates, provide account services (exchange
customer usage and billing information with the utility), and do other administrative
functions (finance, legal, regulatory, contract management, public relations/marketing).
In order to test the economic feasibility of a CCA program, a community must
determine its procurement priorities and other community objectives.It must then use
this information combined with usage data from the utility, projected demographics,
and fuel costs to determine what the cost to its customers will be over a period of years.
Since the transmission and distribution charges will be the same whether a customer
buys electricity from the CCA or the utility, the comparison should focus on the
generation portion of a customer's bill, including any exit fees allowed by the CPUC. In
11
order to be prepared for the best and worst case scenarios, sensitivity analyses(for
example, increasing or reducing the future price of natural gas by a certain percentage)
should be tested.
The CRS,or exit fee,is supposed to protect the rates of the customers who remain with
the IOU after a CCA program is established.It is the difference between the current
market price of electricity and the average cost of the utility's generation resources.
Theoretically, a CCA will be able to purchase electricity at the current market rate;when
the CRS is added to a customer's bill, the cost will equal that of the IOU.In order to
provide electricity for less cost than the utility, a CCA will need to either purchase or
produce electricity for less than the market rate. Buying electricity for less than the
market rate may be difficult. But the tax-free financing authority of local governments
may make electricity production less costly than the IOUs and other commercial
generators. Also,CCAs can provide price stability to customers by buying electricity
under longer term contracts, which provides benefits relative to the uncertainty inherent
in utility rates.
CCAs,like other electricity providers, will be required to provide at least 20%renewable
energy resources to their customers by 2010.The Energy Commission-funded pilot
program tested four supply alternatives (20%renewable energy, all purchased;20%
renewable energy, some owned by CCA;40% renewable energy,all purchased;40%
renewable energy,some owned by CCA). The results of the pilot program studies are
specific to the communities studied;not all had the same savings or losses,although the
trends were consistent in all instances.For example,the difference in cost between 20%
and 40%renewables was minor, and CCA financing of generation was required to
capture significant savings.
2.2. What Are the Potential Benefits of Community Choice
Aggregation?
The potential benefits of CCA include:
• Customer choice in selecting or influencing the selection of energy resources
serving the community.
• Local accountability for selection of energy resources, rate-setting, and
administration of the CCA.
• Reduced energy costs through the negotiation of energy prices below those offered
by investor-owned utilities,or from CCA-owned or financed generation.
• Increased price stability through a diversified energy supply portfolio, which
includes long-term power purchase agreements and ownership of low-cost
generating resources.
• Affordable renewable energy through economies of scale achieved by aggregating
customer load and using public financing.
12
• Environmental benefits related to the procurement of energy from renewable
and/or low-emission resources.
• Ability to wheel electricity, that is, to generate it in one location and use it in
another.
• Energy security through the selection of reliable energy suppliers and/or
construction of reliable generating resources.
• Opportunities to influence and implement effective energy efficiency and demand
side management programs within the community.
2.2.1. Customer Choice
CCA provides choice to all electricity customers of the community. All customers have
the option of being automatically enrolled in the CCA program or remaining with the
IOU. Because direct access has been suspended by the California legislature for anyone
who is not already a direct access customer, CCA is currently the only mechanism that
allows customers to buy electricity from an entity other than an IOU.
One benefit that is important to many communities is the ability to use electricity
generated from renewable energy resources and significantly exceed renewable energy
standards imposed on IOUs by the state. CCA allows communities to weigh the costs
and benefits of such decisions and, ultimately, to choose their preferred resource
portfolio.
2.2.2. Local Accountability
Unlike IOUs, local governments are accountable to their citizens through locally elected
officials whose tenures depend on serving the public good and supporting the interests
of their communities. When compared with an IOU, the decisions of a local authority
will be more transparent and will better reflect the desires of the community. An IOU
will be subject to the preferences of its investors as well as the regulatory constraints
imposed by the CPUC.
A CCA program allows communities to provide innovative energy services to customers
that might not be explored by IOUs. Communities will be able to develop programs that
respond to the concerns, needs, and values of their constituents.
One example could be formation of green pricing programs that provide customers with
the option of choosing to use, and paying for, more renewable energy as a percentage of
their total electric consumption. Other, more price sensitive customers could choose not
to participate in such green pricing programs in order to maintain their lower rates.
Other innovative services could include special rates for population subgroups (e.g., low
income, government facilities, enterprise zones, etc.), program-financed distributed
generation, and a host of other value-added services.
The CCA can also use its ratemaking authority to establish economic development and
business-specific rate incentives to help lure desirable businesses and jobs to the
13
community. Incentive-laden pricing could be a factor in retaining businesses that might
otherwise leave the community to seek locations with lower costs of doing business.
2.2.3. Reduced Energy Costs
Pilot project feasibility studies indicate that with the implementation of local CCA
programs, electric cost savings could be 4-5% of total electric bills over a 20-year period.
This savings can be used to lower rates for CCA customers, contribute to reserve or
contingency funds, or augment the community's revenues for public services to its
constituents.
CCAs can secure low-cost energy supplies by (1) negotiating low-cost, potentially long-
term power purchase agreements with energy suppliers, and/or (2) using public
financing to develop generating resources.
With respect to developing or investing in new generating resources, local governments
have substantial financial advantages over IOUs. Three key advantages are:
• Because cities, counties, and Joint Powers Agencies are not-for-profit entities,
rates will not need to reflect an investor return, whereas IOUs are allowed by the
CPUC to include a profit margin in retail electric rates.
• A CCA, as a public organization, qualifies for tax-exempt financing to support
the development of power generation facilities, resulting in a cost of capital that
is approximately half that of an IOU.
• CCAs, as public organizations, will not be required to pay state or federal income
taxes, another considerable savings when compared with IOUs.
In the short term, these financial advantages are somewhat offset by the increased costs
of paying off the state's long-term bonds and power purchase contracts, which were
entered into during the energy crisis of 2000-2001. After these costs are paid off, which
will occur around the 2012 calendar year, CCAs may likely secure savings, particularly if
they invest in or own new clean power plants.
The CPUC has authorized surcharges on customers of CCAs. These surcharges will be
used to recover above market costs associated with the DWR's long-term power
purchase agreements. These surcharges represent the difference, on a system average
basis, of the average cost of the IOU's supply portfolio and the market price of
electricity. In effect, the CRS shields the IOUs and their remaining ratepayers from the
costs of losing customers to the CCA. The CRS will be determined annually by the
utilities and the CPUC and reflected in the utilities' tariffs.
With respect to the CCA, this means the aggregating community must obtain electricity
supplies at below market prices if it is to provide electricity cost savings to its customers
during the period to which the CRS applies. There are two ways a CCA can obtain
below market electricity prices:
14
• The CCA can 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.
• The CCA can utilize its ability to issue low-cost municipal bonds to develop or
contract for generation resources or to purchase electricity from resources
financed by other public agencies using low-cost municipal bonds.
While the opportunity for negotiation of low-cost power supplies will be circumstantial,
the CCA's ability to secure public financing offers a competitive advantage over IOUs.
The CCA, as a public agency, can finance generation projects at an effective cost of
capital that is approximately one half that of an IOU or a typical merchant generation
developer.
The municipal financing advantage is well-suited for development of renewable
generation projects, as these projects generally have relatively high capital costs and low
operating costs. By financing generation resources (conventional, such as natural gas
fired, or renewable) or providing capital to prepay for electricity purchases, the CCA can
obtain electricity at below market costs.
Once the CRS terminates at some point in the future, the CCA will compete directly
against the IOU's then-current supply portfolio. By 2013, approximately 40% of the
IOUs' supply portfolios will be comprised of power purchase contracts executed after
2005. Therefore, the cost competitiveness of the IOUs' portfolios in the post-CRS
timeframe will largely depend on how efficiently they procure electricity supplies
during the next several years. The conservative assumption is that the IOUs will procure
electricity at prevailing market prices and that a CCA will need to bring its financing
advantages to bear in order to obtain electricity cost savings in the post-CRS period.
While conceptually the imposition of the CRS eliminates cost savings opportunities,
except to the extent a CCA can procure electricity at below market prices, in practice the
customer mix of the CCA's program is an important determinant of whether cost
savings opportunities exist. The CRS is calculated as if a CCA served a mix of customers
identical to the overall mix of customers on the IOU's system.The actual customer mix
within a CCA could be more heavily weighted towards commercial and industrial
customers, which subsidize the residential customer class under the IOUs' current rate
structures.
In the event that a CCA included a customer base that was heavily weighted towards
commercial and industrial sectors, its residential customers would likely benefit from
lower rates when compared with those of an IOU because some of the commercial and
industrial margins could be used for lowering rates across the board. Conversely, if a
CCA included a comparatively large percentage of residential customers, similar
savings may not likely be achieved.
15
2.2.4. Increased Price Stability
Experts expect California's growing demand for electricity to be met by an increasing
dependence on natural gas-fired power plants. California already imports about 84% of
its natural gas from other regions, and our growing appetite for more electricity will
require even more imported fossil fuels, including liquefied natural gas (LNG) from
other countries. Because gas-fired generating resources account for the majority of the
electricity consumed in the state, there is substantial price risk associated with much of
our power supply. A CCA may be able to mitigate some of this price risk by developing
or procuring energy from generating resources other than natural gas.
Renewable generating resources are not affected by fuel price fluctuations. In most
instances, renewable energy has no fuel cost and is not subject to supply shortages that
have occurred in natural gas markets. A combination of new renewable energy supply
and long-term power purchase contracts will help achieve a higher level of price
stability for homes and businesses, and will protect the local economy from fossil fuel
price swings.
CCAs can also ensure rate stability by locking in electricity prices with long-term, low-
priced energy contracts from a variety of sellers. Business customers in particular tend to
value predictability in their energy costs.
Historically, IOU rates have exhibited periods of relative stability punctuated by periods
of high rates (during times of crisis or when major investments in energy infrastructure
are being made). Due to actions taken in response to the energy crisis of 2000-2001, as
well as the imposition of California's statewide Renewables Portfolio Standard, the
IOUs' current supply portfolios are much more heavily weighted toward fixed price
contracts and renewable energy contracts than before the energy crisis. This should
result in the IOUs' ability to charge ratepayers somewhat predictably increasing rates
over the next several years. California is entering a period of major electricity
infrastructure investments, and the addition of new utility-owned generation will also
cause IOU rates to increase.
A CCA will make its electricity procurement decisions and set the rates it charges to
customers. A CCA has a wider range of fiscal management alternatives than an IOU to
control its electric supply costs and rates. For example, publicly owned (i.e., municipal)
utilities commonly create rate stabilization funds using retained profits that enable them
to weather short-term cost increases without the need to increase rates.
2.2.5. Affordable Renewable Energy
Because a CCA is a public agency, it can procure electricity from renewable resources
financed with tax-exempt bonds and thereby obtain renewable energy at relatively low
cost. Under a CCA program, homes and businesses can enjoy the benefits of non-
polluting renewable energy resources at an affordable price.
Initial feasibility studies across the state for this pilot project suggest that many
communities can meet up to half of their electricity demand with renewable energy
16
resources(such as wind, solar, and geothermal steam), while still maintaining a modest
savings over current IOU rates. That is more than double the renewable energy content
the IOUs plan to include in their portfolios.
Currently, renewable generation comprises a relatively small portion of each IOU's
generation portfolio. As adoption of these renewable technologies continues to increase,
suppliers/builders of these technologies will need to increase production levels to meet
demand. Manufacturing and technological enhancements/expansions required to meet
this demand should lower the cost of producing renewable technologies, a benefit that
will ultimately pass to the CCA and its constituents. However, the demand for
renewable energy created by the Renewables Portfolio Standard (RPS)has driven up the
price of renewable energy in the short term as utilities attempt to meet the 20% standard
by 2010. Cost pressures should ease once the basic RPS requirements have been met.
2.2.6. Environmental Benefits of New Generation
By implementing a CCA program, a community can influence the development of new
generation, either by offering contracts to suppliers for the purchase of energy or by
direct involvement in developing new generating resources. Development of new
generation, whether renewable or fossil fueled, will likely displace the production of
older, less efficient generating sources.
According to the Energy Commission, approximately one-third of natural gas consumed
in California is used for production of electricity.Today's natural gas-fired generation
units can operate 30% to 40% more efficiently than similar generating technologies
developed in the 1960s era, many of which are still online in California. For every
kilowatt-hour(kWh) of electricity produced by a new generating resource, there will be
up to 40% less natural gas consumed when compared to older units and even greater
reductions in air emissions and greenhouse gases.
Furthermore, should a CCA choose to develop renewable generating resources, natural
gas consumption and emissions will both decrease. As previously noted, kWh produced
by a renewable energy resource requires no natural gas consumption and, depending on
the renewable technology employed, air emissions may also be eliminated.
2.2.7. Self-Generation and Wheeling
A CCA program will provide a legal mechanism to transmit excess power from one
location to another within the community, something not possible without CCA. Excess
production from a CCA cogeneration or solar facility could be used to serve other
customers within the community rather than being sold to an IOU or, in the case of net
metered solar, lost to the system. The CCA program will enable the community to obtain
greater value for its distributed generation facilities by diverting energy to community
loads rather than back to the grid.
2.2.8. 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 and the economic
17
risk associated with natural gas markets.The flurry of activity related to construction of
new LNG facilities along the California and Baja California coast attests to the increased
demand for imported natural gas.
Many people are concerned that during the next 10-20 years the United States will
become as dependent on natural gas imports as it 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, a community can ensure that the electricity consumption of customers
participating in the program does not contribute to the potential problems associated
with increased dependence on imported natural gas.
A CCA program can also promote greater reliance on local distributed generation
facilities such as solar panels, on-site wind turbines,and co-generation facilities or fuel
cells.Incorporating local distributed electric generation sources and remote renewable
energy power plants helps diversify risk and increase service reliability.
2.2.9. Demand-Side Energy Efficiency
A CCA will be motivated to reduce overall energy costs.An integrated approach to
supply planning,energy efficiency, and demand response should translate into greater
energy savings. Energy efficiency and/or demand side management programs can be
creatively structured to meet the unique needs of a community while yielding
reductions in supply costs.
The CCA can use its revenue bonding capacity to finance worthy public benefits
programs such as installation of rooftop photovoltaic systems and energy efficiency
investments. It can repay the bondholders through charges included in monthly
customer bills. The CCA's knowledge of its community will help improve the
effectiveness of energy efficiency investments by targeting programs that support
community preferences.
Current CPUC rules do not grant aggregators the right to administer public goods
funding for energy efficiency programs.However, AB 117 does require that a
proportional share of energy efficiency funding be spent in a community that forms a
CCA program.Formation of a CCA program will obligate IOUs to ensure that
communities are not underserved by energy efficiency programs that they oversee.The
CCA may be able to seek authority to replace the IOU as administrator of energy
efficiency programs by submitting a program application to the CPUC.
2.3. What Are the Potential Risks of CCA?
Communities that are investigating CCA face political, financial, and administrative
risks, which may be mitigated with careful planning and use of experienced energy
professionals. There are also regulatory risks that can impact a CCA program,but, so
far, the CPUC process has been favorable to the CCA community.
18
2.3.1. Political
The primary risk when investigating CCA is political, especially if the IOU directly or
indirectly opposes the CCA program. Whereas each of the local utilities has publicly
supported CCA, there are always caveats that might cause them to oppose a specific
CCA effort as it progresses toward an implementation plan.
Typical utility responses to local government energy initiatives are to urge local
leadership to slow down for the purpose of avoiding pitfalls that may result from a lack
of understanding of pertinent issues/considerations. The utility may criticize feasibility
study assumptions and methods and may suggest that becoming a CCA entails great
risk with little or no commensurate benefits.
Furthermore, the IOU may formally oppose elements of the implementation plan at the
CPUC. For example, each of the utilities has voiced opposition to allowing CCAs to
phase in operations over a multi-year period, and, as a result, phase in proposals
contained in an implementation plan may be protested, or the utility may attempt to
charge the CCA service fees for accommodating a phased CCA implementation.
In the extreme case, the utility might sponsor community organizations to oppose the
program, as has been done by both SCE and SDG&E in their efforts to prevent
municipalities from forming municipal utilities within their service territories.
Communities should be realistic and anticipate some degree of opposition from their
utility during their efforts. Utilities are prohibited from using ratepayer funds to
compete with the CCA for customers; however, they are not restricted from using
shareholder funds to market to customers. It should be noted that AB 117 requires
utilities to fully cooperate with CCAs, and active opposition to a CCA's efforts would
appear to violate the law.
Once a commitment to develop the implementation plan is made, an intensive effort will
be required to decide the particulars of the CCA program. Choices must be made
regarding program management and organizational structure, resources and suppliers,
rates and customer protections, terms and condition of service, financing, and staffing.
And all of this must be done in a very public setting, so that the residential, commercial,
and industrial constituents are fully informed and allowed to participate in the process.
2.3.2. Financial
The major risk associated with forming a CCA program is the possibility that its rates
exceed those charged by the respective IOU.This could cause customers to become
dissatisfied with the program and/or return to IOU service.
The CCA's ratemaking authority and ability to raise rates, if necessary, should protect
the CCA from the financial impacts of unanticipated cost increases. And if long-term
program costs remain uncomfortably high, the CCA will have the option to terminate
the program. If this becomes necessary, customers of the CCA will return to IOU service.
To protect against potential costs associated with this, the CCA must set aside financial
reserves to cover reentry fees in the event of program termination.
19
A CCA should not be formed unless there is a financial firewall that insulates the
community's General Fund and taxpayers from financial liabilities of the CCA.
However, the General Fund could be affected if the city council or board of supervisors
voluntarily exposes the General Fund. A community's bond rating could also be
indirectly affected if the CCA defaults on its bonds.
Unless outside financing is available for startup expenses, communities will need to
allocate funds for this purpose. If the CCA is not able to successfully implement its
programs and generate revenues, these startup funds would not be reimbursed.
Other factors influencing the cost-competitiveness of a CCA program will depend on:
• The mix of customers served by the CCA and the rate charged by the IOU for
various customer classes.
• The composite load profiles (hour-by-hour energy consumptions) of the CCA's
customers.
• The CCA's resource mix.
• The use of low-cost municipal bonds to finance generation development.
• Electricity prices and prices for other services negotiated with third-party electric
suppliers.
• The IOU's generation costs and whether the increase in costs is passed on to
CCA customers through the CRS.
• The costs charged by the IOU for implementation activities and transactions such
as metering, billing, and customer services.
2.3.3. Administrative
Energy procurement and resource planning are subject to certain risks and uncertainties
that must be managed by the energy supplier, whether it is the IOU or the operator of a
CCA program. Forming a CCA program does not increase operational risks, but
responsibility for their management transfers to the CCA and/or its suppliers.
The CCA will be able to obtain services from a variety of large, experienced suppliers to
help manage the CCA program. Municipal utilities, for example, have been successfully
managing commodity, credit, and operational risks for many decades, even during
times of high commodity prices and supply shortages. Professional program
management and application of standard industry risk management practices will be
critical to the successful operation of a CCA and should allow a CCA to manage risks as
effectively as an IOU.
The primary risks inherent in CCA operations are unanticipated events that may cause
the CCA's costs to increase, or the rates of the IOU to decrease. In either case, the rates
charged by the CCA would likely exceed those of the IOU, and CCA customers may
become dissatisfied with the program. If such a situation were to persist, customers may
leave the CCA and return to IOU service.
20
To the extent customers are not precluded from leaving the program, the CCA could
face stranded costs as community members leave the CCA. This could lead to further
increases in the per-kWh rate charged to customers, which would likely prompt
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 CCA customers find themselves obligated to a program with higher rates
than those offered by an IOU (or other competitors), their dissatisfaction may be
directed at those responsible for administering that program. Such a risk highlights the
importance of clear disclosures in the customer notification process so that potential
customers are clearly informed of their rights and obligations prior to taking service in
the program.
The major variables and risks that might impact a CCA's costs are:
• The CRS will vary year-to-year. The CRS is inversely related to the market price
of electricity. If market prices fall, the CRS will increase. If the CRS increases and
the CCA has locked in electricity prices through long-term electricity or fuel
contracts, a CCA's customers' total rates will increase.
• A CCA could overrely on long-term contracts with fixed prices, potentially
resulting in a high-cost portfolio at a time when market prices are falling.
• A CCA could fail to secure its customer base, making debt financing difficult to
obtain and exposing the CCA 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.
• A CCA's energy suppliers could default on supply contracts (credit risk) at times
when energy spot markets arc high, forcing the CCA to purchase energy at
relatively high prices.
• Customers could fail to pay the CCA's charges, and the CCA's credit policies and
customer deposits may be insufficient to recover the uncollectible bills.
• The IOU could make changes to its rates that reduce the cost of generation
services and increase the costs of delivery services or that shift costs among
customer classes in a manner that disadvantages the customer mix served by a
CCA.
• 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 a CCA's cost of providing
service. For example, they could require a CCA to use geographic-specific load
profiles for electricity procurement.This could advantage coastal communities
21
that have relatively flat load profiles while hurting those located in hotter, inland
climates with their peaks and valleys of electricity use.
Ultimately, the major operational risks are under the control of the program's
management. Professional management is the key to mitigate the inherent risks
involved with providing retail electric services.
The experiences of the IOUs during the energy crisis of 2000-2001 illustrate what can
happen when risks are not properly managed. The IOUs' exposure to electricity price
spikes during the energy crisis stemmed from a constraint imposed by the CPUC on
their contracting abilities, coupled with a legislated rate freeze. Without these
constraints, the financial situations of the IOUs would have been much different.
Because the utilities had divested nearly all of their natural gas-fired generating
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
forced the California Department of Water Resources (DWR) 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. PG&E and SCE were unable to raise rates and experienced financial
devastation.
A CCA will not be subject to these types of constraints on its procurement practices.
Being a municipality, it will exercise its own authority over resource planning and
ratemaking decisions. A professionally managed electricity procurement program, using
sound risk management practices, would not expose itself to the risks that the IOUs
faced during the energy crisis.
2.3.4. Regulatory
Decisions by regulators could cause cost increases for a CCA program. A CCA may
participate in regulatory proceedings at the CPUC or FERC in an effort to influence the
regulatory process, which may or may not protect its interests and those of its
customers.
Typically, associations are formed among entities with common interests. These
associations participate on behalf of their constituents during the regulatory process to
influence regulators. The amount of influence wielded in the regulatory process
depends on the level of influence of the association's membership as well as the number
of resources the association is able to devote to such efforts.
To some extent, the degree to which regulatory risk can be managed depends upon the
prevalence of CCA throughout the state. If CCAs become widespread, 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 are affected.
22
2.3.5. Risk Mitigation
The risks of forming a CCA program evolve as a community begins its implementation
planning process and then progresses to startup of program operations.The
community's risk exposure also depends greatly upon the implementation approach it
chooses.
Each of the above risks can be mitigated, although not altogether eliminated. A CCA can
develop its program in such a way that it would be exposed to very little risk. Electricity
supply contracts can be structured to transfer many of the risks to the suppliers.
Table 2-1 below describes basic risk management techniques for each of the primary
risks associated with operating a CCA program.
Table 2-1. Risk management strategies
Risk Mitigation
Cost Responsibility Surcharge Volatility Use shorter duration supply contracts to offset
CRS risk. If market prices decrease, the CCA's
supply portfolio costs will also decrease,
offsetting the increase in the customer's CRS
payments to the IOU.
Commodity Price Volatility Diversify supply portfolio by using contracts
with various terms, multiple suppliers, and
renewable energy and conventional
generation. Transfer commodity price risks to
energy suppliers through fixed-priced contracts
or guaranteed discount pricing.
Customer Attrition Establish exit fees following the free opt-out
period. Negotiate term contracts with large
customers.
Credit Risk Perform periodic credit and exposure
monitoring; ensure supplier diversity; maintain
collateral and surety instruments. Require
deposits from customers and return customers
to utility for failure to pay bills.
Utility Rate Changes and Other Regulatory Participate in CPUC process to prevent shifting
Risks of costs to program customers.
Source: Navigant Consulting, Inc.
Physical and financial reserves are also important components of a CCA program that
reduce program risk. Industry rules dictate certain reserve requirements for all
electricity suppliers to protect the integrity of the system and to ensure reliability.
Like other energy suppliers, CCA programs will need to provide physical reserves to
ensure reliable operation of the electric grid.The California Independent System
Operator (California ISO) requires load-serving entities to maintain operating reserves
(6%-8% of load) and regulating reserves (2.5%-5%) that can be quickly called upon in
the event that the system experiences outages or electricity consumption unexpectedly
23
increases. Load-serving entities can arrange for their own reserves, or the California ISO
will charge the load-serving entity for the costs of reserves procured on its behalf. The
costs of these reserves should be included as an expense item when performing a
feasibility analysis.
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 intended to both ensure the existence of
adequate generating capacity and reduce the ability of power suppliers to charge high
electricity prices that can occur when capacity is scarce. The costs of planning reserves
should also be included as an expense item in the feasibility analysis.
A CCA program should maintain financial reserves in the form of rate stabilization
funds or other reserve funds required by banks to support debt financing. Rate
stabilization funds are maintained at the discretion of program management and the
program's governing board.These funds are used to offset financial impacts to
customers in the event of short-term cost increases and accrue cash for future capital
expenditures.
To the extent that debt financing is used 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. 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.
Communities can phase in implementation of CCA to help ensure a smooth transition
for customers that join the program. Although a program's financial viability should not
be dependent upon a phased implementation, a phase in could reduce implementation
risk and could contribute to the program's financial benefits during the initial startup
stage.
An example of phased implementation could be the initial offer of program energy to
non-residential customers during a pilot phase of six months to one year. Based on
successful operation during the pilot phase, the program could then offer its energy to
all customers in its jurisdiction.
By initiating a CCA program with non-residential customers, the number of transactions
(account transfers, monthly billing, etc.) that must be completed will be less than in a
non-phased implementation. In this phased implementation scenario, the program will
be able to work out any startup kinks while dealing with a much lower volume of
transactions/customers than in a non-phased approach.
Another benefit of the phased implementation model is that non-residential customers
are higher-margin customers when compared to the residential customer class, so the
initial phase in period would provide greater margins for the program to help cover
24
program startup costs. A CCA must comply with the legal requirements of AB 117 that
require the eventual offering of program services to all residential customers.
2.4. What Are the Elements of a Community Choice
Aggregation Program?
A CCA program will include all the 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 the IOU that provides billing, metering, and related
services to CCA customers. These activities can be grouped into the broad categories
described below.
2.4.1. Portfolio Operations
Portfolio operations are 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.
Electricity Procurement
The essential purpose of a CCA is to supply electricity to its customers. As an
aggregator, the CCA can choose from various types of resources and wholesale
electricity products that reflect the community's values related to cost certainty,
environmental considerations, and cost effectiveness.
A variety of generation resources or power 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. These
cycles typically peak daily during the afternoon hours and seasonally during the
summer months.
The CCA must consider these load patterns when assembling a supply portfolio that
will match resources to the aggregate load shape of its customer base. Different types of
generation resources and supply contracts can be used to meet base load requirements,
intermediate resource needs, and peaking load requirements. These concepts are
illustrated in Figure 2-1. The jagged line on the graph represents the electric load for this
community for one week, starting on Sunday.
25
Spot Market Purchases
300,000.0 "Imbalances" or
Load Following Products
Peak Load or
6X16Power
Product
•
Y iso,000.o •
•
loo,000.o
50,000.0 - Base Load for Generation Resources
or 7 X 24 Power Products
o.o -
Figure 2.1: Supply portfolio matched to load shape
Source: Navigant Consulting, Inc.
A typical supply portfolio would utilize generation owned by the CCA 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 (July-September) of each year. Spot market purchases and
sales are used to fill the load requirements that remain after using both long-term and
short-term contracts and/or CCA-owned generating resources.
Risk and Credit Management
Risk management techniques need to be employed to reduce the CCA's exposure to
volatile energy markets and to insulate customer rates from sudden changes in
wholesale market prices. Credit monitoring must also be performed 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 specific supplier by comparing the value of the supply contract to the
contractual price. Exposure to suppliers is greatest when the contractual price is low
relative to market prices, and the risk of default becomes a concern (in this instance,
supplier default would require the CCA to procure energy' at market prices, which when
higher than contract prices would require the CCA to raise customer rates or offset them
with reserve funds).
26
Collateral and other security instruments, such as letters of credits or surety bonds, arc
commonly used to manage credit risks between wholesale electricity buyers and sellers.
Load Forecasting and Data Collection
The CCA will be required to provide energy for each hour of the day, either through
self-generation or supply contracts. In performing electricity procurement functions,
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) must be developed.
To develop both long-term and short-term energy procurement plans, a CCA may use
off-the-shelf and/or customized forecasting applications that will model future energy
demand based on a range of detailed assumptions, including historical load data
provided by the IOU. Subject matter experts may also be hired by the CCA to assist with
the development and interpretation of such forecasts.
By regularly preparing and monitoring these short- and long-term forecasts in relation
to actual customer load, the CCA will be able to fine-tune its procurement strategies to
meet the needs of its customers while minimizing unnecessary energy purchases (which
would result in selling energy, often at a financial loss, to a third party or back to the
grid) or spot purchases.
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 IOU's recorded usage
for each individual customer.
All customer classes are not metered in the same way. Residential and small commercial
consumers (electric demand less than 20 kilowatt [kW]) typically have simple meters
capable of metering only cumulative energy consumption. Medium commercial
customers (electric demand in the range of 20-500 kW) arc 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 that record electric demand in 5, 10, or 15 minute intervals
(interval data recording meters).
Without a time-of-use record of energy consumed, the CCA will have to rely on typical
rate-class load profiles. The California ISO allows use of load profiles that are approved
by the CPUC for scheduling and settlement. These load profiles represent the average or
typical customer and not the CCA's actual customers. To date, the CPUC has approved
the use of rate-class load profiles for use by the utilities and energy service providers for
electricity scheduling and settlement. The IOUs have opposed proposals that CCAs be
allowed to use area-specific load profiles for these purposes.
CCAs have the option, under the law, to meter electricity supplied to their territories to
obtain an accurate record of aggregated loads. The IOU is required to install, maintain,
and calibrate metering devices at mutually agreeable locations within or adjacent to the
27
CCA's political boundaries at the request and at the expense of the CCA. The IOU will
also be required to read the metering devices and provide the data collected to the CCA
at the aggregator's expense. Assessing the size, type, location, quantity, and installation
cost of such CCA wholesale metering will require an analysis of the IOU's distribution
system. At this time, it is not clear to what extent the CPUC or the California ISO would
have to approve the CCA's use of boundary meters for electricity scheduling and
settlement.
Scheduling Coordination
Scheduling coordination costs are associated with electric supply transactions with the
California ISO. All customer meters must be represented by a California ISO-certified
scheduling coordinator. The scheduling coordinator submits schedules to the California
ISO of hourly electric demands and supply resources on behalf of the CCA.
The scheduling coordinator is responsible for costs associated with energy imbalances
between actual hourly loads and actual hourly deliveries from the resources it
represents. It is also responsible for the costs of reserves and other ancillary services
provided by the California ISO that are necessary for reliable operation of the
transmission system.
A CCA has several choices for obtaining services of a scheduling coordinator. Some
companies act as independent scheduling coordinators and charge 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 scheduling coordinator services are bundled into the overall cost
of electricity provided by the supplier.
It is also possible for the CCA itself to become a California ISO-certified scheduling
coordinator, which requires acquisition of specialized software, completion of
certification training conducted by the California ISO, and continuous staffing of a
scheduling desk for round-the-clock, or 24 x 7, operations.
2.4.2. Rates
Rate design is the process of determining the charges that will be applied to customer
electricity usage. Rate schedules define the charges for each kWh, kW, or other unit of
electric service.There may be one or more rate schedules that are applicable to each
customer class.
The CCA is responsible for setting charges associated with the generation services it
provides to its customers. The first step in setting rates is to determine the total amount
that must be collected from customers in order to cover all of the CCA's costs of doing
business.This amount is known as the CCA's revenue requirement and consists of
operating expenses, depreciation and amortization, interest and financing expenses,
taxes, and contributions to reserve funds.
28
Ultimately, rates are established to recover the CCA's revenue requirement. Because
rates are established based on forecasted customer demand, energy costs, and other
considerations, the CCA will need to periodically adjust rates, based on differences
between actual and forecasted data, to maintain sufficient revenues.
The revenue requirement is split between the 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 performed on
a cost of service basis, so that rates reflect the differences in the CCA's costs to serve each
customer class.
The CCA may use load research to estimate customer class load profiles and cost of
service by using sampling techniques. Load research meters (that can record customer
electricity consumption in 5-15 minute intervals) are installed on a small sample of
customers within each rate class. Alternatively, the CCA may use the customer class
load profiles created by the IOU.
2.4.3. Account Services
The CCA must be able to exchange customer usage (meter) data electronically with the
IOU using the utility's standard electronic data interchange procedures and formats. The
CCA must also receive and process customer payments collected by the IOU.
Aggregators may also need to calculate individual customer bills. If this is necessary, the
CCA will need to provide these calculated amounts to the IOU in an appropriate data
format and by the prescribed timeline associated with IOU billing cycles.
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 CCA. However,
PG&E's rate-ready billing service offers fewer rate classes than its own billing services;
therefore, cost comparisons may not be possible for CCA customers. PG&E also offers
hill-ready billing service whereby the CCA calculates the amounts due from each
customer and submits these amounts to PG&E for collections. SCE and SDG&E offer
only bill-ready billing.
The CCA must also be able to obtain customer meter data and process this data for
submission to the California ISO through its scheduling coordinator. This data is used
by the California ISO to complete its financial settlement process. Customer meter data
must be processed in accordance with the CPUC's protocols.
The IOUs will perform this function for CCAs as part of their metering service.
However, the CCA must then 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 hourly usage data to submit to the California ISO.
2.4.4. Administration
Administration and management of the CCA program includes finance, legal,
regulatory, contract management, and other program management functions.The scope
29
of necessary administrative functions depends on the complexity of the CCA
implementation, which could range from the execution of a single contract with an
energy services provider for operation of the entire program to full-scale planning and
staffing required for comprehensive, in-house operation and management of the CCA
program. There are other variations of program implementation that exist between these
two extremes. At a minimum, a senior level manager with experience in the electric
utility industry should head the CCA program.
2.5. Deciding Community Procurement Objectives
Local governments investigating CCA have many objectives to consider. They range
from reducing costs for all customers (or for a specific customer class) to increasing the
amount of renewable energy their communities consume. Making these decisions
should be a public process that ensures the values of the community (ies) are reflected in
the CCA program.
The following outline provides a planning template for a CCA resource portfolio. The
questions posed in this outline will help a potential CCA determine how much and what
kind of generation resources it ought to procure or own.
1. Renewable Energy Targets
a. What percent of your community's electricity consumption do you ultimately
want to serve through renewable resources? This amount may range between
20% (minimum required by 2010) and 100% (maximum possible).
b. How quickly would you like, or are you able, to meet the target percentages
determined in l.a.? As a guideline, your plan should provide annual target
percentages that achieve at least 20% by 2010.
c. How do you want to procure renewable energy?
1) Do you want to own (or invest in) renewable generation facilities? If so,
what percentage of your renewable portfolio do you want to establish
through community-owned assets? When can these facilities be brought
on-line? How many megawatts(MWs) will they total? What capacity
reserve will you need based on the type of generation you propose to
own (wind and solar energy are intermittent resources and will require
dispatchable resources that arc available when they are not—this is called
capacity reserve).
2) What percentage of renewable energy will you purchase from the
market? What are the contract dates and capacities (MW)?
2. Conventional Generating Resources (non-renewables)
a. Do you want to own (or invest in) conventional generation facilities? If so,
what percentage of your portfolio do you want to establish through
community-owned, conventional generation assets? When can these facilities
be brought on-line?How many MWs will they total?
30
b. What percentage of your portfolio 1vill be established through purchases of
conventional generation from the market? What are the contract dates and
capacities (MW)?
3. Distributed Generation (local, non-centralized power generation, e.g., rooftop
photovoltaic (PV) systems)
a. What resources currently exist within the community? For each technology
(PV, micro turbine, etc.) determine the following characteristics:
1) Capacity (kW)
2) Energy (kWh)
3) Cost
4) In-Service Dates
b. What distributed generating resources may be potentially developed within
the community? For each technology (PV, micro turbine, etc.) determine the
following characteristics:
1) Capacity (kW)
2) Energy (kWh)
3) Cost
4) In-Service Dates
4. Spot Market Purchases—how much energy do you plan to buy on the spot
market? (under 15% of the community's total energy portfolio is recommended)
5. Supply Portfolio Sensitivities—the future is unknowable. It is best to provide a
range of possibilities for certain variables in your feasibility calculation so that
you are aware of the best case/worst case possibilities. Possible variables for
sensitivity analysis:
a. Natural gas/power prices (+/-25%)
b. CRS (+/- 25%)
c. IOU rate projections (+/-5%)
d. IOU rate design (General Rate Case proposals)
e. Renewable subsidies (Supplemental Energy Payments [Energy Commission],
Production Tax Credits [U.S.])
f. Combined operation with other communities (Joint Power Authority)
2.6. Getting the Necessary Data
Local governments can request data on electrical consumption for all electric customers
within a potential CCA's jurisdiction from the local IOU. A city or county requesting
such data must include a statement from its mayor or county administrator that it is
investigating, pursuing, or implementing community choice aggregation.
31
Certain aggregated information is available free of charge, while other customer
information requires payment of modest fees and execution of a non-disclosure
agreement to protect customer confidential data. Sample data request letters are
attached in Appendix A.
Understanding each IOU's revenue requirement is also critical when determining the
feasibility of a CCA program. The IOU's revenue requirement is the basis for
establishing its rates, the key comparison for determining financial viability of a CCA.
Most of the data required to estimate an IOU's revenue requirement should be readily
available in its General Rate Case, the current FERC Form l filing for each IOU, and in
recent Cost of Service Proceedings with the CPUC. The data included in these
publications/documents can then be projected forward to evaluate future years of CCA
operations. These data can be found on the utility websites (www.pge.com,
www.sce.com, www.sdge.com) in the regulatory information and financial sections.
2.7. Evaluating the Data
2.7.1. Study Approach
A financial analysis should be performed in order to develop statements of income for
the CCA program.The calculated savings, or potential income, is the difference between
the IOU's retail power costs and the CCA's projected cost of providing power.
IOUs provide services at regulated cost-based rates. Hence, the IOU's rates are directly
tied to a demonstrated revenue requirement, which it is authorized by the CPUC to
recover through rates. An IOU's revenue requirement includes the utility's expenses,
return or profit, and taxes paid by the utility.
To determine potential savings or income, a financial analysis should compare the IOU's
revenue requirement at current and projected rates with the revenue requirement of the
CCA program. If more than one CCA supply portfolio is studied (for example, varying
percentages of renewable resources), each should be compared to the IOU to determine
if it will produce cost savings or benefits.
A CCA program is limited to providing the electric commodity only. The IOU will
continue to provide electric delivery services over its existing distribution system and
will provide end-consumer metering, billing, collection, and all traditional retail
customer services (i.e., call centers, outage restoration, extension of new service).
Therefore, to evaluate the potential benefits of CCA, only costs associated with
wholesale electric commodity procurement and related business expenses need be
considered.
In preparing the financial evaluation for a CCA program, a community should perform
a thorough analysis of:
• The IOU's forecasted rates (including CRS).
32
• CCA energy or commodity costs (including generation ownership, power
purchase contracts, renewable energy contracts, and spot-market purchases).
• California ISO charges.
• Operations and scheduling costs.
• Financing costs.
• Revenue offsets and available financial incentives.
Each of these items should be factored into the analysis. The CCA program's capital
costs should be amortized over a 30-year period and financed at a municipal rate
(presently 5.5%). Related interest and amortization should be included in the annual
costs of the program.
The object of the financial analysis is to compare the total costs of operating the CCA
program with the total costs of continuing to take retail utility service. The results of this
financial analysis should be incorporated in the potential CCA's feasibility analysis.
2.7.2. Customer Base
The potential customer base for the CCA program includes all of the electric customers
in the community. However, customers have the option to opt out of the CCA program
and continue to receive their electric service from the IOU. Some customers may choose
to not participate in the program, or opt out during the initial 60-day free opt-out period,
and some direct access customers may be prevented from joining the program until their
direct access contracts expire.
The number of customer opt outs will depend on various factors, not the least of which
is how the CCA's electric rates compare to those of the IOU. Other factors that will
influence customers' opt-out decisions include whether the CCA provides non-price
benefits important to customers, such as increased renewable energy purchases or
expanded energy efficiency programs, and customer loyalty or enmity to the IOU. Many
of these factors are directly dependent on details within the CCA's implementation plan,
and the impacts cannot be reasonably estimated prior to completion of the CCA's
implementation planning process.
For feasibility analysis development, 100% customer participation can be used as a
starting point. Within a reasonable range of assumed opt-out percentages, the study
results can be adjusted proportionately. The CPUC has chosen 5% for residential
customers and 20% for commercial/industrial customers as default opt out figures for
planning purposes.
2.7.3. Key Assumptions
This section describes the high level assumptions that provide the framework for a
feasibility analysis. The detailed assumptions used in the Energy Commission-
sponsored pilot program are listed in Appendix B.
33
• CCAs must maintain adequate capacity reserves to maintain reliability standards
and will follow standard industry risk management practices. They will be held
to the same capacity reserve standard as the IOUs.
• CCAs will match or exceed the renewable energy content of the IOUs' portfolios
and are eligible for the existing Energy Commission subsidies provided for
renewable energy procurement up to the minimum RPS(i.e., subsidies are
available for the first 20% of renewable energy).
• Market prices for renewable energy will reflect the developer's costs, including
the effects of available subsidies.
• CCAs will be able to finance generation projects.
• CCAs will be able to obtain electricity from the wholesale market on comparable
terms with the IOUs.
• The CPUC will not allow IOUs to negotiate special rates or contracts to retain
customers.
• CCA operations will be able to be outsourced to third parties.
• Reinstatement of direct access will not preempt CCA rights and customer
relationships.
2.7.4. Utility Rate Benchmarks
Estimates of CCA cost savings should be assessed by comparing CCA costs to the rates
that would otherwise be charged by the IOU. The IOU's rates are derived from its costs
or revenue requirement. When developing the feasibility analysis, the feasibility
contractor will have to make some assumptions about future IOU rates. These
assumptions should be clearly delineated within the feasibility analysis.
2.7.5. Cost Responsibility Surcharges
The single greatest obstacle to achieving significant cost savings through CCA in the
next several years is the imposition of cost responsibility surcharges (CRS) on CCA
customers. The CRS is designed to shield the IOU's remaining customers from any cost
increases that might result from customers switching to CCA service.
The feasibility contractor should model expected CRS using the methodology adopted
in CPUC Decision (D.07-01-025). According to this method, the above-market portion of
the IOU's generation portfolio, including IOU 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 only, 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 depend on future electricity market prices and the IOU's future
generation costs.
There is an inverse relationship between the CRS and wholesale electricity market
prices. If future power prices decline, the CRS will be higher,but the cost of procuring
34
power for the CCA program will be lower. These two impacts tend to offset one another.
Therefore, the magnitude of the CRS should not be looked at in isolation, but should be
assessed in context with 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 should be modeled in a sensitivity analysis.
2.7.6. Renewable Energy Subsidies
A variety of tax incentives, credits, and publicly funded subsidies exist for renewable
energy development, which reduce the cost of the renewable energy content of the
program's supply portfolio. These subsidies include:
• Production tax credits
• Renewable Energy Production Incentives
• 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 Energy Commission (Supplemental Energy Payments), are more
long-lived, but are contingent on the amount of public goods funds collected through
utility rates. A community studying CCA feasibility will need to decide which of these
subsidies to include in its analysis.
The additional costs for purchases of renewable energy up to the minimum RPS should
be offset by Supplemental Energy Payments for renewable contracts, while the
incremental renewable energy above and beyond the minimum requirement should be
assumed to receive no subsidy. Thus, in financial analyses of the costs of renewable
energy, anything above the first 20%should be paid entirely by customers of the CCA.
It should also be assumed that Supplemental Energy Payments will not be available to
offset costs of renewable resources that CCAs own or otherwise finance. The reason for
this assumption is that the process for determining Supplemental Energy Payments is
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 their costs above a market benchmark, determined by the CPUC.
2.7.7. Financial Analysis Structure
CCA customer electric loads should be applied to the IOU's current and projected
generation rates to yield its revenue requirement from the customers in the potential
CCA area. All CCA operating expenses should be projected and subtracted from the
IOU's revenue requirement to yield the projected financial benefit. Elements that should
be contained in the analysis are summarized below.
• Utility Forecast Generation Rates
o Utility retained generation (IOU-owned power plants)
35
o Qualifying facility generation (higher priced generation contracts)
a Bilateral power purchase contracts
o New renewable energy purchases
o California ISO charges
o Residual spot market purchases or sales
• CCA Energy Cost (Commodity Costs)
o Spot market purchases
o Power purchase contracts
a Renewable energy contracts
o Generation ownership
• California ISO Charges
o Ancillary services/reserves
o Grid management charges
a Deviation charges
• Operation and Scheduling Costs
o Electricity procurement
o Risk and credit management2
o Load forecasting
o Scheduling and settlements
o Rates
o Account services
a Administration
• Non-Bypassable Charges/Cost Responsibility Surcharge
o Uneconomic utility retained generation and power contracts
o DWR power purchase contracts
a DWR bond charges—Financing past purchases
2.7.8. Load Analysis
Detailed definition of community electric power needs is required to determine the
economic viability of the CCA. Community electric demand and energy consumption,
2. The costs of uncollectible customer accounts are not explicitly included in the pro forma,under
the premise that the CCA would require customer deposits from customers that pose likely credit
risks,similar to the accepted utility practice. Under current rules the CCA cannot cause service to
be shut off to the customers for failure to pay its portion of the bill, whereas the utility can;
however, the CCA has the right to return the customer to the utility for failure to pays its charges.
36
generally referred to as electric load, should be analyzed,beginning with and based
upon data provided by the IOUs in response to the communities' formal requests (see
Appendix A for sample data request letters). The communities' annual hourly load
shapes should be developed and a determination made regarding associated energy
supply requirements.
Each utility publishes annual load shapes for the major customer classes, which can be
used in conjunction with the monthly energy consumption data by rate class, provided
in response to the CCA's data request, to model the CCA's overall load shape. The time-
of-use supply requirements serve to define the types of resources necessary to supply
electric energy to the CCA. Section 2.4.1, Portfolio Operations, provides additional
discussion regarding time-of-use considerations, load forecasting, and resource selection
with respect to selection of community power supply.
2.7.9. Load Forecast Method
Community electric load data should be provided by the IOU and include at least 12-
month, year-to-date energy consumption and the number of customers by rate class.
Data for residential customers should include the percentage of residential consumption
that occurs in each of the tiers consistent with the tiered rate structure the IOU has in
place. The IOU may provide more rate classes than needed, which can be collapsed into
seven higher-level Customer Sectors. Suggested rate classes and their generic sector rate
class description assignments are listed in the following Table 2-2.:
Table 2-2.
Rate Schedule to Customer Sector Assignment
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
Monthly load information should be ordered by month,January through December, to
reflect monthly seasonal use patterns and should be treated as prototypical for a
37
particular year's energy consumption. Static load profiles, as published by the IOU, can
be used 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, which can also be developed from available data (based on
descriptions provided in the previous table), should be characteristic of load usage
patterns within each of the Customer Sectors. The following Table 2-3. reflects an
example:
Table 2-3.
Static Load Profile Assignment
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
As part of a prospective CCA's load analysis, it is recommended that a 20-year electric
load forecast be performed. Electric energy requirements and customer populations
should be escalated based upon the most reliable sector-specific growth planning
statistics. If the community does not have this information available, the IOU system-
wide growth rates can be applied.
An example of the number of customer accounts and annual energy sales for the initial
year (2006) of a program are shown in Table 2-4. below.
Table 2-4. Forecast number of accounts and annual energy sales
2004* 2005* 2006*
Accounts kWh Accounts kWh Accounts kWh
Residential 46,278 186,558,920 46.426 187.155.909 46,574 187,754.808
Small Commercial 4,476 93,7(19,959 4,550 95,256.173 4.625 96,827,900
Medium Commercial 542 96,730,076 551 98,326.122 560 99,948,503
Large Commercial 56 52,193,719 57 53,054,916 58 53,930,322
Large C/I 7 79,828,758 7 81,145,932 7 82,484,840
Street Lighting 22 4,671,795 22 4,671,795 22 4.671,795
Traffic Control 144 668,871 144 668,871 144 668.871
Total 51,524 514,362,098 51,756 520.279.718 51.989 526,287.039
*2003 Data Provided by Distribution Utility(PG&h)and Escalated by Applying The Following Growth Rates:
Growth Rates
Residential 0.32%
Commercial 1.65%
Street Lighting and Traffic Control 0.00°i%
38
2.7.10. Community Energy Load Shape
The community composite annual energy load shape (average kW per hour) can be
developed by combining average loads in each hour from each of the Customer Sector
load profiles identified above. A prototypical annual load profile is shown in Figure 2-2.
7
m
1 91 T .11 711
0
8760 Hours per Year
Figure 2-2. Prototypical annual load profile
Source: Navigant Consulting, Inc.
Electric load should then be 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,
will be the basis for sizing the portfolio of contracts and generation resources needed to
serve the community's (ies') load profile.
2.7.11. Renewables Portfolio Standard Requirements
The California Renewables Portfolio Standard Program (RPS) established by Senate Bill
SB 1078 (Sher, Chapter 516,Statutes of 2002), requires that a retail seller of electricity
provide a specified minimum percentage of electricity generated by qualifying
renewable energy resources. CCAs will be retail sellers of electricity and, therefore,
subject to this law.
Each IOU 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 2010. Aggregated loads of a CCA program are a subset of the load
currently served by the IOUs. Therefore, analyses can assume that renewable energy
requirements of a prospective CCA will, at a minimum, be equal to the renewable
energy percentage required of each IOU.
The bill requires the CPUC to adopt rules for implementing the RPS (CPUC Rulemaking
06-05-027), and CCA planners must understand these renewable energy requirements
39
before they can assess the cost-benefits and make decisions to implement a CCA
program.
2.7.12. Supply Portfolio Details
A CCA program should be supplied from a diverse portfolio of energy resources. The
portfolio should be designed to achieve the CCA's renewable energy objective in stages.
The CCA may need to initially match the renewable content of an IOU's portfolio and
then incrementally increase the renewable component to achieve its goal (at least 20%)
by 2010. The CCA can invest in generation resources to meet its energy requirements,
especially for base load amounts (the minimum amount used every day). Typically, the
portfolio should also include power purchases through long-term (five-year) contracts
and spot market purchases to supplement the CCA's generation resources.
The resource types may include:
• Spot market purchases—short-term electricity purchases to supplement supplies
under contract or ownership control of the CCA.
• Contract purchases—longer-term, fixed-price power purchases. Terms can be
monthly, quarterly, annual, or multi-year.
• Natural gas power production—production from a combined cycle natural gas
combustion turbine owned by the CCA used for base load or shaping purposes.
• Renewable energy purchases—purchases of renewable energy to meet the CCA's
renewable resource goals, with a minimum equal to the IOU's renewable energy
mix.
• Renewable energy power production—production from renewable energy
resources owned by the CCA.
• Off-system sales—sales of excess energy into the spot market at times when the
resources under contract or ownership are above the CCA's load requirements.
The resource mix can include both conventional and renewable resource ownership.The
initial portfolio will likely contain only purchases from the open market and will later
add production from wind, geothermal, and other renewable resources. The earliest
feasible date for a CCA to acquire equity in a new generation resources, considering lead
times for negotiations, permitting and financing, will be several years.
2.7.13. Alternative Supply Scenarios
Analyzing alternative supply scenarios will assist a potential CCA in understanding the
cost effectiveness and tradeoffs among different resources that could be included in a
CCA's supply portfolio. For the Energy Commission-financed pilot study, analyses were
prepared for four supply portfolios that differed by the amount of renewable energy
included in the portfolio and by whether the CCA owned generation resources used to
supply electricity to the program. The four alternatives were:
40
Alternative Supply Scenario 1
Supply Scenario 1 assumed the CCA will double the renewable content of the IOU (40%
v. 20%) and purchase all of its load requirements from the open market. Including
renewable energy increased the portfolio's cost, even after considering the subsidies
potentially available to the CCA's renewable energy suppliers.
The renewable energy costs for purchases up to the minimum required by the RPS (20%)
were assumed to be offset by Supplemental Energy Payments administered by the
Energy Commission, while the incremental renewable energy above and beyond the
minimum requirement was assumed to receive no subsidy. Thus, the second 20% of
targeted renewable energy was paid entirely by customers of the CCA.
Capital expenditures associated with Scenario 1 were limited to program startup costs.
This supply strategy usually resulted in a loss over the 20-year study period.
Alternative Supply Scenario 2
Supply Scenario 2 assumed the CCA will match the renewable content of the IOU (20%)
and purchase all of its load requirements in the open market. Renewable energy
subsidies were available to offset the incremental cost of the CCA's renewable energy
purchases.
Capital expenditures of Scenario 2 were limited to program startup costs. This strategy
resulted in a smaller loss over the study period than Scenario 1.
Alternative Supply Scenario 3
Supply Scenario 3 assumed the CCA will double the renewable content of the IOU (40%
v. 20%) and produce electricity from resources that it owns. The portfolio also included
power purchases through five-year contracts and spot market purchases to supplement
the CCA's own electricity production. Supply Scenario 3 included both conventional
and renewable resource ownership.
The portfolio initially contained only market purchases similar to Supply Scenario 1, but
after three years, it included production from wind and natural gas-fired, combined-
cycle resources. The third year was selected as the earliest feasible date for the CCA to
acquire equity in a new generation resources, considering lead times for negotiations,
permitting, and financing.
No subsidies were assumed to be available to offset costs of the CCA's renewable
resources. Subsidies were included for renewable energy purchases, if needed,
consistent with the subsidy described for Scenario 1.
Capital expenditures for Scenario 3 included startup costs and generation investments
over$100 million. This supply strategy usually resulted in total savings over the 20-year
study period.
41
Alternative Supply Scenario 4
Scenario 4 was similar to Scenario 3 except that the portfolio matched the renewable
content of the IOU's supply portfolio (20%) with a corresponding increase in the
capacity of natural gas fired generation financed by the CCA. Capital expenditures
associated with Scenario 4 included startup costs and generation investments of less
than$100 million.
This supply strategy resulted in total savings over the study period slightly smaller than
Scenario 3.
Comparing the alternative supply scenarios revealed the cost advantage enjoyed by a
CCA in financing capital-intensive generation projects. The incremental cost of
increasing renewable energy from 20% to 40% was not a significant factor in the
program's cost-effectiveness for the pilot project.
The results of the pilot program studies are specific to the communities studied. Not all
had the same savings or losses, although the trends were consistent in all instances. That
is, the difference in cost between 20% and 40% renewables was minor, and CCA
financing of generation was required to capture significant savings.
This example is meant to demonstrate that a potential CCA should model various
supply and financing scenarios in its planning process. Each CCA may have other
alternatives to test.
2,7.14. Sensitivities
Sensitivity analyses can help put upper and lower bounds on expected financial results
from implementing a CCA program. Sensitivity analyses for the major variables
expected to impact the financial results should be run. The pilot project analyzed the
following sensitivities:
• Natural gas and power prices (+/-25`)/0).
• CRS (+/-50%).
• IOU system average rate projections (1% to 3% annual growth).
• IOU revenue allocation changes to reduce cross subsidies.
None of the sensitivity scenarios eliminated program savings over the study period.
However, the high natural gas/power price scenario and the high CRS scenario caused
revenue losses in the early years of the program.
A CCA 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,
as described in Section 1.11, could lessen exposure to these factors by allowing initial
program operations to benefit from the collection of higher margin rates from
commercial customers, which would help offset potential financial risks of this nature.
42
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.
2.7.15. Cost of Renewable Energy
The Energy Commission'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 types of generation
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 in Table 2-
5 below:
Table 2-5. Renewable resource technologies expected to fulfill the California Renewables
Portfolio Standard (2003 Dollars)
2005 Levelized
Resource Portfolio Contribution Production Cost
($IMWh)
Wind Class 4 site 66% 60 *
Concentratin• Solar 1% 121
Landfill Gas 4% 44
Solid Biomass Direct Combustion 4% 66
Geothermal Bina 25% 55
Wei•hted Avera•e 59
Source:California Energy Commission Renewable Development Resource Report
*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 wind resources are intermittent. These figures do not include
production tax credits, which were scheduled to expire at the end of 2007.
Escalating the cost to 2006 by assuming 2.5% annual inflation yields a 2006 average
renewable cost of$62 per lvIWh for wind power. This is about$18 per MWh above the
projected market prices of system power in 2006.
All else being equal,and assuming no CCA capital financing of renewable energy, the
cost of doubling PG&E's 14% renewable mix would be$18/MWh *0.14 =$2.52 per
MWh. In this case, a typical household would pay $1.26 more per month to double the
amount of renewable energy used to supply its electricity consumption.3 The premium
declines over time as natural gas and electricity market prices are expected to rise faster
3.Typical residential consumption is approximately 500 kWh or 0.5 MWh per month.
43
than the cost of renewable energy production. By 2018, the market price of renewable
energy is expected to be no greater than the cost of conventional generation resources.'
The projected costs of renewable and conventional electricity that were used in the 2005
feasibility studies are shown in Fig 2.3 below':
I
100.0 - - - -
90.0
80.0 - - - -
3 70.0 - - -
2 60.0
a 50.0 - _. _. Renewable Energyl
40.0 '--.-System Power
- - - -
0 30.0 - - - -
20.0 - - --- -- -
t
M " rn g
O O O N N
I N �N N N O O O 0 O N0
Fig 2-3. Northern California market price projections for renewable and conventional
electricity
Source: Navigant Consulting, Inc.
2.7.16. Municipal Financing of Renewable Energy Development
A CCA can reduce the cost of acquiring renewable energy by financing development of
the renewable resources used to supply its program. The following Table 2-6 compares
the total cost of a hypothetical 100 MW wind energy project using the financing
structures that are typically available to an IOU vs. those available to a CCA.
The underlying assumptions are that the utility's capital structure is composed of 50%
debt and 50%equity at an overall cost of capital equaling 9%, while the CCA employs
100% debt financing at a rate of 5.5%. The utility is subject to federal and state income
taxes of 40.75%, resulting in a tax-affected cost of capital approximating 12.9%.The CCA
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.
4.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 affect the CCA economic
analysis.
5. It should be noted that the costs of renewable and non-renewable electricity have increased
since the time of the study;however, the renewable cost premium is still about the same.
44
Table 2-6. Cost comparison—IOU vs. CCA ownership of a 100 MW wind resource
(Thousand of Dollars)6
Cost Element Investor-Owned Utility CCA
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
Source: Navigant Consulting, Inc.
During the first year of operation, the CCA can produce energy at a cost that is nearly
40°!%lower than what the IOU would incur if it owned an identical resource. The CCA's
cost of producing renewable energy would be nearly the same as the market price of
system power.
2.7.17. Operational Issues for Renewable Energy
Renewable resources are generally non-dispatchable, which means they cannot be
turned on or off at will. Instead, they can operate as either base load 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. This places 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%.! It would be
possible to exceed these amounts by over-procuring,but that would require the CCA to
sell excess energy into the market during many hours of the year.
For example, if a CCA 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 CCA could
have between 0 and 300 MW of production. The CCA would either need to purchase up
to 200 MW of replacement energy or it would have up to 100 MW of excess energy to
sell. These imbalances impose financial risk on the CCA, as the prices at which it must
buy and sell energy may not be identical.
One way that a CCA could safely exceed the operational limits on renewable energy is
by purchasing renewable energy certificates (RECs) from producers of renewable
energy. The Energy Commission is currently investigating a system that would facilitate
trading of RECs, and private markets for RECs have been in existence for several years.
6.Tax incentives for renewable resource development, such as accelerated depreciation and
production tax credits, can reduce the cost advantage of the CCA to about 15%,.
7. This refers only to the CCA's program operations and is not intended to imply that the entire
system could efficiently integrate such large amounts of renewable energy.
45
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.
2.8. To Build or Not to Build?
There are essentially two strategies for a CCA to obtain the necessary electricity to serve
its customer base: By contracting with energy suppliers, and through ownership of
power generating plants (asset ownership). Under the contracting strategy, the CCA
provider would go to the competitive wholesale electricity market and would have
numerous suppliers provide competitive bids to meet the energy requirements of the
CCA. Under the asset ownership strategy, the CCA provider would meet all or a portion
of its electricity requirement through the ownership of generation assets.
The Energy Commission pilot study found that to beat IOU rates, CCA ownership of at
least some of its generation supply is necessary. Simply buying from the market will at
best match IOU pricing (since the CRS will be added to the market price to equal the
IOU's portfolio average). CCA administrative costs will also need to be covered, which
would result in a greater cost to CCA customers than to similar customers of an IOU.
A CCA pursuing ownership of power generation resources should finance the project
with tax-exempt bonds that provide a cheaper rate of capital than that which is available
to an IOU. The bonds will be backed by the ability of the CCA to collect revenues from
its customers' utility bills and from other power sales agreements entered into by the
CCA provider.
Ultimately, alternative operating scenarios contemplated in the Energy Commission-
funded pilot study demonstrate that resource ownership is critical to the long-term
financial viability of a CCA. Therefore, a CCA implementation strategy should strongly
consider options involving generation ownership/development.
2.8.1. Financial Projections
The total cost of service for the CCA program should be calculated and compared to the
generation costs charged by the IOU. The differences represent potential savings or costs
associated with the CCA program. Any savings should be 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 should be shown both in dollars per
46
year and as a percentage of customers' monthly electric bills.8 The following Table 2-7
provides a sample summary of cost savings from CCA.
Table 2-7. Sample summary of electric cost savings from community choice aggregation
(Millions of Dollars)
Percentage Of
Year Total CCA Costs PG&E Charges Savings Total Bill
2005 - - - 0%
2006 41.3 42.8 1.4 2°o
2007 41.4 43.4 2.0 3%
2008 43.6 44.9 1.3 2%
2009 42.1 45.9 3.8 5%
2010 44.4 48.1 3.7 5%
2011 45.8 49.5 3.7 4%
2012 47.0 51.1 4.1 5%
2013 43.0 48.4 5.3 6%
2014 43.9 49.7 5.7 7%
2015 46.6 51.3 4.7 5%
2016 47.5 52.4 4.9 5%
2017 49.2 54.9 5.7 6°/0
2018 51.9 58.8 6.9 7°°
2019 54.3 62.3 8.0 8%
2020 57.4 64.3 6.9 6%
2021 58.0 64.7 6.8 6%
2022 59.0 66.1 7.1 6%
2023 58.2 66.3 8.0 7%
2024 61.0 70.1 9.1 8%
Total 935.7 1,035.0 99.3 6%
Source: Navigant Consulting: Inc.
In this case, the total nominal savings over the study period are$99.3 million or
approximately 6% of customers' total electricity costs. Cost savings average
approximately$5.2 million per year.
2.9. Sample Feasibility Study
The city of Berkeley has posted the feasibility study completed for it by the Energy
Commission-funded pilot program on its website. It can be viewed at:
http://www.ci.berkeley.ca.us/sustainable/government/CommunityChoice/CCA.html
8.The percentage savings are expressed based on total electric bills, including IOU delivery
charges.The percentage savings on the generation component of bills would be approximately
double the percentages shown.
47
48
3.0 Developing a Community Choice Aggregation
Implementation Plan
3.1. Section Summary
Once the decision has been made to establish a CCA program, an Implementation Plan
(IP) must be filed with the CPUC. This section discusses the necessary requirements for
developing an 1P.
Any local government wishing to establish a CCA program needs to fully inform its
residents, businesses, institutions, and municipal departments of its interests and
intentions. This informational campaign should start very early in the investigative
process in order to secure stakeholder buy-in.
Before developing an IP, a community must make several fundamental decisions. One
key decision is whether the community should act independently and develop a CCA
for its own jurisdiction alone, or whether the community should reach out to other
jurisdictions, forming a joint CCA. The city or county will need to determine whether
the economies of scale are worth sharing decision-making control with other
communities.
Another key choice will be operational structure. How will the duties described in
Section 2.4 be accomplished? Will they be outsourced or will the CCA develop its own
operations center and administrative staff? If out-sourced, the CCA will need to choose
an operator or operators that will be identified in the IP.
The CCA will have to include the source of its electricity in the IP. Therefore, it will need
to get quotes from suppliers and be ready to sign contracts with them in time to
commence serving its customers on an agreed-upon date.
Phasing in operations is allowed. I'hasing may help a CCA work out operational glitches
before having to provide service for the entire community. It may also be a way to
eliminate potential cash flow problems in the early years of implementation. If a phased
program is planned, it must be described in the IP.
Filing an IP initiates actions on the part of the CCA, the CPUC, and the utility. The
CPUC will set the CRS and the earliest possible date for CCA service to commence. The
CPUC may ask the CCA for more information in order to determine the CRS for its
customers.The CCA must inform its potential customers of their right to opt out of the
CCA program (four notices are required: two before customers are switched over to
CCA service, and two after). The CCA must register with the CPUC and post a bond or
other security to cover the cost of program default. Once notified that the CCA program
will begin, the utility must transfer all CCA accounts to the new supplier within a 30-
day period that coincides with its monthly billing process.
49
3.2. Implementation Plan and Statement of Intent Requirements
AB 117 lists the requirements of an implementation plan that must be filed with the
CPUC. Following submittal, the CPUC will use the IP to determine the CCA's
customers' CRS. The 1I'must be adopted at a duly noticed public meeting of the city,
county, or cities and counties forming the CCA.
The IP must include the following elements:
• Program structure, organization, operations, and funding.
• A system for ratesetting.
• Provisions for disclosure in setting rates and allocating costs among participants.
• Methods for entering and terminating agreements with other entities.
• Rights and responsibilities of program participants (consumer protection, credit
requirements, and shutoff procedures).
• A description of third-party suppliers (including financial, technical, and
operational capabilities).
The IP must also be accompanied by a statement of intent, which discusses how the
CCA will address:
• Universal access.
• Reliability.
• Customer class equity.
• Other requirements established by state law or the CPUC.
The San Joaquin Valley Power Authority's implementation plan can be viewed at:
http://www.communitychoice.info/sjvpa/documents.php
3.3. Deciding Whether to Join With Other Communities
Some communities are considering establishing their own CCA. The city and county of
San Francisco, which owns and operates a municipal water and power utility, is one
example. However, other local governments are investigating CCA with neighboring
communities in order to achieve improved financial results through a joint powers
agency (JPA).
By forming a JPA and jointly implementing a single CCA program, local governments
will increase administrative efficiency of the program and should experience cost
savings through economies of scale. Program implementation by individual
communities will require higher investments of time and financial resources (in terms of
cost/kWh), including ongoing operations costs. Collaborative programs also reduce
potential risks for each participating city or county, as all participants share the
program's risk.
50
The primary disadvantage of a JPA is the reduced autonomy for each participating
community.JPAs also involve another layer in the decision-making process, which may
be made more difficult by potentially dissimilar interests of elected officials from
multiple jurisdictions.
3.3,1. Economies of Scale From Combined CCA Operations
By combining the electric loads of multiple cities and/or counties, a CCA should be able
to achieve economies of scale, reducing administrative and operational costs to
individual members. Variations in community load shapes enable sharing capacity
reserves, a savings in total procurement costs. In addition, the load shape of a joint CCA
program should tend to be more statistically normal (when compared to the load shape
of a single community, which would comprise a much smaller statistical sample size
and would reflect the peculiarities of an individual community's load profile), which
will allow the CCA to procure a larger amount of standard, base load energy products
(base load products generally reflect lower pricing when compared to peaking or
dispatchable products).
In general, joint CCA implementation should reduce cost per kWh, resulting in lower
electric rates for CCA customers. Furthermore, a larger organization, such as a JPA-
based CCA program, would wield greater political influence in the regulatory process,
which may result in additional, short- and long-term benefits for the CCA.
The Energy Commission-funded pilot project included a financial assessment that
combined seven Bay Area communities in a common CCA operation. This joint
operation yielded over$300 million (34%) in additional financial benefits during the first
20 years compared to individual CCA operations.
Joint Powers Agency Structure Option
Only cities, counties, or groups of cities and counties are permitted to be CCAs.JPAs are
common legal structures that many public agencies have formed to offer services in a
more economical and efficient manner. CCA implementation involving JPA formation
can combine city and county jurisdictions to secure long-term power contracts or to
develop JPA-owned generating resources.Joint CCAs may benefit from flatter electric
load shapes, which reduce the overall cost of service.
The following describes some of the possible benefits and impediments of the CCA-JPA
organizational structure:
Benefits:
• The JPA structure will enable its members to jointly exercise common powers.
• The CCA-JPA organization will be a public, nonprofit agency.
• Parties to the JPA wi11 share costs/risks and assist with all JPA projects.
51
• JPA formation will allow members to aggregate financial resources when
securing long-term power contracts or entering into agreements to develop
power plants.
• JPA members will benefit from economies of scale when developing generating
resources, as larger generating projects may offer greater operating efficiencies
and lower cost per kWh.
• The JPA will be able to issue low-cost bonds by ordinance subject to referendum
but without a vote of the elected officials within the JPA communities.
• The JPA will minimize exposure of its members to risk while providing access to
capital, political, and intellectual resources of the other JPA members.
• The JPA will reduce or eliminate the need for duplicate staffing and supporting
systems that facilitate energy procurement/supply for its membership.
Impediments:
• Forming a JPA will be time consuming; all parties must agree on the approach
and structure (the fewer the parties, the more streamlined the process).
• Providing equitable representation for both large and small members without
compromising either's options/interests will be a challenge.
• The decision-making process will be cumbersome, during both formation and
operation (decisions tend to be consensus-driven, slowing processes and
compromising positions as members seek to protect their own interests).
• A JPA may result in less control over ratesetting decisions.
Structural Options for a JPA
If a group of cities and counties decides to form a CCA JPA, there are several options to
consider. Three possibilities follow.
Option 1: Single CCA "JPA" Option
Under the single CCA option, the JPA governing board would have primary
responsibility for managing all aspects of a common CCA program.The JPA would
establish itself as a CCA, and the member cities/counties would authorize their
participation in the JPA by resolution or ordinance. The JPA would have a direct
relationship with CCA customers, the IOU, and energy suppliers. Common activities
may include:
• Resource planning and supply solicitations
• Contract management (suppliers, other contractors)
• Project financing
• Regulatory tracking and participation
• Marketing
• Rate design
52
• Program terms and conditions development
• Finance and accounting
• Legal services
The member communities would influence decisions of the JPA governing board
through designated representatives on the board according to the voting rights set forth
in the JPA agreement.
Option 2: Multiple CCA "Association" Option
Under the Association option, each city or county would form its own CCA program.
However, member local governments would engage in common activities related to
their individual CCA programs, primarily the first three activities listed above. Other
supporting activities related to regulatory support, marketing,etc., might also be
performed on a joint basis. It is likely that a JPA would be formed to facilitate the joint
activities that would underlie the individual CCA programs. The activities that could be
jointly undertaken include:
• Resource planning and supply solicitations
• Contract management
• Project financing
• Regulatory tracking and participation (common)
• Marketing (common)
• Finance and accounting (common)
• Legal (common)
The members would individually administer the front-end or customer facing aspects of
their respective programs. Each community would also have responsibility for program
finances and regulatory compliance. The activities undertaken by the individual cities
and counties could include:
• Rate design
• Program terms and conditions
• Regulatory tracking and participation (CPUC registration, compliance reporting)
• Marketing
• Finance and accounting
• Legal
Comparing the two structures, local governments would have greater autonomy under
the association model,but they would also have more responsibility and staffing
requirements. IOU charges for supporting CCA implementation would increase because
there would be multiple CCA entities rather than one. If rates differ among the cities,
there would be greater costs related to administering more than one set of rates,
different opt-out notices, and different program marketing materials.
53
Option 3: Single CCA With Member Rate-Setting Authority
There is also a third option that would combine elements of the two previously
described organizational structures. This organizational structure would be similar to
Option 1 in that there would be a single CCA entity,but members would have the
ability to set unique rates that would be charged to customers within their respective
jurisdictions. Each member would be responsible for collecting enough revenue in rates
to cover its agreed-upon program costs. This approach would retain many of the cost
savings advantages available to a single CCA program, while providing members with
autonomy during ratemaking processes for their cities.
3.3.2. Cost/Benefit Allocation
Under any of these approaches, the JPA would determine its annual program budget or
revenue requirement based on its projected costs of supply, IOU transaction fees,
administration costs, financing costs, reserves, and other costs. The JPA would then
perform a cost-of-service study to allocate costs to customer classes(residential,
commercial, etc.).
If the JPA sets rates for all members (Option 1) then rates would be designed for each
customer class based on cost-of-service and other considerations. Margins (profits) could
be allocated to each member based on the unique margins derived from sales within
each member's boundaries.
The ratemaking decisions of the JPA would impact profits retained by each member, as
customer mixes may differ significantly within each member city or county. In effect, the
JPA would be determining how much of the cost savings should flow through rates
versus how much should be retained by JPA members.
For example, if the JPA established relatively low rates for residential customers and
higher rates for commercial customers, cities or counties with larger proportions of
residential customers would have less profit available to them. Under this approach, the
JPA may need to incorporate bylaws that prevent establishing rates that would result in
negative margins for any member local government.
Alternatively, if member cities will be independently setting rates for their customers
(Options 2 or 3), then the JPA could allocate program costs to each member city or
county, which would, in turn, need to be recovered through the rates established by
each. The cost responsibility assigned to each member of the JPA would be based on the
cost of service for each defined customer class as well as the volume of retail sales
derived from specific customer classes within each member's jurisdiction. Each member
would be responsible for setting its program rates at levels sufficient to recover its total
cost responsibility to the JPA. Members would be free to design rates as they see fit, as
long as these rates result in collections that cover the members' cost responsibility to the
JPA.
The issues that need to be considered in selecting a rate-setting structure (whether the
JPA sets the rates or its members do) are:
54
• The likelihood that consensus can be achieved among JPA members for an
overall program rate structure, including decisions about how benefits should be
allocated among customers/members.
• The preference to have rates established by the JPA, with a single focus on the
CCA program, rather than by multiple local governments with potentially
dissimilar goals/objectives.
• The willingness of member cities and counties to take on the extra burdens in the
"Association" model (Option 2).
• The likelihood that the ratemaking authority provided in Option 3 will satisfy
desires for local control and self-determination.
• The balance between the additional costs and complexity associated with
maintaining multiple rate structures and the perceived or actual benefits
conferred to each community by allowing unique service rates.
3.3.3. Revenue Bond Issuance
A JPA may issue revenue bonds by ordinance subject to a vote of its constituents but
without a vote of the elected officials within the cities or counties comprising the JPA.
JI'As may also issue securities by resolution of the JPA backed by loan agreements
and/or bond purchase agreements with participating member agencies. The law
provides that some, but not necessarily 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.
For a list of financing alternatives to consider once a JPA has been formed, see Appendix
C.
The financing method that is ultimately chosen by the CCA-JPA will be based on a
number of factors:
• Purposes of Financing. Proceeds from financing can be used for a number of
different purposes, including but not limited to:
c Startup costs
c Construction of new facilities and equipment
o Initial capital for power purchases
o Operations and maintenance expenses
The purpose of financing can and will affect the type of bond issue that the
CCA-JPA may utilize. In the end, the JPA may execute a series of financing
transactions to meet each of its various purposes.
• Tax Eligibility. An important consideration in determining the appropriate
financing technique required to fund specific transactions will depend largely on
the tax-exempt eligibility of the potential financing. As all objectives (i.e.,
purposes and uses of the proceeds) of the financing become known, counsel for
the JPA will be able to make a determination as to whether or not the JPA will be
eligible to issue tax-exempt bonds. A structure that maximizes the use of tax-
exempt bonds will ultimately provide the lowest cost of financing to the JPA.
3.4. Implementation Models
There are a variety of approaches a community may take when implementing a CCA
program. The approaches vary depending on the amount of operational control and the
potential benefits and risks assumed by the community.
3.4.1. Single Third-Party Supplier
At one end of the spectrum, the CCA may choose to out-source administrative
responsibilities of the program to a third-party energy supplier. The CCA essentially
serves as a liaison between electric customers of the CCA and the third-party energy
supplier. It would have no hands-on administrative responsibilities.
To develop such an arrangement, the community must first solicit offers from electric
suppliers to serve its customers. In its request for bids, the CCA would detail its desired
administrative framework, which would largely rely on the energy supplier to perform
the necessary administrative functions of the program. During negotiations with the
prospective energy supplier, the CCA may choose to include provisions that guarantee
discounts relative to IOU rates. This would transfer cost-specific risks from the CCA to
the energy supplier.
This approach offers very little risk to the community, but it also limits the potential for
significant financial savings, particularly when considering the foregone benefits of
municipal-financing (the financing of locally owned generation assets). A CCA should
also consider that energy suppliers may not be willing to agree to such an approach.The
energy supplier may feel that certain risks, such as changes in IOU rates or the CRS, are
not manageable.
Because it is unlikely that suppliers would charge less than the market price of
electricity, potential cost savings would be doubtful. The additional costs imposed by
the CRS would put program costs above those charged by the market and, likely, the
IOU. Bids from electricity suppliers should be obtained early in the CCA's
implementation planning process to help determine whether this approach is viable.
3.4.2. Multiple Third-Party Service Providers
In this approach, the community would unbundle program services and would negotiate
individual contracts with third parties for each discrete service (e.g., billing service,
scheduling coordination, electric supply). The CCA would assume overall responsibility
for the program and for the performance of its contractors. In this scenario, the CCA
would retain responsibility for rate-setting, establishing program policies, and general
administration of the program.
This approach offers several advantages to the CCA, including limited staffing
requirements, increased administrative control (when compared to the Single Third-
Party Supplier option above), diffusion of risk (associated with supplier default), and
56
accumulation of industry knowledge and experience (gained through the execution of
day-to-day administrative responsibilities and interaction with service contractors).
Under this approach, the CCA would be independently accountable for the results
achieved by the program, regardless of success or failure.
3.4.3. Municipal Operations
In the longer term, the community could develop the organizational structure required
to operate all aspects of the CCA program using in-house staff and resources. Recruiting
skilled professional staff with electricity operations experience could be challenging and
may not be feasible for most CCAs in the initial years. Over time, as the CCA gains
experience with the program, some or all of the functions that were initially outsourced
could be brought in-house.
3.5. Getting Quotes From Suppliers and Operators
A request for bids (RFB) should be used to screen potential suppliers for qualifications
and obtain price offers for the services required. A single RFB can be used for electric
supply as well as the customer account services that arc needed for operation of a CCA
program. Developing the RFB requires forethought and good definition of the desired
services, including parameters of how bids should be structured. The goal should be to
obtain responsive bids that can be compared on an apples-to-apples basis. A good
approach is to establish minimum bid requirements from bidders and allow for
submission of creative alternatives in addition to the minimum requirements bids.The
RFB should be conducted after the basic program implementation approach has been
decided but before the formal IP is submitted to the CPUC.
There are several steps involved in developing an RFB for services needed by the CCA
program:
• Develop forecast of customers and annual kWh sales for the primary customer
classifications (residential, commercial, industrial, agricultural, street lighting,
etc.).
• Define customer load profiles: monthly kWh and KW by class, hourly kW by
class.
• Specify desired length of contract terms and dates upon which service will
commence and terminate.
• Identify the specific services requested, such as full requirements for electricity,
renewable energy, and customer account services (customer enrollment, bill
calculations, payment tracking, and customer services).
• Determine whether prices should be fixed, indexed, or a combination of fixed
and indexed prices.
• Determine the schedule for RFB release, bidders' conference, responses due,
evaluation, contract negotiation/due diligence, and contract execution.
57
• Specify minimum bid requirements including, for example, the need to meet
minimum renewable portfolio requirements and resource adequacy standards.
• Develop a standard bidder's template and format for offers.
• Consider whether alternative bid structures will be accepted.
• Define requirements for qualification, including requiring financial statements,
credit ratings, and references.
• Determine whether specific resource types are desired (renewable types, natural
gas-fired, etc.).
• Determine evaluation criteria.
• Determine recipients of RFB, e.g., public posting, pre-screened suppliers, and/or
industry press.
3.6. Phasing?
CCAs will not be required to serve all their customers from Day One. CPUC decisions
allow CCAs to phase in their programs. There may also be clear benefits to phasing in
program operations, such as:
• Phasing in service can reduce implementation risk by enabling a pilot program to
work out any glitches before rolling the program out to all customers.
• A phased implementation approach can help eliminate potential cash problems
that might otherwise occur in the early years of CCA implementation.
AB 117 does not prohibit a CCA from offering service to a portion of the customers
within its jurisdiction. However, AB 117 clearly states that CCAs must offer service to all
residential customers. Presumably, the transfer of residential accounts could be phased in
without violating the residential must-offer requirement.
The CPUC has stated that the decision to establish a phase in or pilot implementation
program should be determined by the CCA, not the IOU or CPUC.The CPUC also
found that a phase in or pilot program may impose additional costs on an IOU that can
be recovered from the CCA. Conversely, some phase in plans may actually reduce IOU
costs. The IOUs are permitted to negotiate with CCAs regarding phase-in plans that may
reduce costs.
3.7. Developing a Marketing Campaign
Any local government wishing to establish a CCA program needs to fully inform its
residents, businesses, institutions, and municipal departments of its interests/intentions.
This informational campaign should start very early in the investigative process in order
to secure stakeholder buy-in.
Switching from a known supplier (an IOU) to a largely unknown, new energy provider
will be a concern for large energy users, and just about everyone else. Business owners
will require assurances with respect to service reliability (this should not be a problem
58
since the IOUs will continue to deliver the power and maintain the transmission and
delivery system for their own customers as well as those of the CCA), price stability, and
cost savings. Other constituents may have different concerns, such as those affected by
low-income subsidies, or those interested in opportunities for energy efficiency.
Involving the constituents early and often will instill a feeling of ownership during
decision-making processes, and, ultimately, in the local government's final
determination with respect to CCA implementation. Anyone who decides to approach
the city council or county board of supervisors with a CCA plan that has not been fully
vetted in a public forum should expect major opposition. San Francisco and Chula Vista
have scheduled multiple community workshops in an effort to make important
information readily available to community members.
Similarly, the East Bay communities of Berkeley, Emeryville, and Oakland have
established a process involving joint stakeholder workshops to solicit and gather
community input during the decision-making stage. These communities will utilize the
information collected in these forums to develop the best possible structure for a joint
CCA in the event that the decision to form a CCA is approved. Each city will also use
education campaigns for its own constituents. Marin County is developing a process
similar to that of the East Bay communities.
Local governments considering CCA should also develop a marketing plan and related
materials.This can be completed during the community workshop stage and will be
critical in educating residents and businesses owners before customers are switched
from the IOU to the CCA. Cities and counties interested in CCA formation should check
with other communities that have established, or are in the process of establishing, a
CCA program to discuss ideas and materials. They should also use as many of their own
resources/publications as possible (water and garbage bills, tax notices, etc.) to inform
and educate members of their community.
As part of the implementation process, CCA programs must provide two distinct notices
to potential customers at least 60 days before CCA operations begin. These notices must
include instructions on how to opt out of the CCA program. Opting out of CCA service
means the customer continues to receive electric services from an IOU (all CCA
customers remain IOU customers for transmission and delivery; CCAs will provide the
electric commodity only). CCAs must provide two additional notices within 60 days
after CCA operations start.
Without a concerted effort to educate all community constituents prior to the first opt
out notification, there will be many questions to answer during this period. Ultimately, a
lack of communication may result in many customers remaining with IOU service. A
CCA should establish a call center before the start of operations to help address
questions and concerns before the opt-out notification period.
59
3.8. Requirements After Filing the Implementation Plan
Filing an Implementation Plan with the CPUC activates certain timelines and related
requirements:
• The CPUC will notify the IOU within 10 days of IP filing that the CCA has filed
the plan.
• Within 90 days of IP filing, the CPUC shall certify that it has received the IP,
including any additional information necessary to determine cost recovery
surcharge. The CPUC shall designate the earliest possible date for
implementation of a CCA program.
• The CCA must offer the opportunity to purchase electricity to all residential
customers within its political boundaries, although the IP can include a plan for
phasing in community participation.
• The CCA must fully inform all customers of their right to opt out of the CCA
program and to continue receiving service as a bundled customer from the IOU.
All customers must be notified twice within 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.
• Customer notification must contain the following information:
o Those customers will be automatically enrolled.
o That each customer has the right to opt out of the program without
penalty.
o The terms and conditions of CCA service.
• The CCA may request the CPUC to order the IOU to provide these customer
notifications in its regular monthly billing at the CCA's expense.
• The CCA 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. At the time of registration, the CCA 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 the IOU.
• The CCA must notify the IOU when its service will begin within 30 days.
• Once notified, the IOU 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.
• The IOU shall recover from the community any costs reasonably attributable to
the CCA, as determined by the CPUC.
3.9. Model Implementation Plan
URL to plan: http://lgc.org/cca/index.html
60
Glossary of Terms
Word Definition
Assembly Bill 117 (Migden, AB 117 grants cities and counties, or groups of them,
Chapter 838, Statutes of 2002) the authority to competitively procure electric
services rather than continuing to rely on the IOU as
the supplier for electric services to customers within
the community. AB 117 was signed into law in 2002.
It has been integrated into California's Public
Utilities Code, primarily in Section 366.2, but with
other provisions in Sections 218.3, 331.1, 366, 381.1,
394, and 394.25.
Assembly Bill 1890 (Brulte, AB 1890 was California's electricity restructuring
Chapter 854, Statutes of 1996,) legislation signed by Governor Wilson in 1996. It
allowed customers to purchase electricity from
providers other than the monopoly utilities. The
utilities were required to divest their thermal power
plants in an effort to make the market more
competitive. They therefore had to purchase about
half of their electricity from the market. Residential
consumers were given a 10%, rate decrease and a cap
on what they could be charged until the utilities
paid off their uneconomic assets.
Aggregator An aggregator is an entity responsible for procuring,
planning, scheduling, accounting, and settling
electricity deliveries for electricity supplies to a
group of end customers.
Base Load Base load is the lowest level of power production
needs during a season or year. Base load power
plants generally operate continuously due to long
startup times. Electricity from base load plants is
generally the cheapest. To meet demand, base load
electricity is supplemented with peak load and spot
market supplies.
61
Word Definition
Bill-Ready Billing Bill-ready billing is one of two methods that a CCA
can use to invoice its customers. It requires the CCA
to apply its rate schedule to the electricity used by
each of its customers and then provide the utility
with the amount to charge. Pacific Gas and Electric,
Southern California Edison, and San Diego Gas&
Electric can process bill-ready billing.
Bundled Customers Bundled customers of investor-owned utilities
(IOUs) are the customers who are not allowed to
choose another electricity provider, or who remain
with the IOU after a CCA is formed.
California Alternate Rates for CARE Program provides a 20 percent discount on
Energy (CARE) monthly bills for qualified low-or fixed-income
households and housing facilities. Qualifications are
based on the number of people living in the home
and the total annual household income.
California Department of Water The Department of Water Resources stepped in to
Resources (DWR) purchase electricity for the utilities following the
energy crisis of 2000-2001. It negotiated contracts
with energy suppliers and issued bonds to cover
some of its costs. All customers of the utilities
during that crisis period will to continue to pay
these costs until they are fully paid.
California Energy Commission The California Energy Commission is the sponsor of
(Energy Commission) the pilot program to investigate CCA feasibility that
produced this guidebook.
California Independent System The California Independent System Operator is a
Operator (California ISO) not-for-profit public-benefit corporation charged
with operating the majority of California's high-
voltage wholesale power grid. California ISO is the
link between power plants and utilities, and
balances the demand for electricity with an equal
supply of megawatts.
California Public Utilities The California Public Utilities Commission is the
Commission (CPUC) state agency charged with oversight of the investor-
owned utilities and with implementing AB 117. The
CPUC has instituted a rulemaking, and issued two
decisions on community choice aggregation.
62
Word Definition
Capacity Capacity is the amount of electric power for which a
generating unit, generating station, or other
electrical apparatus is rated either by the user or
manufacturer.
Capacity Factor Capacity factor is a percentage that tells how much
of a power plant's capacity is used over time. For
example, typical plant capacity factors range as high
as 80 percent for geothermal and 70 percent for
cogeneration.
Community Choice Aggregation These terms are used interchangeably. Any city or
and Community Choice county whose governing board elects to combine
Aggregator (CCA) the loads of its residents, businesses, and municipal
facilities in a community-wide electricity buyers
program; or any group of cities, counties, or cities
and counties whose governing boards have elected
to combine the loads of their programs, through the
formation of a joint powers agency, as long as that
entity is not within the jurisdiction of a local
publicly owned electric utility that provided electric
service as of January 1, 2003.
Competitive Transition Charge The CTC is a charge authorized by the California
(CTC) Public Utilities Commission that is imposed on
investor-owned utility customers to recover the
J
costs of utility investments made on behalf of their
customers. The CTC is to be collected in a
competitively neutral manner that does not increase
rates for any customer class solely due to the
existence of transition costs.
63
Word Definition
Cost Responsibility Surcharge The CRS is charged to CCA customers to offset any
(CRS) negative impact CCA formation may have on the
rates of an investor-owned utility's (IOU) remaining
bundled customers. It is determined by comparing
the required rates for all IOU customers (including
the ones about to leave for a CCA program) to the
required rates of the IOU without the departing
CCA customers. Components of the CRS include
high-cost contracts signed by the Department of
Water Resources (DWR) and the IOUs following the
energy crisis of 2000 and 2001, DWR bond costs, and
other high-priced generation assets of the IOUs.
Delivery Service Delivery service is the delivery of power over
investor-owned utility transmission and distribution
facilities.
Demand-Side Management Demand-side management includes actions taken
on the customer's side of the meter to change the
amount or timing of energy consumption.
Departing Load Departing load is the amount of electricity that will
no longer be supplied by an investor-owned utility
due to direct access, self-generation, or community
choice aggregation.
Deregulation Deregulation or restructuring is the opening of
previous monopoly markets for electricity. In
California, AB 1890 restructured the electricity
market to allow other suppliers to compete with the
investor-owned utilities for customers.
Direct Access (DA) Direct access is the ability of a retail customer to
purchase commodity electricity directly from the
wholesale market rather than through a local
distribution utility. Currently only direct access
customers who were in signed agreements before
the process was suspended following the energy
crisis of 2000 and 2001 can participate. No new
direct access agreements have been allowed since
2002.
64
Word Definition
Distribution System A distribution system is the means of the delivery of
electricity to the retail customer's home or business
through low-voltage distribution lines.
Distributed Generation (DG) A distributed generation system involves small
amounts of generation located on a utility's
distribution system for the purpose of meeting local
loads and/or displacing the need to build additional
(or upgrade) local distribution lines.
End-Use Customer (End-user) An end-use customer is a residential, commercial,
agricultural, or industrial electric customer who
buys electricity to be consumed as a final product
(not for resale).
Energy Efficiency Energy efficiency is using less energy to perform the
same function. An example would be replacing an
incandescent light bulb with a compact fluorescent
light(CFL) bulb that produces the same amount of
light. CFLs generally use about 1/4 of the energy of
incandescent bulbs to produce the same amount of
light.
Energy Service Provider(ESP) ESPs arc third-party operators or energy services
providers, such as marketers or aggregators, who
provide electricity directly to an end-use customer
in the direct access market.
Exit Fees Once a CCA program begins, its customers will
have 60 days to opt out at no cost. After the initial 60
days, exit fees may be imposed to cover any financial
commitment the local aggregator has made to
power suppliers on a customer's behalf. For the
majority of residential customers, such exit fees will
be small, since most residents, and many small
businesses, are relatively small consumers of
electricity.
Federal Energy Regulatory The Federal Energy Regulatory Commission is an
Commission (FERC) independent agency that regulates the interstate
transmission of natural gas, oil, and electricity.
FERC also regulates natural gas and hydropower
projects.
65
Word Definition
General Rate Case General rate case is the filing that an investor-
owned utility makes to the CPUC to adjust the rates
it charges its customers.
Generation Services Generation services are power plants that produce
electricity.
Green Energy Green energy is usually defined as non-polluting,
renewable energy such as solar photovoltaics, solar
thermal, wind, geothermal, and landfill gas.
Different entities use different definitions.
Implementation Ilan Implementation plans are required of potential
CCAs. They must be adopted at a public meeting of
the city, county, or joint cities and counties that will
file the plans with the CPUC. They have certain
requirements in the law. The CPUC will use the
implementation plans to determine the cost
responsibility surcharge for a CCA's customers.
Investor-Owned Utility (IOU) For purposes of the CCA Program, IOU refers to
Pacific Gas and Electric Company, Southern
California Edison Company, and San Diego Gas &
Electric Company, the three electrical corporations
whose ratepayers could switch over to a CCA
program.
Joint Powers Agency (JPA) A JPA is an agreement between more than one
government entity to cooperate on a particular
program or project. A JPA can be between all levels
of government (local, state, and federal). Only cities
and counties can enter into a JPA to establish and
operate a CCA.
Kilowatt (kW) The kilowatt is a unit for measuring power,equal to
one thousand watts. A kilowatt is roughly
equivalent to 1.34 horsepower.
Kilowatt-flour (kWh) A kilowatt-hour is the most commonly used unit of
measure telling the amount of electricity consumed
over time. It equals one kilowatt of electricity
supplied for one hour. A typical California
household consumes about 500 kWh in an average
month.
66
Word Definition
Levelized Cost To compare the cost of a wide variation of
generation types, a levelized cost method is used.
Levelized cost considers the total electrical energy
that a power plant will produce in its lifetime and it
is divided by the total cost of construction along
with the interest and the cash flow during
construction plus the operation and maintenance
cost. Everything is compared using present money
worth.
Liquified Natural Gas (LNG) Natural gas that has been condensed to a liquid,
typically by cooling the gas to minus 260 degrees
Fahrenheit (below zero), or 162 degrees Celsius
(below zero).
Local Governments California cities, counties, or city and county joint
powers agencies count as local governments for the
purposes of CCA. Special districts cannot form a
CCA.
Load Profile The electricity uses of all of the customers of a load-
serving entity are added together for each hour of
the day for a full year to develop its load profile.
Load-Serving Entity (LSE) Load-serving entities are the organizations that
directly provide electric power to end-use
customers.
Megawatt (MW) The megawatt is equal to one million (106) watts.
The productive capacity of electrical generators
operated by utility companies is often measured in
MW. A typical modern nuclear power plant
produces a peak output on the order of 500 to 2000
MW.
Municipalization Municipalization is the act of forming an electric
municipal utility by replacing the existing IOU with
a locally owned electric utility and involves securing
the infrastructure to deliver electricity either by new
construction or by condemnation by eminent
domain of the wires and poles of the IOU.
67
Word Definition
Municipal Utility A municipal utility is a local publicly owned
(customer-owned) electric utility that owns or
operates electric facilities. Examples include the Los
Angeles Department of Water & Power and the
Sacramento Municipal Utility District.There are
many smaller examples around the state.
Non-dispatchable Non-dispatchable resources are ones that cannot be
turned on and off when needed. Solar and wind are
non-dispatchable since they are available only when
the sun is shining or the wind is blowing.
Northeast Ohio Public Energy NOPEC was formed in 2000 as a public aggregation
Council (NOPEC) to purchase electricity on behalf or residents and
small businesses in member communities. Today,
NOPEC consists of 116 member communities and is
the largest public energy aggregator in the United
States.
Open Season Open season allows a CCA to commit to a date on
which responsibility for customer power purchases
will switch from the IOU to the CCA. The Open
Season is strictly voluntary and will occur annually
from January 1 to February 15 or March 1,
depending upon the timing when the California
Energy Commission's resource adequacy forecasts
are due. The primary objectives of the open season
process are to reduce costs incurred by CCAs and
the IOUs, and to provide a mechanism for
coordinating a CCA's transfer of customers.
Opt In/Opt Out An aggregation program that is opt out
automatically enrolls all customers within the
aggregator's territory. Customers may opt out of the
aggregator's program to remain as customers of the
utility. An opt in aggregation program requires each
customer to individually agree to join the program.
Pacific Gas and Electric (PG&E) Pacific Gas and Electric is the investor-owned utility
serving most of Northern California.
68
Word Definition
Peak Load Peak load indicates the additional demand placed
on a system, above the normal base load needs.
Peaking power plants can respond quickly to
changes in demand. Peak load electricity generally
costs more than base load.
Phasing or Phasing In AB 117 requires that any CCA program offer
electricity to all of the residents in the CCA's
territory. The law and the rules decided by the
CPUC allow a community to phase in operations.
That is, the CCA does not have to serve all of its
customers on the first day of operations. It can add
them in steps over a period, as long as all residential
customers are eventually offered service.
Photovoltaic (PV) Photovoltaic is a solar power technology that uses
solar cells or solar photovoltaic arrays to convert
light from the sun directly into electricity.
Power Purchase Agreement A power purchase agreement is a contract for the
(PPA) purchase of electrical energy and/or capacity.
Production Tax Credits A renewable production tax credit can be thought of
as a reward that the federal or state government
pays to companies that generate energy from
renewable sources such as wind power. The federal
government currently offers a renewable production
tax credit of 1.8 cents per kilowatt-hour. As a tax
credit, it can only be used to reduce the amount of
taxes a firm owes. Non-tax-paying entities such as a
CCA can take advantage of the similar Renewable
Energy Production Incentive.
Public Interest Energy Research The California Energy Commission's Public Interest
(PIER) Energy Research (PIER) Program supports energy
research, development and demonstration (RD&D)
projects that will help improve the quality of life in
California by bringing environmentally safe,
affordable and reliable energy services and products
to the marketplace. The PIER Program funded this
project and guidebook.
69
Word Definition
Qualifying Facility (QF) QFs are non-utility power producers that often
generate electricity using renewable and alternative
resources, such as hydro, wind, solar, geothermal,
or biomass (solid waste). QFs must meet certain
operating, efficiency, and fuel-use standards set
forth by the Federal Energy Regulatory Commission
(FERC). If the QFs meet these FERC standards,
utilities must buy power from them. QFs usually
have long-term contracts with utilities for the
purchase of this power, which is among the utility's
highest-priced resources.
Rate-Ready Billing With rate-ready billing, the CCA provides the rate
schedule to the utility that applies it to customer
usage to develop the charge amount. PG&E is the
only utility to offer rate-ready billing, but for fewer
tiers of service than its own rate schedule. This will
make it difficult for consumers to compare the
CCA's rates to PG&E's.
Renewable Energy Renewable energy comes from resources that
constantly renew themselves or that are regarded as
practically inexhaustible. These include solar, wind,
geothermal, hydro, and biomass. Although
particular geothermal formations can be depleted,
the natural heat in the Earth is a virtually
inexhaustible reserve of potential energy.
Renewable resources also include some
experimental or less-developed sources such as tidal
power, sea currents, and ocean thermal gradients.
Renewable Energy Credits (REC) Renewable energy credits are tradable units that
represent the commodity formed by unbundling the
environmental attributes of a unit of renewable
energy from the underlying electricity. Under most
programs, one REC would be equivalent to the
environmental attributes of one megawatt-hour of
electricity from a renewable generation source.
70
Word Definition
Renewable Energy Production The Renewable Energy Production Incentive (KEPI)
Incentive (REI'l) provides financial incentive payments for electricity
produced and sold by new qualifying renewable
energy generation facilities. Qualifying facilities are
eligible for annual incentive payments of 1.5 cents
per kilowatt-hour (1993 dollars and indexed for
inflation) for the first 10-year period of their
operation, subject to the availability of annual
appropriations in each federal fiscal year of
operation.
Renewables Portfolio Standard California's Renewables Portfolio Standard requires
(RPS) retail sellers of electricity to supply 20%of their
electricity from renewable resources by 2010.
Eligible renewable resources include biomass, solar
thermal, photovoltaics, wind, geothermal, fuel cells
using renewable fuels, small hydropower of 30
megawatts or less, digester gas, landfill gas, ocean
wave, ocean thermal, and tidal current. Municipal
solid waste is generally eligible only if it is
converted to a clean-burning fuel using a non-
combustion thermal process.
Renewable Resources The Renewable Resources Development Report is
Development Report(RRDR) organized to provide an indication of changes in
development of renewable energy resources over
time, moving from past to present to future. It
provides a historical context for renewable
electricity generation in California and the other
states in the Western Electricity Coordinating
Council (WECC). The renewable resources included
in this report are wind, geothermal, biomass, biogas,
solar photovoltaic, concentrating solar power, small
hydroelectric, and ocean energy.
Revenue Requirement The revenue requirement for a utility or CCA is the
amount of money that must be collected from
ratepayers to cover its costs.
Rulemaking 03-10-003 The California Public Utilities Commission
established Rulemaking 03-10-003 to decide the
implementation issues of CCA. Decisions were
adopted in December 2004 and December 2005.
71
Word Definition
San Diego Gas & Electric San Diego Gas & Electric Company is the investor-
Company (SDG&E) owned utility that serves the San Diego area with
gas and electricity.
San Joaquin Valley Power The SJVPA is the first entity in California to file a
Authority (SJVPA) Community Choice Aggregation Implementation
Plan with the CPUC. The SJVPA plans to start
serving customers in November 2007.
Self-Generation Self-generation is a generation facility dedicated to
serving a particular retail customer, usually located
on the customer's premises. The facility may either
be owned directly by the retail customer or owned
by a third party with a contractual arrangement to
provide electricity to meet some of the customer's
entire load.
Sensitivity Analysis A sensitivity analysis allows a researcher to model
the best- and worst-case scenarios for variables. For
example, starting with the expected future cost of
natural gas for the next 20 years, a sensitivity
analysis might test the impacts of natural gas cost
that is 25%higher or lower than the expected cost.
Southern California Edison Southern California Edison Company is the
Company (SCE) investor-owned utility that serves most of Southern
California outside the San Diego area with
electricity.
Spot Market Spot market purchases and sales are used to fill the
load requirements that remain after using both long-
term and short-term contracts and/or CCA-owned
generating resources.
Statement of Intent Along with an implementation plan, a CCA must
file a statement of intent with the CPUC that
addresses universal access, reliability, and customer
class equity.
72
Word Definition
Supplemental Energy Payments Production incentives, referred to as supplemental
(SEP) energy payments (SEPs), will be awarded to eligible
renewable generators for the above-market costs of
eligible electricity procurement by California's three
largest investor-owned utilities (IOUs) to fulfill their
Renewables Portfolio Standard obligations.
Transmission System The transmission system is an interconnected group
of electric transmission lines and associated
equipment used to move or transfer electric energy
in bulk between points of supply and consumption.
Utility-Retained Generation Utility-retained generation is a term for the power
(URG) plants the utilities did not divest, such as nuclear
power plants and hydro-electric facilities.
Vintaging Vintaging is a term used to describe the how CCAs
could have different cost responsibility surcharges
based on when they commence serving their
customers.
Wheeling Electricity Wheeling is the transmission of electricity by an
entity that does not own or directly use the power it
is transmitting. Wholesale wheeling is used to
indicate bulk transactions in the wholesale market,
whereas retail wheeling allows power producers
direct access to retail customers.
73
Appendix A
Sample Data Request Letters
[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
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 CPUC'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]. The
[CITY/COUNTY OF NAME] appreciates your assistance.
Sincerely,
APA-1
[DATE]
San Diego Gas & Electric Company
Attention: [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE NAME]
101 Ash Street
San Diego, CA 92101
SUBJECT: Information Request Per D.03-07-034
Dear [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE NAME]:
The [CITY/COUNTY] of [NAME] (CITY OR COUNTY) is currently reviewing its options in
becoming a Community Choice Aggregator (CCA), in accordance with legislation enacted
in 2002 (Assembly Bill 117), 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 San Diego
Gas& Electric Company (SDG&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].
• Aggregate annual usage data (kWh) broken out by city, zip code, and customer and
rate classes, on a monthly basis.
• Public Goods Charge customer payments by zip code and city. Quarterly or monthly
aggregated participation data already tracked for CPUC reports.
• The proportional share in a CCA's territory or proposed territory as defined in the
CPUC's energy efficiency policy manual.
Please include the number of electric service accounts in the first bullet above and separate
the information between customers currently receiving bundled utility service from SDG&E
and customers currently served under direct access arrangements.
The [CITY OR COUNTY] understands that D.03-07-034 ordered that SDG&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]. The
[CITY/COUNTY OF NAME] thanks you for your assistance.
Sincerely,
APA-2
[DATE]
Southern California Edison Company
Attention: [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE NAME]
PO Box 800
2244 Walnut Grove Ave,
Rosemead, CA 91770
SUBJECT: Information Request Per D.03-07-034
Dear [LOCAL GOVERNMENTAL AFFAIRS REPRESENTATIVE NAME]:
The [CITY/COUNTY] of[NAME] (CITY OR COUNTY) is currently reviewing its options in
becoming a Community Choice Aggregator (CCA), in accordance with legislation enacted
in 2002 (Assembly Bill 117), 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 Southern
California Edison Company (SCE) 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].
• Number of accounts in each rate group.
• Aggregate consumption (monthly kWh) for each rate group.
• Aggregate noncoincident demand in each rate group where metered demand data is
available.
• Coincidence factors which estimate coincident demands where metered data is
available.
• Standard system average load profiles by rate group, to estimate load shapes.
• The proportional share in the potential CCA territories, as defined in the CPUC's
energy efficiency policy manual.
Please separate the information in bullets 1 and 2 above between customers currently
receiving bundled utility service from SCE and customers currently served under direct
access.
The [CITY OR COUNTY] understands that D.03-07-034 ordered that SCE "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]. The
[CITY/COUNTY OF NAME] thanks you for your assistance.
APA-3
Sincerely,
APA-4
Appendix B
Key Assumptions Used in CCA Feasibility Analysis and
Modeling for the California Energy Commission Pilot Project
Feasibility Studies Completed in 2004 and 2005
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 (w
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 (c_o$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 Information Technology (IT).
d) Activities include scheduling coordination, procurement/planning, risk
management, credit, rates and load research, Administration and General, 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 CAISO-required
ancillary services, up to 15% of peak load.
c) Costs of meeting planning reserves equal to market value of capacity.
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.
APB-1
b) The cost and resource mix comprising the portfolio is derived from the Energy
Commission's Renewable Resources Development Report (RRDR) (2003). See RRDR
Table 4, page 37 and discussion at page 87. Costs from the year 2005 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.
(-1) 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 include a risk factor of$5 per
MMWh 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 RI'S. 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
distributed generation production, if any, will be in addition to the RPS
minimums.
1) Supplemental energy payments are available to offset the incremental costs of
renewable contract purchases (10-year terms) up to the minimum RPS
requirement. Public Goods Charge funds are sufficient to buy down 100% of the
cost premium of renewables.
m) Supplemental energy payments are not available for city-owned resources and
are 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 2010.
APB-2
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 Navigant Consulting, Inc. in January
2005.
c) Implied system clearing heat rates for 2005-2010 are 8,000, 8250, 8700, 9000,
10,000, and 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, and Replacement Reserve.
j) 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, and Congestion Charge.
1) 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
CCA's choosing to own generation will acquire equity interests in combined cycle
gas turbine facilities based on the following cost and operating parameters:
a) Installed cost of$700 per KW.
b) Heat rate of 7,000 mmbtu/MWh.
c) $3 per MWh fixed and variable operations and maintenance.
d) 0.1 pounds per MWh emissions.
e) $10 per pound cost of Nitrous Oxides (NOx) emissions.
f) 90% planned capacity factor.
APB-3
g) 2% forced outage rate.
h) Excess sales sold at prevailing market clearing prices.
8) Cost Responsibility Surcharges
a) Cost Responsibility Surcharges (CRS) 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 CRS for CCAs.
d) CRS includes DWR bonds, DWR power charge, utility Competitive Transition
Charge (CTC), and Regulatory Asset (PG&E bankruptcy charge).
e) Uniform indifference fee per KWh for all CCA customers, regardless of rate class
and CCA startup date. No baseline credits reflecting Assembly Bill 1X
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 CRS.
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.
e) PG&E-owned generation resources includes Nuclear(Diablo Canyon), Hydro,
and Fossil facilities. Production and sales data are from I'G&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.
APB-4
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°A° 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.
APB-5
Appendix C
Alternative Financing Methods
Financing General Limited Special Certificates of Revenue
Method/ Obligation Obligations Assessment Participation Bonds
Characteristics Bonds Bonds
Project Acquisition Acquisition Facilities of Unrestricted Revenue
Financeable and and local benefit producing
improvements improvement to property facilities
of land and s of land and
buildings buildings
Authorization Issuer's Resolution of Resolution of Resolution of Resolution of
governing issuer issuer, issuer issuer
board and governing petition of governing governing
public election board and beneficiaries board board
(2/3 vote) 2/3 vote
Area of Boundary of Boundary of Flexible N/A Service area
Authorization issuer facilities issuer of issuer
Jurisdiction district facilities
(flexible) district
(flexible)
Hearing None None Majority Maybe None
Procedure protest ordinance
hearing adoption
Validation None None None None None
Nature of debt Unlimited ad Portion of Annual Rental or Service
service payments valorem tax current assessments installment charges and
revenues based on payments fees from
benefits users
received;
property
taxes may
not be used
Source of debt Property General Annual General and/or Service
service payment owners in revenues of property enterprise charge and
issuer issuer assessments revenues of fee
jurisdiction issuer collections
Security Full faith and Revenue Tax Lease or Coverage
credit collections collections/ installment sale test and
and coverage Foreclosure contract contracts
test
Lessor/Lessee No No No Yes No
Required
Refundable Yes Yes Yes Yes Yes
Debt Service No No No Yes Yes
Funds Subject to
Gann Limit
Reserve Fund No Yes Yes Yes Yes
AI'C-1
Financing General Limited Special Certificates of Revenue
Method/ Obligation Obligations Assessment Participation Bonds
Characteristics Bonds Bonds
Capitalized No No Yes Yes New
Interest enterprise
only
Debt Service No Yes Value/lien No Yes
Coverage ratio 3:1
Method of Sale Competitive or Competitive Competitive Competitive or Competitive
Negotiated or Negotiated or Negotiated Negotiated or Negotiated
Advantages Lower interest No pledge of Isolates No voter Higher
rate General Fund projects approval interest rate
Disadvantages Voter approval Voter Limited Highly Debt Service
required approval security structured Reserve
Higher Limited Fund
interest rates flexibility
APC-2