HomeMy WebLinkAboutAgenda Packet 2004/05/19
CITY COUNCIL AGENDA
Adjourned Regular Meeting
Wednesday, May 19,2004 6:00 p.m.
Council Chambers
Public Services Building
276 Fourth Avenue, Chula Vista
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CllY OF
CHUlA VISTA
City Council City Manager
Patty Davis David D. Rowlands, Jr.
John McCann City Attorney
Jerry R. Rindone Ann Moore
Mary Salas City Clerk
Stephen C. Padilla, Mayor Susan Bigelow
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The City Council meets regularly on the first calendar Tuesday at 4:00 p.m.
and on the second, third and fourth calendar Tuesdays at 6:00 p.m.
Regular meetings may be viewed at 7:00 p.m. on Wednesdays on
Cox Cable Channel 24 or Chula Vista Cable Channel 68.
Agendas are available on the City's website at:
www.chulavistaca.gov
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AGENDA
I declare under penalty of perjury that I am
employed by the City of Chula Vista in the
Office of the City Clerk and that I posted this
document on the bulletin board according to
Brown Act requirements.
Dated 6- / L{ -{)I.{ Signed c::¡:¡~~
6:00 P.M.
May 19, 2004
CALL TO ORDER
ROLL CALL: Councilmembers Davis, McCann, Rindone, Salas, and Mayor Padilla
ORAL COMMUNICATIONS
Persons speaking during Oral Communications may address the Council on any
subject matter within the Council's jurisdiction that is not listed as an item on the
agenda. State law generally prohibits the Council from taking action on any issue
not included on the agenda, but, if appropriate, the Council may schedule the
topic for future discussion or refer the matter to staff. Comments are limited to
three minutes.
ACTION ITEM
1. RESOLUTION OF THE CITY COUNCIL OF THE CITY OF CHULA VISTA
ACCEPTING THE MUNICIPAL ENERGY UTILITY FEASffiILITY REPORT AND
PEER REVIEW ANALYSIS REPORTS; AND DIRECTING STAFF TO (1) RETURN
TO COUNCIL BY JUNE 8, 2004 FOR FURTHER CONSIDERATION OF THE
CONSULTANT'S RECOMMENDATION TO IMPLEMENT CITY MUNICIPAL
ENERGY UTILITY BUSINESS MODELS; (2) PREPARE AND DISTRffiUTE A
REQUEST FOR PROPOSAL FOR A FULL-REQUIREMENT GREENFIELD
DEVELOPMENT AND COMMUNITY CHOICE AGGREGATION SERVICE
PROVIDER AND RETURN TO COUNCIL FOR FURTHER ACTION; (3)
CONTINUE TO WORK WITH THE CALIFORNIA PUBLIC UTILITIES
COMMISSION TO ASSERT THE CITY'S POSITION REGARDING THE
DEVELOPMENT OF COMMUNITY CHOICE AGGREGATION RULES, EXIT FEES
AND MUNICIPAL DEPARTMENT LOAD FEES; (4) CONTINUE TO WORK WITH
SANDAG TO IMPLEMENT REGIONAL ENERGY OPTIONS; AND (5) CONTINUE
TO ACTNEL Y MONITOR AND INFLUENCE PENDING AND NEW CALIFORNIA
PUBLIC UTILITIES COMMISSION, CALIFORNIA ENERGY COMMISSION,
STATE AND FEDERAL ENERGY RULES AND LEGISLATION
In August 2000, the Council directed staff to investigate any and all energy options that
the City could pursue to potentially protect Chula Vista residential and commercial
ratepayers from exponential rate increases and better position the City to deal with the
volatility and uncertainty of the energy market. The proposed resolution accepts the
Municipal Energy Utility Feasibility Report and Peer Review Analysis Reports and
directs staffto take further actions.
Staffrecommendation: Council adopt the resolution.
OTHER BUSINESS
2. CITY MANAGER'S REPORTS
3. MAYOR'S REPORTS
4. COUNCIL COMMENTS
ADJOURNMENT to the Regular Meeting of May 25, 2004, at 6:00 p.m. in the Council
Chambers, and thence to an Adjourned Regular Meeting on May 27, 2004
at 6:00 p.m. in the Council Chambers.
Page 2 - Council Agenda May 19, 2004
CITY COUNCIL MEETING AND WORKSHOP
AGENDA STATEMENT
ITEM:
MEETING DATE: 5/19/04
ITEM TITLE: Resolution Of The City Council Of The City Of Chula
Vista To:
A) Accept The Municipal Energy Utility Feasibility Report And Peer Review Analysis
Reports.
B) Direct Staff To Return To Council By June 8, 2004 For Further Consideration Of
The Consultant's Recommendation To Implement City Municipal Energy Utility
Business Models.
C) Direct Staff To Prepare and distribute A "Request For Proposal" For A Full-
Requirement Greenfield Development And Community Choice Aggregation
Service Provider And Return To Council For Further Action.
D) Direct Staff To Continue To Work With The California Public Utilities Commission
To Assert The City's Position Regarding The Development Of Community Choice
Aggregation Rules, Exit Fees And Municipal Departing Load Fees.
E) Direct Staff To Continue To Work With SANDAG To Implement Regional Energy
Options.
F) Direct Staff To Continue To Actively Monitor And Influence Pending and New
California Public Utilities Commission, California Energy Commission, State and
Federal Energy Rules And Legislation.
SUBMITTED BY: A,,;,taot C;ty M,"ag~
REVIEWED BY: City Manage;. æ ~ \ (4/5ths Vote: Yes...x... No}
INTRODUCTION:
At Council's direction, Staff began implementing the City's Energy Strategy and Action
Plan, adopted in May of 2001. To date, on-going energy conservation programs are
being implemented, City facilities are renovated and built to exceed state energy
efficiency requirements and renewable power is being installed on some City facilities.
A significant aspect of the Strategy requires an analysis of the costs, benefits and risks
associated with forming and operating a municipal energy utility (MEU). The purpose of
the City of Chula Vista Municipal Energy Utility Analysis is to identify and evaluate the
potential for a municipal energy utility to 1) better control the City's energy future, 2)
provide stable rates for customers, 3) enhance local control of conservation funds, 4)
generate new city revenues, 5) enhance city services, 6) catalyze economic development
opportunities, 7) mitigate the local environmental impacts of energy generation and
distribution, 8) fund renewable energy projects and 9) generate quality local jobs.
Council Workshop Date: 5/19/04
Page: 2 of 29
The results of the analysis by Duncan/Navigant indicate that there are legally, financially
and technically feasible MEU models that the City should pursue. These MEU models,
which are defined in detail below, include Community Choice Aggregation (CCA),
Greenfield Development (GD) and Municipal Distribution Utility (MDU).
The MEU models are viable as independent business models and can provide maximum
benefits to the City when a phased implementation approach is carried out. The MEU
business models are viable using a "contract" supply strategy for electricity procurement
and become even more financially feasible using "locally owned generation" as an
electricity supply strategy.
There are significant start-up, and on-going, costs as well as risks associated with
implementing each City MEU business model. However, the cosUbenefit analysis
conducted by the consultants takes these costs into account when determining financial
viability, and these risks can be mitigated by implementing the most successful business
practices already used by the approximately 38 existing California and almost 2000 U.S.
public utilities.
To test and validate the consultant team's findings, conclusions and recommendations,
Staff retained the peer review services of three independent energy consultants. This
report provides a summary of the review findings from R.W. Beck (Attachment 1).
Crossborder Energy (Attachment 2) and Tabors, Caramanis and Associates (Attachment
3). Also attached to this Staff report are the MEU Report Executive Summary
(Attachment 4), Report (Attachment 5), the Appendices (Attachment 6), and the March
25, 2003 Council Agenda Statement selecting Duncan/Navigant (Attachment 7).
RECOMMENDATION: That Council:
1. Accept The Municipal Energy Utility Feasibility Report And Peer Review Analysis
Reports.
2. Direct Staff To Return To Council By June 8, 2004 For Further Consideration Of
The Consultant's Recommendation To Implement City Municipal Energy Utility
Business Models.
3. Direct Staff To Prepare and distribute A "Request For Proposal" For A Full-
Requirement Greenfield Development And Community Choice Aggregation
Service Provider And Return To Council For Further Action.
4. Direct Staff To Continue To Work With The California Public Utilities Commission
And Other State Agencies To Assert The City's Position Regarding The
Development Of Community Choice Aggregation Rules, Exit Fees And Municipal
Departing Load Fees.
5. Direct Staff To Continue To Work With SANDAG To Implement Regional Energy
Options.
6. Direct Staff To Continue To Actively Monitor And Influence Pending and New
California Public Utilities Commission, California Energy Commission And State
Energy Rules And Legislation.
Council Workshop Date: 5/19/04
Page: 3 of 29
BOARDS/COMMISSIONS RECOMMENDATION:
Not applicable.
BACKGROUND:
In 1996 Governor Wilson signed AB 1890, putting California on course for energy
deregulation. The projected benefits of deregulation were never realized, instead San
Diego Gas and Electric (SDG&E) customers' bills dramatically increased, beginning in
May 1999. Soon after, Pacific Gas and Electric and Southern California Edison warned
the state of their impending bankruptcies and their lack of financial worthiness to
continue buying power for customers. In 2000 and 2001, SDG&E customers
experienced brownout alerts and blackouts due to lack of power supply and market
manipulation by the energy Industry. In early 2000, Governor Davis signed AB 1X into
law authorizing the Department of Water Resources to begin buying power to serve
California's energy needs. In January 2003, the regulated, Investor Owned Utilities
(IOU) were directed to resume purchasing power for customers.
In August 2000 Council directed Staff to investigate any and all energy options that the
City could pursue to potentially protect Chula Vista residential and commercial
ratepayers from exponential rate increases, and better position the City, to deal with the
volatility and uncertainty of the energy market. In April 2001, following a Council
workshop outlining the City's options, Council directed Staff to return with the
implementing resolution adopting a City Energy Strategy and Action Plan. In May 2001
Council passed Resolution No. 2001-162 adopting the City's Energy Strategy and
Action Plan (please see Attachment 7). Included was a recommendation that the City
take the initial steps to assess the costs and benefits of forming and operating a
municipal utility. On June 5 Council passed Ordinance No. 2835 establishing the City's
status as a Municipal Utility, and directing Staff to conduct a cost-benefit analysis of the
various energy business models that could be used to operate a municipal utility. In
addition, to assessing the cost/benefit, Staff was tasked with identifying the risks
involved with establishing an MEU to provide a strong "go or no go" recommendation to
Council. The City of Chula Vista Municipal Energy Utility Feasibility Analysis (MEU
Report) is the result of this effort. The MEU Report evaluates initial facility acquisition
costs and provides various business models to rigorously test the economics of City
ownership and operation of an energy utility. This agenda statement is a summary of
the process used to implement the Council's direction. It also summarizes the
recommendations of the City's consultant team and identifies differences in their report
from the peer review comments.
When Staff negotiated its most recent SDG&E franchise agreement, the term was
limited to 5 years because of the uncertainty of deregulation and the volatility of the
energy market. That volatility still exists and as a result, some issues identified by the
consultants have been overtaken by events, and others are still awaiting the adoption of
implementing rules and regulations by the California Public Utilities Commission
(CPUC).
Finally, this report provides Council with a comparative analysis of the recommended
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Page: 4 of 29
MEU business models and the proposed franchise agreement with SDG&E. The intent
of this analysis is to outline for Council the cost benefit of the proposed franchise with
SDG&E to the implementation of an MEU business model. It is important to note that
these options are not necessarily mutually exclusive. In fact, if Council implements one
or more of the report recommendations, it is likely that the City will continue to have a
long term energy relationship with SDG&E in some form.
DISCUSSION:
SDG&E is the San Diego region's energy service provider. SDG&E is a business unit of
SEMPRA Energy (SEMPRA) a national Fortune 500 energy services holding company
headquartered in downtown San Diego. SEMPRA (SRE) is a publicly traded company
with a market capitalization of approximately $7.3 billion dollars. SEMPRA's annual
revenue from SDG&E is approximately $1 billion dollars. SDG&E services San Diego
and southern Orange counties and 25 cities. SDG&E is the investor owned utility that
provides energy services to the City of Chula Vista. Chula Vista is approximately 9% of
SDG&E's total natural gas and electricity market and makes up approximately 7% of all
energy meters. SDG&E's five-year average - 1999 to 2003 - annual gross receipts from
Chula Vista is approximately $100 million dollars.
In December 2002, SDG&E submitted a request to the CPUC to increase annual
natural gas and electricity service wide rates by at least $100 million. This matter is
currently under a settlement proposal before the Commission to limit the rate increase.
The City Council directed Staff to intervene in the proceedings and contest the
settlement agreement. The City's points against the proposed settlement are:
1. The proposed settlement would implicitly accept the form and detail of the
initial "cost of service" filing in lieu of a general rate case. A general rate
case establishes what the California Public Utilities Commission refers to
as "revenue requirements," and has the effect of setting the basis for rates
for up to five years. General rate cases have historically provided greater
detail and opportunity for ratepayers and their advocates to review the
facts behind revenue requests than the current "cost of service," filing
provides. The SDG&E cost of service filing and the record developed in
hearing does not support a settlement that could establish rates for five
years;
2. The opponents to the proposed settlement are making the case that
Sempra and its affiliates (SDG&E, Southern California Gas Company),
has not passed on the savings that were projected and required to be
passed. The opponents are also making the case that this settlement
blends the costs between Sempra's affiliates in a manner that will make it
unlikely, if not impossible to identify and pass those required savings on to
rate payers in the future, and that without these savings the settlement
establishes a higher base line for future cost of service or general rate
case filings.
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3. The Settlement continues a long history of very high utility earnings for
SDG&E while providing no rate relief for SDG&E customers;
4. The Settlement tacitly assumes continuation of questionable capital
investments and utility programs such as the design, location and timing of
transmission projects, the management of energy conservation funds and
other projects strongly opposed by local interests;
5. The Settlement rejects the majority of revenue requirement adjustments
raised by local interests such as the City of Chula Vista, the Utility
Consumer's Action Network (UCAN), and Federal Energy Administration
(FEA) which represents the Military and other federal agencies); and
6. The Settlement ignores the negative impacts of SDG&E's rates on San
Diego County.
In comparison, the CPUC approved reduced rates for ratepayers submitted by the other
two major Utility service areas in California. Southern California Edison (SCE) rates were
reduced by $1.2 Billion in July 2003 effective August 2003 and Pacific Gas and Electric
(PG&E) rates were reduced by $783 million in February 2004 effective March 2004.
The high and ever increasing cost of energy in the SDG&E service area places the region
and the City at a commercial disadvantage as compared to the rest of the state and most
of the United States. The California Energy Commission is projecting that SDG&E's
average electricity rates will be the highest in California for the next decade. Department
of Energy data for 2002 indicate that California has the third highest rates in the nation
only behind the cost of energy in New York and Hawaii. A lack of adequate energy
generation and transmission infrastructure in its service territory also contributes to
SDG&E's high cost of service.
The San Diego Regional Energy Office (SDREO) conducted the 'Regional Energy
Infrastructure Study' (REIS) in 2001/2002 and concluded that the current state of
SDG&E's energy infrastructure is in dire need of enhancement. The REIS recommends
adding more native generation, repowering the plants at South Bay and Encina, and
installation of additional "local" transmission by 2005/2006 to prevent a recurrence of the
energy crisis that occurred in 2000/2001.
Consultant Selection Process
Notwithstanding its efforts in statewide and regional energy issues, and having
accomplished many of the recommendations of the City's Energy Strategy, the City
Council directed Staff to pursue the feasibility of a City MEU. Staff immediately began
to develop a Request for Proposal (RFP) to conduct the feasibility study.
Soon after these efforts began, an unsolicited proposal from Edison Utility Services
representatives (now ENCO) - an MEU design/build operator - presented a revenue
sharing proposal for an "electricity only" Greenfield Development project in undeveloped
areas of the City. In a Greenfield Development MEU, the City would own and operate
Council Workshop Date: 5/19/04
Page: 6 of 29
electric distribution systems, set rates and supply energy to customers. Under the
proposal, ENCO would finance, construct and operate the Greenfield Development
MEU as a Third-Party service provider for the City. The revenue sharing mechanism of
the proposal between ENCO and the City would be modeled on a sliding scale. The
distribution of the benefits and risks are dependent on the level of investment and risk
accepted respectively by ENCO and the City for infrastructure use not already funded
by developers. Energy supply, operation and maintenance costs would be recovered
through rates.
At the same time, ChevronTexaco (Chevron), a company similar to ENCO, also
approached City Staff and presented their "electricity only" Greenfield Development
MEU program. Chevron reviewed and commented on the City's scope of work for the
feasibility study. Chevron then proposed to conduct the feasibility study "at no cost" for
the City.
Based on a series of meetings with ENCO & Chevron, Staff was convinced that the
"greenfield" proposal represented a sound business opportunity worthy of serious
consideration. City Staff sought SDG&E's input about the proposed MEU feasibility
study. Staff also solicited SDG&E's input regarding the draft scope of work for the RFP.
Based on SDG&E's input, Staff agreed that the better approach for the City would be to
select the feasibility consultant through an open and competitive process that would
consider multiple options, not just the one being proposed. Staff also incorporated
SDG&E recommendations in the scope of work. Based on SDG&E's input and the
City's shared concerns about objectivity, Staff declined the EN CO and Chevron
proposals and Chevron's offer to conduct the feasibility study at no charge. Shortly
thereafter SDG&E unilaterally chose to withdraw from participation with City Staff
in the development and implementation of the RFP process.
On December 20, 2002 Staff released an RFP to study the costs and benefits of
implementing various possible MEU businesses, including owning and operating all or
portions of the local distribution system. The RFP was released to over 60 national
legal, energy and engineering firms. SEMPRA (SDG&E's parent company) and three
firms recommended by SDG&E (EES Consulting, Black and Veatch, and RW. Beck,
which ultimately was used as one of the peer review consultants) were among the
companies provided with the RFP.
On January 9, 2003 Staff conducted a pre-bid conference attended by about 20
representatives from 15 firms. Because SEMPRA, not SDG&E, was on the mailing list,
Staff delivered an RFP package to SDG&E one day prior to the meeting. SDG&E had
participated in the development of the RFP scope of work well in advance of the
meeting and an SDG&E representative was able to attend the meeting. Responses to
questions received at the pre-bid conference and prior to January 17 were distributed to
potential bidders on January 24. On February 7, Staff received proposals from the
following nine firms: (no proposal was received from SDG&E)
. Alliant . GDS Associates
. Astrum Utility . McDonald Partners
. Black and Veatch . Milbank Tweed
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. Duncan/Navigant . RW Beck
. EES Consulting
On February 21,2003, after a thorough review of the proposals from the nine firms, an
internal selection committee composed of City Staff: Sid Morris, Glen Googins, Michael
Meacham, Willie Gaters, Maria Kachadoorian, and Dave Byers unanimously selected
the following top five firms for initial interviews in March 2003:
. Alliant . GDS Associates
. Black and Veatch . RW Beck
. Duncan/Navigant
On March 5 and 6, 2003 an interview panel composed of the internal section committee,
Bill Carnahan, Executive Director of Southern California Public Power Authority and
Dave Wright, City of Riverside Municipal Utility Assistant Director interviewed the top
five firms and selected the following top two firms for final interviews, follow-up
questions and referral background checks:
. Duncan/Navigant
. RW Beck
On March 14, 2003 the internal section committee (again with assistance from Mr.
Carnahan and Mr. Wright) unanimously agreed to recommend Navigant Consulting,
Inc., Duncan, Weinberg, Genzer & Pembroke and McCarthy & Berlin (collectively
referred to as "Duncan/Navigant") for Council consideration. On March 25, 2003 Staff
presented a report on the RFP process and Staff's recommended firm to Council (see
Attachment 8). Duncan/Navigant was selected based upon the following criteria:
. The proposal as originally submitted was complete in its approach,
addressing all of the major scope of work components;
. The consultant team Duncan/Navigant has a longstanding working
relationship with one another, and past efforts by this group reflected
extensive, detailed research in addressing clients' concerns;
. Duncan/Navigant was most knowledgeable in identifying the South Bay
Power Plant and other possible local generation options as a potential key
opportunity for a Chula Vista MEU;
. Duncan/Navigant was most clear in its intent and ability to provide the City
with an "actionable intelligence";
. The consultant had relevant California experience including extensive work
with California regulatory agencies;
. The consultant has demonstrated the experience and ability to deliver a
report on time, within budget and according to established criteria;
. The consultant team exhibited the best overall breadth and depth of
energy industry sophistication; and
. Duncan/Navigant offered the greatest number of hours applied to the task,
approaching, in many respects, a phase II level of analysis.
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In April 2003, the City contracted with Duncan/Navigant.
MEU Models Study Process
Objective of the MEU Feasibility Study
Navigant/Duncan was tasked to answer the question: Is it viable for the City of Chula
Vista to pursue the implementation of MEU business? If so, what form of MEU
business?
Duncan/Navigant identified and evaluated the financial, legal and technical feasibility of
various MEU business models and analyzed each MEU business model's merits
relative to the objectives listed below:
. Establishes reliable and stable electricity and natural gas supply and maintains
the highest level of customer service.
. Identifies a viable business model that benefits the City's time and investment.
. Ensures an environmental advantage for City residents, businesses and the
region.
. Results in a citywide distribution of MEU benefits.
. Enables the utilization of the MEU as an economic development tool to retain
and attract businesses.
. Enhances Chula Vista's vision to continue as a vibrant community in the region.
Report Financial. Leaal. and Technical Feasibilitv Analvsis Methodoloav
A general description of Duncan/Navigant's methodology to analyze the financial, legal
and technical feasibility of an MEU business models is described below:
Leaal Feasibilitv Analvsis
Duncan/Navigant identified and analyzed the alternatives available to the City
under applicable federal laws, state and local regulations applicable to municipal
energy utility formation and operation. Duncan/Navigant analyzed the potential
costs of acquiring SDG&E's distribution and other facilities, by voluntary sale or
condemnation, and the City's potential obligation to pay SDG&E's "stranded
costs" (reimbursable capital investments). Duncan/Navigant also analyzed and
addressed applicable legal requirements, regulatory approvals, and applicable
laws and regulations governing the acquisition and delivery of electric and gas
supplies to a City MEU.
Financial Feasibility Analvsis
Duncan/Navigant determined the costs, benefits and feasibility of implementing
selected utility structure business models by incorporating prospective loads, load
shapes, existing (SDG&E) rates, energy resource supply portfolios, capital costs,
debt service, operation and maintenance cost projections, exit fees, in-lieu tax
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payments and other inputs in Duncan/Navigant's proprietary "Utility Feasibility and
Cost of Service" model (UFCOS). The UFCOS Model then generates detailed
reports that demonstrate the revenues that can be generated by each integrated
business model over time. The benchmark for financial composition is the same
service provided by SDG&E using existing and projected SDG&E rates. The
UFCOS Model output reports include cost-of-service requirements, revenue
projections and forms the bases for preliminary rate design. The UFCOS platform
allowed for iterative sensitivity analyses, with variable inputs regarding forward
energy prices, fuel costs and asset valuation alternatives.
Technical Feasibilitv Analysis
For the Greenfield and MDU alternative, Duncan/Navigant conducted a
preliminary appraisal of the electric and gas utility facilities now owned and
operated by SDG&E in the City, and identified facilities necessary for the City to
operate each feasible MEU business model. Duncan/Navigant analyzed the
system modifications necessary to separate the MEU gas and electric distribution
systems from SDG&E and the contractual arrangements (including borderline
agreements, interconnection agreements, and power and gas supply
agreements) necessary for the operation of a distribution system. For all
business models including CCA, Duncan/Navigant also developed and provides
an analysis of all available and economically feasible power and gas supply
alternatives open to the MEU, including purchased power, the availability of
Federal preference power, MEU-owned generation, and available gas and
pipeline resources, together with an estimate of the cost of power and gas supply
and a comparison of such costs with the current cost of power, energy, and gas
presently provided by SDG&E.
Utility Business Models and Alternatives
Identification of Utilitv Options
Duncan/Navigant analyzed five municipal energy utility business models and
alternatives authorized under federal and State law. Duncan/Navigant identified the
following business models that could legally facilitate Chula Vista's entry into the
MEU business:
. Community Choice Aggregation (CCA): electricity;
. "Greenfield municipalization" development (Greenfield): electricity immediately
with the potential for gas
. Municipalization under a city electric utility department format, eventually leading
to a Municipal Distribution Utility (MDU) system;
. Participation in a joint powers agency (JPA); and
. Municipalization under a Municipal Utility District format (MUD).
As an MEU, the City could develop or acquire generation resources, and/or purchase
power to meet the City's load requirements. A MEU would position the City to provide
energy to the community by replacing SDG&E services in whole or in part. A MEU
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would ultimately provide the City with a public utility structure to protect the Chula Vista
community from unreasonably high-energy costs, and unreliable energy supply, while
allowing the community to locally control its energy future.
Duncan/Navigant's legal review of the business models identified three basic models
and one derivative that merited further financial and technical review:
. Community Choice Aggregation (CCA) (Target Implementation Jan. 2006)
. Greenfield Development - Immediate Implementation
. A combination of CCA and Greenfield Development (Target Implementation Jan.
2008)
. Municipal Distribution Utility (reconsideration in 2010)
Duncan/Navigant has recommended that the complexities of organizing an MUD and
coordinating efforts with other local governments or entities would add unnecessary
complications and delay an immediate implementation. However, Duncan/Navigant did
recommend that these models should be revisited at a later date.
Financial and Technical Feasibilitv of MEU Business Models and Alternatives
Financial analysis of the selected MEU business models were "run" for a study period of
18 years (2006 to 2023). A summary of the MEU business models evaluated by
Duncan/Navigant includes key elements critical for a viable MEU business. These
elements are:
. Key Assumptions . Pro-Forma Results
. Supply Strategy . Recommendations
. Start-Up Costs and Operational Issues . Financing Options
. Risks . Next Steps/Implementation
. Benefits
MEU Business Model Discussion
Communitv Choice Aqqreqation
The City has an option to serve as a community load aggregator for electric
power pursuant to Assembly Bill 117 - this is subject to the CPUC review of the
City's Implementation Plan, the adoption and application of exit fees (a per
kilovolt charge applied by the CPUC to recover the cost of the Department of
Water Resources energy contracts, currently under discussion at the CPUC),
and the implementation of final rules by the CPUC. The City is engaged in the
CPUC proceeding to determine exit fees and final rules. A load aggregator is an
entity that procures electric energy and/or natural gas for residents and
businesses within a community. Under this business model, the City would not
own the electric or gas distribution system within the City. Rather, it would
procure electric power and/or natural gas, either through owning a generation
facility, market purchases, or through a partner on behalf of the customers that
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choose to aggregate their load. As a CCA, the City would use SDG&E's
distribution and transmission facilities to deliver electricity and/or natural gas to
its customers. Notwithstanding the application of exit fees, Duncan/Navigant has
identified CCA as a viable alternative for the delivery of energy.
Greenfield Development
Another viable option is a the implementation of a Greenfield project under the
City's Municipal Utility status adopted by Council on June 5, 2001. Typically, this
structure would include undeveloped acreage of land designated for an industrial
park or new residential subdivisions. Duncan/Navigant has not identified any
legal impediments to pursuing this MEU business model. Duncan/Navigant
identified the Otay Ranch Area, Mid-Bayfront, and Sunbow planning areas as the
sites primarily adaptable to a Greenfield project.
A Greenfield Development requires investment in distribution facilities to supply
energy to previously undeveloped areas within the City of Chula Vista. The
distribution system is typically planned and built in collaboration with the
developers of the projects and much of the cost is borne by the developers. The
consultant's feasibility analysis assumes a worst case, with these costs borne by
the City. Even under this model, Duncan/Navigant has identified greenfields as
warranting serious consideration. However, it is likely the City would use a
model similar to the utility and require that the developer dedicate these facilities.
The MEU may need to fund and construct a substation, and if so, would have to
interconnect to SDG&E's system in order to supply energy. The MEU would also
need to develop the distribution system configuration (underground) lines,
appurtenances, and service extensions, as well as make arrangements for
appropriate meters and related customer service functions. Notwithstanding
these planning and phasing requirements, these costs are included in the
Greenfield business model.
Communitv Choice Aaareaation/Greenfield Development Combined
This business model represents the derivative of the main options. The City
would implement both the CCA and Greenfield models simultaneously and
administer and operate the two programs using City Staff and/or an outside
Third-Party service provider to oversee operations. The Duncan/Navigant report
indicates that the City enhances the near term economic benefits by forming a
CCA program and simultaneously pursuing and implementing Greenfield
Development programs.
Municipal Distribution Utilitv
As defined by Duncan/Navigant, an MDU is a public agency that acquires some
or all of the existing utility infrastructure within its jurisdiction and uses it to
provide energy services previously provided by the incumbent utility. The
Duncan/Navigant Report states that there are approximately 38 public agencies
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that currently provide electric utility services to communities in California,
servicing approximately 25% of the state's total electric load. With this utility
structure, the City could acquire some or all of SDG&E's electric and/or gas
distribution system by a negotiated sale or condemnation. Under this option,
MDU services could be provided by a City utility department, or contracted out.
The City Council, or a separate board appointed by the Council, would oversee
the MDU operations. Duncan/Navigant recommends that the MDU model be
pursued only after at least 2 years of successful CCA and/or CCA/Greenfield
operation.
Summary of Fiscal Implications
The Duncan/Naviaant Feasibilitv Studv Recommends Three Viable Citv MEU Business
Models
The findings of the feasibility study indicate that, pending the outcome of CCA rulemaking
by the PUC, it would be legally, financially and technically feasible for the City to
implement "electricity only" CCA & CCA/Greenfield operation MEU business models
beginning in 2006. Although the viability of each MEU business model works with
contracted/purchased electricity, each MEU business model is enhanced with City
ownership of generation capacity located within the City. Locally owned generation will
reduce supply cost and transmission congestion charges borne by the community.
Duncan/Navigant is only recommending an MDU for further consideration after 2-4 years
of successful operation of a CCA or CCA/Greenfield MEU. The Report does not
recommend a natural gas MEU at this time, but suggests that it may become viable
depending on price fluctuations and the development of lower cost LNG opportunities
south of the U .S.lMexican border.
Duncan/Navigant projects that, over an 18-year period, an electric CCA supplied with
contract power would generate revenues of $4.78 million annually ($86 M) whereas an
electric CCA supplied with local generation would generate annual revenues of $13.56
million ($224 M).
In a combined electric CCA/G reenfield , a community aggregates energy for the
community over the Utility's infrastructure and develops City owned energy infrastructure
in undeveloped parts of the City. An electric CCA/Greenfield supplied with contract power
would generate annual revenues of $9.45 million ($170 M) whereas an electric
CCA/Greenfield supplied with local generation would generate annual revenues of $19.5
million ($351 M).
In an electric only MDU, the City would negotiate for the purchase of the Utility owned
electric distribution infrastructure. A MDU supplied with local generation would generate
annual revenues of $18.3 million ($329 M). The table below provides a side-by-side
overview of the viable MEU business models.
. --.-.-. ----------------~--
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Summarv of MEU Business models, StartuD Cost and Projected Revenues
Business model Supply Strategy Pre-implementation Revenues $
Startup Cost
CCA Contract 225 thousand 86 million
CCA Generation 225 thousand 244 million
CCAlGreenfield Contract 13.8 million 170 million
CCAlGreenfield Generation 13.8 million 351 million
MDU Generation 185 million 329 million
Generation 78 million
Potential MEU Benefits
The MEU business models identified above would fulfill most of the City's community-
wide energy objectives and would provide the following benefits over time:
Local Control of City's Energy Future
. Establish a local Municipal Utility structure that's only focus is on service and
delivering value to the community, not profit to shareholders.
. Establish a local Municipal Utility that is accountable to local ratepayers, not
shareholders, state and federal regulators.
. Establish reliable electricity and natural gas supply that reduces or eliminates
scheduled brown outs and maintains the highest level of customer service.
. Stabilize consumer rates.
. Establish land use guidelines for power lines and utility boxes that put local quality
of life issues first.
. Enhanced Control of Local Conservation Funds to:
0 Ensure an environmental advantage for City residents and businesses,
0 Invest the $3,000,000 already collected from Chula Vista ratepayers each
year to produce real savings for current rate payers,
0 Establish better incentives for existing residents and businesses to invest in
conservation and clean generation options,
0 Invest in a more environmentally sustainable energy future based on
renewable sources that do not use fossil fuels,
. Invest in medium and long-term energy procurement and power generation
strategies that reflect the City's commitment to a sustainable environment and
cleaner air including;
0 CO2 reduction, the prevention of global warming, and particulate reduction.
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. Investment in energy procurement and generation, infrastructure and operational
services that maintain existing jobs and create new quality jobs for local residents.
. Enable the utilization of the MEU as an economic development tool to retain and
attract businesses
0 Establish better incentives that encourage developers to reduce costs
through increased invest in conservation and clean generation for residential
and commercial building using rate structures, infrastructure taxes and other
means available.
. New city revenues at no increased cost to ratepayers
0 Equitably invest new revenues generated from an MEU business throughout
the City in the form of enhanced existing services and/or new services.
. Enhance Chula Vista's vision to continue as a vibrant community in the region
and a leader in environmental stewardship.
MEU Development Risks And Risk Management
If the City elects to proceed with an MEU business, it will face significant political, financial
and legal risks. Most efforts to develop a locally controlled MEU have been met with
aggressive public relations campaigns and legal challenges from the local Investor
Owned Utility and utility trade associations. However, the Duncan/Navigant report
suggests these risks can be managed and mitigated to the point where they are
outweighed by the potential financial and environmental benefits to the community. The
risks and costs involved in developing an MEU business model are summarized below.
Political Risk
SDG&E will likely wage a public relations campaign to stop the City's efforts. SDG&E
attempted to stop the City of San Marcos from forming a Greenfield Utility by
sponsoring a "citizens initiative opposing a Greenfield development. The San Diego
Union Tribune reported that this matter was recently settled between SDG&E & San
Marcos.
Financial Risks
As identified by Duncan/Navigant
MEU Business Start-up Costs are Substantial
. CCA: $225,000
. CCNGreenfield: $13.8 million
. MDU: $185 million
If the MEU business fails, some or all of these costs might not be recovered.
Notwithstanding the risks, the Duncan/Navigant report points out the potential
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Page: 150129
upside is equally significant:
. Reliable and consistent supply
. The reinvestment of saving into City services as opposed to going to
shareholder profits
. Local planning and control compared with decision making by a state
agency in San Francisco and a for profit private corporation
. Economic development and business development opportunities
Also, as Duncan/Navigant points out further mitigation is achieved through:
. The phasing of facilities commensurate with need.
. The concurrent implementation of CCA/Greenfield, enabling the City to
secure power at more competitive rates due to cost effective load factors.
. Outsourcing operations and maintenance.
. The installation of the electric distribution infrastructure by local developers.
(Even if this cost is absorbed by the developers, there are still potential
savings opportunities for them over the costs and charges they currently pay
to SDG&E.)
. The inherent price advantage Municipal utilities have over IOUs because
they are not motivated by profits for shareholders.
Volatile Procurement Costs
The cost to acquire or generate electricity may fluctuate dramatically. Some of
these costs might not be recoverable in rates (and thus may become City costs), or
if passed on to the ratepayer, may result in volatile energy prices in Chula Vista.
Mitiqatinq Factors
Possibly the most notable factor is that during the energy crisis, Municipal
Utilities did not suffer the price fluctuations encountered, and in some cases,
created by the utility industry. However, because Chula Vista is not an
established public utility, it will be critical to insure that the City's energy"
portfolio is balanced and minimizes market fluctuations and manipulation.
Leqal Risks
Significant legal costs may be incurred defending the MEU against legal
challenges to its validity, or claims for damages caused by MEU business
operations.
Mitiqatinq Factors
The Duncan/Navigant reports that there are inherent benefits and
advantages to public ownership of the utility system, as noted previously;
the State's publicly owned utilities were protected from dramatic increases in
rates. Although some increases occurred, they were not on the same
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Page: 160129
magnitude as those experienced by investor-owned utility customers. In
fact, many public utilities made significant profits on the sale of energy, to
those outside their service area, during the energy crisis and a few have
been investigated based on those profits.
Leaal/Reaulatorv Risks
. SDG&E's sponsored lawsuits may defeat, or make more costly, any
attempted MEU business.
. Legislative changes and CPUC proceedings may routinely "change the
rules" for MEU business operations in ways that increase costs and/or
affect local service control or quality.
. CCA rules are not finalized and attempts by the IOUs to influence the
PUC rule making process have not been acceptable.
Mitiaatina Factors
The report recommendations proposed by Duncan/Navigant are very
conservative and even based on a worst-case scenario still has a positive
cost/benefit. The earlier a public agency establishes itself as an operating
public agency, the sooner the agency is "grand fathered" in under the then
current regulations. Additionally, the existing approximately 38 California
public utilities, representing approximately 25% of the state's energy load,
are collectively a formidable group that are likely to prevent any further
erosion of public utility rights.
Independent Peer Reviews
Because the magnitude of this project and the potential risk/reward issues, Staff engaged
independent third-party consultants to assess the conclusions and recommendations,
findings and key assumptions in the feasibility study conducted by Duncan/Navigant.
Peer reviewers assessed the projections for SDG&E's rates, power purchase costs and
generation development costs used by Duncan/Navigant in the modeling Proformas to
test the practical application of the feasibility study's assumptions, findings and
recommendations. The independent consulting firms include RW. Beck, Tabors,
Caramanis & Associates and Crossborder Energy.
In general, the peer reviewers independently concluded that the feasibility study used
very conservative assumptions and that Duncan/Navigant's analysis and
recommendations were reasonable (please see Attachments 3, 4 and 5). Specifically:
RW. Beck
R.W. Beck was retained to review and comment on the practical aspects of
Duncan/Navigant's key assumptions, findings, conclusions and recommendations.
RW. Beck also evaluated critical components of the proformas prepared by
Duncan/Navigant. These components included verifying the preciseness of the
forecasts for power purchase costs (PPC), generation development costs and projected
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SDG&E rates.
General Findinqs
. Using a discount rate of 10% for Net Present Value ("NPV") calculations is high
for a public entity. A discount rate of 6% to 7% would be more reasonable for the
City. As the discount rate is decreased, savings to the City would increase.
. Exit fees seem high at the end of the study period. It is highly likely that exit fees
within the SDG&E service area in particular will be lower relative to SCE and
PG&E.
. The schedules for implementation are very optimistic. In each case, the schedule
for implementation is more rapid than what is likely to occur, particularly if
SDG&E decides to oppose the initiative. The long end of the range provided for
implementation is what could reasonably be expected.
. Power plant costs for Chula Vista appear to be optimistic given R W. Beck's
experience (Capital cost Duncan/Navigant estimates $600/kW vs. $850/kW).
Costs can vary, depending on various conditions, including location, existing
infrastructure, access to fuel, electrical transmission facilities, water supply, and
emission restrictions. (Applies to CCA, CCNGreenfield and MDU generation
business models.)
. RW. Beck also notes that its cost projection is based on an average and that
Chula Vista's unique features may save costs. Duncan/Navigant based its
development costs on recent projects implemented by Navigant and on a
California Energy Commission study titled Comparative Cost of California Central
Station Electricity Generation Technologies - June 5,2003.
. Based on this limited review, it appears that the methodology employed in the
models used for this analysis is consistent with industry practice.
Communitv Choice Aqqreqation (CCA) Conclusions and Recommendations
. Something less than 100% participation should be assumed in the CCA Base
Case analysis, since it is unlikely that no customers will opt out of the CCA
program.
. There should be more consistency in power supply costs between SDG&E and
Chula Vista (at a minimum in a sensitivity analysis).
Greenfield Development (GO) Conclusions
. There is a fairly long lead-time before GD becomes economic. Such a lengthy
gap between implementation and savings creates risk to the City, particularly if
the CCA or MDU options fail to be implemented.
"._---------,----,-
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. Developer funding of GD utility infrastructure should be equal to what would be
contributed to SDG&E.
. There should be discussion of adverse reliability issues in GD due to limited
ability or additional costs to loop feed to spot systems.
. The City should make certain that it will move forward and likely be successful
with the implementation of either CCA and/or MDU before committing to this
option.
. There should be discussion of adverse reliability issues in GD due to limited
ability or additional costs to loop feed to spot systems.
. There should be more consistency in power supply costs between SDG&E and
Chula Vista (at a minimum in a sensitivity analysis).
Municipal Distribution Utilitv (MDU)
. A cost of $15 million for acquisition fees, severance, and start-up is likely very
low.
. Human Resource cost calculations assume fringe benefits of 15% - public
agencies' fringe costs are generally closer to 40% or more.
. Human resource requirements appear to exclude purchasing, warehousing,
buildings & ground, security, mail, legal, human resource, secretaries, and
reception.
Crossborder Enerav Assessment
Cross border Energy was retained to provide a focused assessment of the
Duncan/Navigant forecasts of the SDG&E electric and natural gas rates. Crossborder
Energy was asked to validate the key assumptions in the forecast and to comment on
the reasonableness of the forecast results. SDG&E rate forecasts are an important
element of Duncan/Navigant's findings in the MEU report because they form the basis
for assessing the MEU business model rate performance, and thus the projected
savings relative to SDG&E.
. Electric Rate Projection Findings
0 Crossborder Energy's independent electric rate model produced results
that were within 1 % of Duncan/Navigant's electric rate projections; this
validated Duncan/Navigant's projections.
. Natural Gas Rate Projection Findings
0 Crossborder Energy's independent natural gas rate model indicated that
Duncan/Navigant's natural gas rate projections were conservative and
suggested that we should keep an option open for further consideration of
gas as an MEU business model.
.- ..-.... .--_. ----...--.._.._m._'__. -.--- .
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Tabors. Caramanis and Associates Assessment
Tabors, Caramanis and Associates were retained to provide a focused assessment of
the Duncan/Navigant forecasts for the Power Purchase Contracts and generation
development costs.
. General Findings
0 Community Choice Aggregation rules are still pending formal adoption by
the California Public Utilities Commission.
0 Other states have successfully implemented aggregation programs. Most
successful programs are not based on full community programs.
0 The City could become a Co-op Purchasing Aggregator. This allows the
City to purchase energy on behalf of customers but the City does not take
title to power.
0 Aggregation alternatives should be explored in sufficient detail.
0 Outsourcing can reduce the City's risk in CCA business options and in
Greenfield business options.
0 The City may want to obtain rights to low cost electricity through existing
generation or projects that are in advanced development. The City would
need to have the CCA or Greenfield in place before finalizing any deal, but
contingency agreements could be pursued now.
0 The report does not adequately stress the volatility of the energy market.
The City needs to be prepared to manage the risks associated with
volatility and be ready to directly or indirectly manage the risks.
0 The report appropriately proposes a phased approach.
Peer Review Conclusions
Although each of the peer review consultants identified certain items that they may have
done differently, used a different discount rate or a higher exit fee, they generally found
the findings, assumptions and analysis by Duncan/Navigant supportable. In many
cases the assumptions used by the peer review consultants were more aggressive and
only made the MEU feasibility more attractive/viable. In those cases where the factors
used by the peer review consultants had a significant impact on the numbers used by
Duncan/Navigant, the outcome was not so significant as to change the stated
recommendation.
Go/No-Go Recommendation
Duncan/Navigant evaluated a variety of MEU business models. Based on this analysis, it
recommends that the City initially develop an MEU business by forming a Community
Choice Aggregator (CCA). Thereafter, within two years, the City should combine CCA
with a Greenfield utility business. Duncan/Navigant believes that with the experience
gained from operating a CCA/Greenfield Development Utility the City could consider
transition into a Municipal Distribution Utility (MDU) in four to six years. An MDU entails
full ownership of all or part of the existing electric and gas delivery systems. The
Duncan/Navigant report indicates that this gradual step-by-step growth will provide the
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Page: 20 of 29
City with valuable experience in the MEU business before fully committing to operating a
full distribution business. Duncan/Navigant believes that all the MEU business models
(except MDU) would be viable immediately if supported by power purchase agreements
(PPA). Duncan/Navigant believes that viability of all of the MEU business models would
be enhanced including the MDU if supported by in-city electricity generation with a
capacity of 130MW. Duncan/Navigant believes using a gradual approach ensures that
the Council will have incremental decision points and that costs, benefits, risks and
impacts to the City associated with each step can be evaluated, debated and understood
before escalating the City's level of commitment.
The results of the Duncan/Navigant feasibility study demonstrate that the City's unique
characteristic and the projected financial benefits and other local benefits from
developing an electricity utility business would outweigh the legal, financial and
technical risks. In other words, based on the results of the feasibility study, it is
financially, legally and technically feasible for the City to implement an "electricity utility"
business subject to the adoption of final CCA regulations.
The Duncan/Navigant feasibility study illustrates that each of the recommended MEU
business models are viable as stand-alone endeavors. To maximize benefits of the
business models, the consultants recommend that the City concurrently pursue the
implementation of a CCA/Greenfieid MEU by 2006. Specifically, that CCA be
implemented immediately, subject to the PUC approval of the City's implementation plan
or adoption of pending regulations, and that Greenfield development be pursued within
two years and combined with the CCA. The consultant's also recommend that the City
reconsider a natural gas service and Citywide MDU beginning in 2010 after the City has
gained experience in operating an electric CCA/Greenfieid MEU. The consultant's also
recommend that the City develop ownership of generation capacity to enhance benefits
from the proposed MEU businesses by 2010.
A caution that needs to be highlighted is that there are critical regulatory issues that have
yet to be decided and that will have a major impact on the final policy action by the City
Council. The California Public Utilities Commission (CPUC) is currently reviewing costs
related to exit fees, municipal departing loads and the regulations for implementing CCA.
Although costs related to exit fees and municipal departing loads have been incorporated
into the MEU business proformas, these issues and the regulations for CCA need to be
fully resolved before the City commits to forming a CCA-MEU business. Notwithstanding,
the City has and should continue to engage in developing and positioning itself to forming
an MEU business prior to a final ruling from the CPUC on these matters.
Summary of SDG&E Franchise Aareement
As noted previously, this report provides an analysis of the consultant's MEU business
model recommendations compared to the implementation of a franchise agreement with
SDG&E. This section will outline the status and components of an agreement with the
Utility.
.-...--.. ..__..
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Franchise Description
Ordinance Nos. 2746 and 2747 adopted September 15, 1998 - Franchise Agreement -
grants SDG&E the right to locate electricity and natural gas distribution systems in City
"right-of-way" for a fee and other negotiated benefits. Under the Franchise, SDG&E has a
"non-exclusive" grant to distribute electricity and natural gas citywide to residents and
businesses. The Franchise Agreement expired on expired in June 30, 2003. The existing
terms and conditions of the expired franchise agreement are continuing on a month-to-
month basis.
Franchise Pavment
The City receives a franchise fee of 1.1 % of gross annual receipts for electricity and
2.0% of gross annual receipts for natural gas within the limits of the City. Other
negotiated benefits include transacting "Industrial Development Bonds" for SDG&E
capital projects. Under Rule 20A, SDG&E also allocates funds to underground
aboveground electric distribution lines based on priorities set by the City. These funds
are retained and managed directly by SDG&E. The chart below shows actual franchise
fee revenues from 1999 to 2003 and projected franchise fee revenues from 2004 to
2005 and 2006 to 2023. Projected Franchise Fees are based on "revenue
requirements" and franchise fees modeled in pro-formats prepared by
Duncan/Navigant.
Actual Franchise Fee Revenues
From 1999 to 2003
Year Electricity ($) Natural Gas ($) Total
1998 $663,907 $408,156 $1,072,063
1999 $723,636 $1,014,008 $1,737,644
2000 $730,334 $2,586,932 $3,317,266
2001 $1,025,938 $5,249,096 $6,275,034
2002 $709,553 $488,844 $1,198,397
2003 $774,303 $654,799 $1,429,102
Year Total
2004 $1,606,915
2005 $1,638,098
... ...-.-...-..-------.---.-.-...---.-
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Projected Franchise Fee Revenues
From 2006 to 2023
Year Electricitv ($\ Natural Gas ($) Total
2006 $972,544 $709,487 $1,682,031
2007 $996,858 $649,888 $1,646,746
2008 $1,021,779 $678,964 $1,700,744
2009 $1,047,324 $857,963 $1,905,287
2010 $1,073,507 $885,203 $1,958,710
2011 $1,100,344 $905,022 $2,005,366
2012 $1,127,853 $924,482 $2,052,335
2013 $1,156,049 $937,995 $2,094,044
2014 $1,184,951 $955,994 $2,140,944
2015 $1,214,574 $978,468 $2,193,043
2016 $1,244,939 $989,004 $2,233,943
2017 $1,276,062 $1,001,924 $2,277 ,986
2018 $1,307,964 $1,030,510 $2,338,474
2019 $1,340,663 $1,055,154 $2,395,816
2020 $1,374,179 $1,077,923 $2,452,102
2021 $1,408,534 $1,103,840 $2,512,374
2022 $1,443,747 $1,133,173 $2,576,920
2023 $1,479,841 $1,145,509 $2,625,350
Total $21,771,712 $17,020,502 $38,792,214
The total projected nominal revenue from franchise fees from 2006 to 2023 is
approximately $38.8 million. Additional revenues are realized if SDG&E refunds
existing bonds to realize lower interest rates. The City is paid 25 basis points for issuing
the bonds on behalf of SDG&E.
Status of Franchise Neaotiations
SDG&E has notified the City of their intention to reduce the City's undergrounding
allocation as well as other negotiated benefits if a formal Franchise Agreement is not Staff
believes that SDG&E has no basis for unilaterally reducing any benefits afforded the City
under the current expired franchise.
Staff is in on-going discussions with SDG&E negotiators to reach terms and conditions
for a Franchise Agreement that is mutually acceptable to both the City and SDG&E.
Staff cannot provide a definitive schedule to reach a conclusion to the negotiations at
this time.
Although Staff had intended to provide the City Council with a comparative analysis of
the benefits of an MEU versus a Utility Franchise Agreement, it cannot be completed
due to the lack of a franchise agreement proposal by SDG&E. Over the course of
negotiations, the City has provided SDG&E with a menu of options it considers
- -------------- ------- ------- ------
Council Workshop Date: 5/19/04
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important to a franchise agreement. SDG&E subsequently requested more detail to
clarify each of the options, which the City provided. The City's offer was prepared in the
menu fashion to provide greatest possible flexibility and allow SDG&E to select those
items that best met SDG&E's corporate guidelines for entering into a franchise
agreement, and to enhance the opportunity for a successful negotiation. After waiting
some time without a comparable formal or written counter proposal, the City then
submitted another offer, "back to back" without receiving a counter offer from SDG&E
and in a manner inconsistent with normal negotiating protocol. This offer reduced the
scope of the menu but retained those elements critical to an agreement. This offer is
still pending with no response. In fact, the only recent offer received from SDG&E could
be considered regressive. It recommended an excessive term of 55 years, with a
reduction in the rule 20A Undergrounding allocation and no other appreciable
enhancements.
Due to the extended nature of these negotiations, and the lack of an agreement with
SDG&E, Staff recommends the timely consideration of the MEU analysis and
recommendations.
City's MEU Business Model Options and Staff Recommendation
Advantaae of Municipal Utilities Over For Profit Utilities
The Duncan/Navigant report points out that municipal utilities have an inherent price
advantage over Utilities because the municipal utility is not motivated to produce profits
for shareholders but value for their residents and businesses. Public utilities are
permitted to set rates which cover both capital and operating expenses, fund utility
reserve accounts, in-lieu-of-tax payments to local governments, and other worthy public
works projects. In addition, the public utility has access to tax-exempt financing for
many capital expenditures. These key components provide the City with a significant
advantage regarding retail electricity rates as compared to remaining a full-requirement
customer of SDG&E.
Chula Vista Characteristics That Make It A Good Candidate For An MEU
Chula Vista's continued development within western Chula Vista, the mid Bayfront and
the eastern territories offers significant employment opportunities through new
businesses locating in this area. Energy costs can be an important consideration in an
employer's site selection. Electric rates in California are expected to remain high.
Current energy costs in the SDG&E service area are not competitive with other areas.
Comparatively, the SDG&E service area has the highest energy rates in California (for
example, the City of Anaheim advertised having the lowest electric rates in Orange
County.) A MEU opens up the opportunity to provide the Chula Vista community with
increased reliability and access to lower cost energy.
Size and Growth:
. Chula Vista is the seventh fastest growing City in the nation and expects to add a
minimum of 15,000 equivalent dwelling units, several million square feet of
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commercial and industrial space and a future major university on 500 acres. At
its current size, Chula Vista would rank in the top 20 out of the approximately 38
California public utilities based on sales, and the top 11 out of 38 based on
customer base.
. Acquiring title to new energy infrastructure in new development could lower the
cost of development for developers and add valuable assets to the City's
portfolio.
Tax Exempt Financino:
. Chula Vista can use tax-free financing for new energy infrastructure; this will
lower the relative cost of service.
Existino Enerov Infrastructure:
. Chula Vista is a host to major energy infrastructure:
0 A 706 MW base load power plant that is being considered for repowering.
0 Adjacent to a 4 MW landfill power plant with potential expansion to 8 MW
over the next several years.
0 Major regional natural gas and electricity distribution and transmission
lines throughout the City.
Additionally, according to the California Municipal Utility Association (CMUA)
approximately 38 publicly owned electric and gas utilities continue to successfully
operate in California. These public utilities have provided energy to nearly 3 million
customers, or 25 percent of the electric load at a cost that is on average 15% to 40%
less than their investor owned counterparts over the past several years. The public
utilities in California identified by the CMUA include:
Alameda (1887)* Imperial Irrigation District Riverside (1895)
Anaheim (1894) Lassen MUD (1986) Roseville
Anza Lodi Sacramento MUD (1947)
Azusa (1898) Lompoc Shasta Lake (1993)
Banning LA DWP Silicon Valley Electric (1896)
Biggs Long Beach Surprise Valley
Burbank (1913) Merced Irrigation District (1996) Toulumne County
Coalinga Modesto Irrigation District Trinity County PUD (1982)
Colton (1895) Needles (1983) Truckee Donner PUD
Glendale Palo Alto Turlock Irrigation District
Gridley Pasadena Ukiah (1897)
Healdsburg Plumas-Sierra Vernon (1989)
Hetch Hetchy W&P Redding
.Reflects the year in which the
pubiic utiiity was established.
Staff was not able to
determine this ¡ntonnation tor
every utility.
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Page: 25 of 29
Conclusion
The consultants have conducted a comprehensive analysis of the MEU business
options available to the City, which has subsequently undergone a comprehensive peer
review. The feasibility study recommends, and the peer review process supports, the
implementation of a CCA and Greenfield MEU in order for the City to begin to gain
control of it's energy future and meet the objectives stated earlier in this report. and
repeated below:
Local Control of City's Energy Future
. Establish a local Municipal Utility structure that's only focus is on service and
delivering value to the community, not profit to shareholders.
. Establish a local Municipal Utility that is accountable to local ratepayers, not
shareholders, state and federal regulators.
. Establish reliable electricity and natural gas supply that reduces or eliminates
scheduled brown outs and maintains the highest level of customer service.
. Establish land use guidelines for power lines and utility boxes that put local quality
of life issues first.
. Stabilize consumer rates.
. Enhanced Control of Local Conservation Funds to:
0 Ensure an environmental advantage for City residents and businesses,
0 Invest the $3,000,000 already collected from Chula Vista ratepayers each
year to produce real savings for current rate payers,
0 Establish better incentives for existing residents and businesses to invest in
conservation and clean generation options,
0 Invest in a more environmentally sustainable energy future based on
renewable sources that do not use fossil fuels,
. Invest in medium and long-term energy procurement and power generation
strategies that reflect the City's commitment to a sustainable environment and
cleaner air including;
0 CO2 reduction, the prevention of global warming, and particulate reduction.
. Investment in energy procurement and generation, infrastructure and operational
services that maintain existing jobs and create new quality jobs for local residents.
. Enable the utilization of the MEU as an economic development tool to retain and
attract businesses
- ------------ -<------
Council Workshop Date: 5/19/04
Page: 26 of 29
0 Establish better incentives that encourage developers to reduce costs
through increased invest in conservation and clean generation for residential
and commercial building using rate structures, infrastructure taxes and other
means available.
. New city revenues at no increased cost to ratepayers
0 Equitably invest new revenues generated from an MEU business throughout
the City in the form of enhanced existing services and/or new services.
. Enhance Chula Vista's vision to continue as a vibrant community in the region
and a leader in environmental stewardship.
In addition, other factors have come to light, which impact Staffs evaluation of the
findings and ultimate recommendations:
. Energy experts are predicting that the energy market is uncertain at best and
predicted to worsen unless additional infrastructure is added in the region.
I
. The Regional Energy Infrastructure Study (REIS) commissioned by SANDAG
indicates that unless additional energy infrastructure in added in the region to
serve the region, another crises will occur by 2005. SDG&E in its 20-year
resource plan reiterated that additional infrastructure was also needed to ensure
rate stability and reliable supply. The REIS suggest that at least two new base
load generation plants be added in addition to repowering of the existing power
plants in the San Diego region. REIS also recommends that additional
transmission lines be added to connect local sources and that a focus be
placed on an increase in conservation to ensure adequate supply. I
. The twenty year resource plan proposed by SDG&E to the PUC concentrates on
the construction of two new generation facilities and significantly greater
transmission capacity with the stated goal of reducing utility paid "reliability must
run" (RMR) charges. This translates into the possible elimination of the existing
South Bay and Encina Power Plants. The net result is a decrease in total local
generation; an increase in dependency on local generation from a single source
(SDG&E), greater reliance on energy transmitted from outside the region and
reduced competition to facilitate lower rates. SDG&E's 20-year resource plan
does not meet the intent or spirit of the regional goals established by the
Regional Energy Infrastructure Study. A regional plan that SDG&E helped
develop.
. In December 2002, SDG&E filed an application with the CPUC to increase the
"revenue requirement," effectively increasing future service territory rates by
$100,000,000 per year. This matter is pending a settlement agreement to
increase annual rates, which is being contested by the City.
In short, the lack of energy infrastructure and ever increasing utility rates in the region
- ~--_.._---~~_.-_._-_._-------_._--- ----
Council Workshop Date: 5/19/04
Page: 27 of 29
will continue to erode Chula Vista's budget and any flexibility to provide new programs
and better services. Based on the feasibility study, a City MEU business would be viable
and could address the City's objectives, which have been mentioned previously.
Comparison of the MEU Business models with the SDG&E Franchise Aqreement
Benefits
As shown in the table below, a majority of the MEU business models are more
financially favorable when compared to SDG&E's current "month-to-month" franchise
arrangement. In most cases, the City could implement an MEU business model that
would still allow SDG&E to retain their energy infrastructure and continue to provide
benefits under a franchise agreement.
ComDarison of MEU Business models and Franchise Benefits
MEU supply Nominal NPV of Average
Rank Business Model Strategy Savings Savings Annual
($ Millions) ($ Millions) Savings(%)
1* CCAIGreenfield Generation 351 122 10%
2 MDU Generation 329 109 9%
3* CCA Generation 244 90 8%
4* CCAIGreenfield Contracts 170 52 4%
5* CCA Contracts 86 28 2%
6* Greenfield Contracts 89 21 10%
7 MDU Contracts 16 (12) -1%
# Franchise None 39 16 none
*Franchise payments would continue under business models 1, 3. 4, 5 and 6 in areas served
by SDG&E with the exception of Greenfield areas served by the City.
The comparison above provides a financial basis that further supports the
implementation of a City MEU business model. Although a franchise agreement does
provide considerable resources that contribute to the City's ability to enhance public
services, it has not produced the kind of potential benefits afforded other California
public utilities, which are identified in the report under local control. It has not protected
residents and businesses from exponential rate increases, it has not produced
consistent conservation benefits that are commensurate with the amount of funds
collected annually from local ratepayers and it has not produced the kind of economic
development opportunities for Chula Vista businesses that Staff has asked for and
identified in other communities.
Staff Recommendation
The MEU Report and peer review clearly indicate that the City can start and operate a
feasible City MEU. The state of the energy market, the inherent risk involved with
creating a new MEU business and the significant start-up costs associated with forming
a new MEU operation are manageable risks that also represent opportunity that, over
time, have been born out by approximately 38 public utilities that produce benefits for
their respective communities at substantial savings for their ratepayers. The
.--------------'------
Council Workshop Date: 5/19/04
Page: 28 of 29
comparison of the MEU business models and the Franchise Agreement also
demonstrate that the City could potentially implement a model that generates financial
benefits to enhance City services, stabilizes rates for residents and businesses,
mitigates risk by phasing different components of the MEU over time and allows an
SDG&E franchise to continue for many years to come.
Political and legal challenges will present significant barriers and the level of their
cooperation should determine how much Chula Vista can and should rely on a future
partnership with SDG&E to provide energy services for Chula Vista ratepayers.
Staff ranked each business model relative to the associated risks and implementation
potential based on the cost/benefit, risks and timeline associated with each MEU
business model.
Summary of MEU Business models, StartuD Cost and Pro'ected Revenues
MEU Risk Benefits/ Startup Cost $ Supply Supply Calendar
Business Savings $ Strategy Strategy Year
Model Capital Start
Investment $
CCA Lowest 86 million 225 thousand Contract 2006
CCAJ Mid-low 170 million 13.8 million Contract 2006
Greenfield
CCA Mid 244 million 225 thousand 78 million Generation 2010
CCAJ Mid-hi 351 million 13.8 million 78 million Generation 2010
Greenfield
MDU Highest 329 million 185 million 78 million Generation 2010
Based on a review of potential cost/benefits, risk and likelihood of implementation, Staff
believes that the City should continue to pursue development of a City MEU business
model to control the City's energy future.
Staff recommendations are included below, but Staff is not requesting that Council
action be taken at this time on these recommendations. Staff is however, requesting
that Council direct Staff to return to council on June 8, 2004 for go/no-go actions
regarding the Municipal Energy Utility. At the June 8, 2004 meeting, Staff will
recommend that Council direct Staff to implement City MEU business models as
outlined below:
1. Direct Staff To Prepare Applicable Zoning And Permitting Ordinances That More
Specifically Address Time And Placement Issues Regarding Energy Utility
Infrastructure By Fall 2004.
2. Direct Staff to prepare a resolution that would, under its status as a Municipal
Utility (Ordinance No. 2835, June 5, 2001) declare itself a Community Choice
Aggregator.
3. Authorize Staff To Complete And Execute An Implementation Plan To Become A
..~..__...__.-_..__.---~--_._--~._-_._....
Council Workshop Date: 5/19/04
Page: 29 of 29
Community Choice Aggregation Administrator.
4. Direct Staff To Return To Council With A Full Staffing Plan For Implementation
Of The Greenfield Development And Community Choice Aggregation Programs
and appropriate funds therefore.
5. Direct Staff To Appropriate $475,000 In Additional Funds To Continue To
Implement The City's Energy Strategy, Plus The Cost For Additional Staff To
Implement The Selected Municipal Energy Utility Business Models.
The adoption of the resolution before City Council today, does not require an
appropriation and will not have an impact to the general fund. The items which Staff
has proposed to bring back to City Council at the June 8, 2004 meeting would require
an appropriation from the available fund balance of the General Fund:
Continue the work with the CPUC to develop viable
regulations and exit fees for a Community Choice Aggregation
(CCA) program (Outside Consultant Fees) $250,000
Complete and submit an implementation plan to the
CPUC for a Community Choice Aggregation Program
Based on the estimates provided by Duncan/Navigant $225.000
Total Funding Request Anticipated for June 8, 2004 $475,000
Once the City's CCA implementation plan is approved by the CPUC, Staff anticipates
that it will return to Council for additional funds for the pre-development, power
procurement and a Staffing plan to implement a MEU business model, should City
Council chose to move forward.
FISCAL IMPACTS:
The City Council's approval of the recommendation contained in this resolution will not
have an impact to the general fund. The action that Staff has outlined for consideration
at the June 8, 2004 meeting would require an appropriation from the un-appropriated
balance of the General Fund for an estimated $475.000.
ATTACHMENTS:
1. Peer Review Report - RW. Beck
2. Peer Review Report - Crossborder Energy
3. Peer Review Report - Tabors, Caramanis and Associates
4. MEU Report - Executive Summary
5. MEU Report - Report
6. MEU Report - Appendices
7. March 25, 2003 City Council Agenda Statement
..u.--.-- ....--.-----.----------...-.. .. .
~
RESOLUTION NO. 2004- -
RESOLUTION OF THE CITY COUNCIL OF THE CITY OF CHULA VISTA
ACCEPTING THE MUNICIPAL ENERGY UTILITY FEASIBILITY REPORT AND
PEER REVIEW ANALYSIS REPORTS; AND DIRECTING STAFF TO (1) RETURN
TO COUNCIL BY JUNE 8, 2004 FOR FURTHER CONSIDERATION OF THE
CONSULTANT'S RECOMMENDATION TO IMPLEMENT CITY MUNICIPAL
ENERGY UTILITY BUSINESS MODELS; (2) PREPARE AND DISTRIBUTE A
REQUEST FOR PROPOSAL FOR A FULL-REQUIREMENT GREENFIELD
DEVELOPMENT AND COMMUNITY CHOICE AGGREGATION SERVICE
PROVIDER AND RETURN TO COUNCIL FOR FURTHER ACTION; (3)
CONTINUE TO WORK WITH THE CALIFORNIA PUBLIC UTILITIES
COMMISSION TO ASSERT THE CITY'S. POSITION REGARDING THE
DEVELOPMENT OF COMMUNITY CHOICE AGGREGATION RULES, EXIT FEES
AND MUNICIPAL DEPARTMENT LOAD FEES; (4) CONTINUE TO WORK WITH
SANDAG TO IMPLEMENT REGIONAL ENERGY OPTIONS; AND (5) CONTINUE
TO ACTIVELY MONITOR AND INFLUENCE PENDING AND NEW CALIFORNIA
PUBLIC UTILITIES COMMISSION, CALIFORNIA ENERGY COMMISSION,
STATE AND FEDERAL ENERGY RULES AND LEGISLATION
WHEREAS, in August 2000 Council directed Staff to investigate any and all energy
options that the City could pursue to potentially protect Chula Vista residential and commercial
ratepayers from exponential rate increases, and better position the City, to deal with the volatility
and uncertainty of the energy market.
WHEREAS, in April 2001, following a Council workshop outlining the City's options,
Counci1 directed Staff to return with the implementing resolution adopting a City Energy Strategy
and Action Plan. In May 2001 Council passed Resolution No. 2001-162 adopting the City's
Energy Strategy and Action Plan
WHEREAS, at Council's direction, Staff began implementing the City's Energy Strategy
and Action Plan, adopted in May of2001; and
WHEREAS, on-going energy conservation programs are being implemented, City
facilities are renovated and built to exceed state energy efficiency requirements and renewable
power is being installed on some City facilities; and
WHEREAS, the purpose of the City of Chula Vista Municipa1 Energy Utility Analysis is
to identify and evaluate the potential for a municipal energy utility to 1) better control the City's
energy future, 2) provide stable rates for customers, 3) enhance local control of conservation
funds, 4) generate new city revenues, 5) enhance city services, 6) catalyze economic
development opportunities, 7) mitigate the local environmental impacts of energy generation and
distribution, 8) fund renewab1e energy projects and 9) generate quality local jobs
NOW, THEREFORE, BE IT RESOLVED that the City Council of the City ofChula Vista
does hereby accept The Municipal Energy Utility Feasibility Report And Peer Review Analysis
Reports; direct staff to return to council by June 8, 2004 for further consideration of the
consultant's recommendation to implement city municipal energy utility business models; direct
staff to prepare and distribute a "request for proposal" for a full-requirement Greenfield
development service provider and return to council for further action. direct staff to continue to
work with the California Public Utilities Commission to assert the City's position regarding the
development of community choice aggregation rules, exit fees and municipal departing load fees;
direct staff to prepare a resolution for consideration on June 8th declaring the City MEU a
"Community Aggregator" and directing preparation of an implementation plan for Council
consideration for ultimate filing with California Public Utilities Commission; direct staff to
continue to work with SANDAG to implement regional energy options; direct staff to continue to
actively monitor and influence pending and new California Public Utilities Commission, California
Energy Commission, state and federal energy rules and legislation.
Presented by Approved as to form by
d¿4:~ ~ J/¡ø
Sid Morris ~ Attorney
Assistant City Manager
n,tto,"eyl",oIMEU Wo,kshop 2004
Attachment 1
April 8, 2004
Via E-Mail CONFIDENTIAL R'W'~r(K
Mr. Glen Googins
Senior Assistant City Attorney
City Attorney's Office
City ofChula Vista
276 4th Avenue
Chula Vista, California 91910
Subject: Independent Review of Municipal Energy Utility Feasibility Analysis
Dear Mr. Googins:
On November 10, 2003, the City of Chula Vista ("City") retained R. W. Beck, Inc.
("R. W. Beck") to provide an Independent Review of the City of Chula Vista Municipal Energy
Utility Feasibility Analysis Phase I Report ("Feasibility Analysis") dated October 10, 2003,
prepared by Duncan, Weinberg, Genzer & Pembroke, P.C.; McCarthy & Berlin, L.L.P.; and
Navigant Consulting, Inc. ("Duncan, McCarthy, and Navigant").
In this Independent Review, R. W. Beck has perfonned a high-level fatal flaw analysis of the
strengths and weaknesses of the Feasibility Analysis. Specifically, R. W. Beck has provided an
Independent Review that includes:
- the identification and assessment of key assumptions to detennine reasonableness;
- a critical review of the methodology employed to analyze the options;
- a general assessment of the Feasibility Analysis assumptions, conclusions and recommend-
ations; and
- suggested improvements.
In our experience, the finns that perfonned the Feasibility Analysis (Duncan, McCarthy, and
Navigant) have a long history of providing quality service to cities such as the City of Chula
Vista. This Independent Review is intended to draw on R. W. Beck's experience in tenus of
preparing and presenting similar analysis and recommendations to public agencies, such as the
City. Our comments, observations, and recommendations are intended to provide constructive
feedback and observations that will better prepare the City and its consultants for upcoming
public discussion on the Feasibility Analysis.
The R. W. Beck Independent Review is presented in sections. These include:
- General Comments
- Community Choice Aggregation ("CCA")
- Greenfield Development ("GD")
- Combined ("CCAlGD")
- Municipal Distribution Utility ("MDU")
- Gas Case
Copyright 2004, R. W. Beck, Inc. All Rights Reserved
2710 Gateway Oaks Drive, Suite 300 South, Sacramento CA 95833-3502 Phone 916.929.3653 Fax 916.929.1710
Mr. Glen Googins
April 8, 2004
Page 2
As requested by the City, each section includes a review of the assumptions, methodology, and
an assessment of the conclusions and recommendations. Organizing the Independent Review in
this manner has produced some duplication of issues because they apply to two or more sections.
General Comments
Assumptions
- A discount rate of 10% is used for Net Present Value ("NPV") calculations. This rate is
unusually high for a public entity. Most publicly owned enterprises are using discount rates
in the 6% to 7% range given today's market. The impact oflowering the discount rate would
be to raise the expected savings over the life of the analysis, since future savings are
discounted at a lower rate. It is also important to note that the NPV savings are but one
measure of perfonnance. Review of cash flow, nominal dollar savings, and annual net
income are also important factors.
- Exit fees (California Cost Responsibility Surcharge for Municipal Departing Load) seem
high at the end of the study period. These fees primarily include (1) California Department
of Water Resources (CDWR) bond charges; (2) CDWR Power Charges; and (3) the "Tail
Competitive Transaction Charge" (Tail CTC). It remains unclear what the eventual
magnitude of these fees will be. The Feasibility Analysis assumes a high exit fee scenario
based on methodology established by the California Public Utilities Commission (CPUC) in
detennination of Direct Access Cost Responsibility Surcharge (DA CRS) issued on
November 7,2002 (Decision 02-11-022). This is a sound methodology; however, it is highly
likely that exit fees within the SDG&E service area in particular will be lower relative to
SCE and PG&E, since SDG&E had less exposure to the CDWR charges. The impact of
lower exist fees will be to improve the savings under applicable models (CCA, MDU and
Greenfield Development). The CPUC is continuing to debate exit fees in R.02-0l-0ll
(Municipal Departing Load Exit Fee) and R.03-1O-003 (Community Choice Aggregation
Exit Fees).
- The schedules for implementation are very optimistic. In each case, the schedule for
implementation is more rapid than what is likely to occur, particularly if SDG&E decides to
oppose the initiative. The long end of the range provided for implementation is what could
reasonably be expected.
Methodology
- Feasibility Analysis spreadsheets provided to us by Navigant do not contain the fonnulae or
sufficient detail to document that all potential costs were included in the analysis. Examples
include generation capacity reserve costs and financial reserves for debt service coverage. It
is important to recognize that the fonnulae contained in the model are proprietary and the
model contains the intellectual property of the consultant. Therefore, it is not expected that
infonnation other than the results would be made available. During the course of our
discussions, Duncan, McCarthy, and Navigant represented that all such applicable costs are
Mr. Glen Googins
April 8, 2004
Page 3
included in the Feasibility Analysis. Based on this limited review, it appears that the
methodology employed in the models used for this analysis is consistent with industry
practIce.
8 Some sensitivity analyses around key assumptions could be beneficial. For example, a range
of potential assumptions should be shown for:
. Different energy supply costs, including gas prices. (:1:20%)
. Lower distribution system purchase cost (-20%), but higher severance fees. (+100%)
. Distribution O&M costs. (:1:10%)
. Exit fees. (-25% to :1:10%)
Conclusion and Recommendation
8 A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
8 Exit fees are likely to decrease with time as existing obligations are restructured or expire.
Lower exit fees will result in greater savings to the City.
Community Choice Aggregation (CCA)
Assumptions
8 A key assumption in the Feasibility Analysis is that SDG&E will meet power supply ÍÌ'om
the market and pay a 5% premium to market, while Chula Vista generates 80% of its supply.
A more conservative approach for planning purposes would be to assume SDG&E power
supply costs at market prices or that SDG&E develops a power supply portfolio that includes
ownership of generation. Sensitivity could then be analyzed assuming variation of SDG&E
cost either above or below market.
8 Power plant costs for Chula Vista appear to be optimistic given R. W. Beck's experience.
Cost Element Analysis R. W. Beck
Capital cost $6001kW $8501kW
Variable O&M $2IMWh $2IMWh
Fixed O&M $4/MWh
Heat rate 7,000 MMBtulkWh 7,500 MMBtulkWh
Gas price escalation +O.7%/yr 2.3%/yr
Costs can vary, depending on various conditions, including location, existing in/Tastructure,
access to fuel, electrical transmission facilities, water supply, and emission restrictions.
Mr. Glen Googins
April 8, 2004
Page 4
. SOG&E prices are based on market prices that are projected to increase by 35% over the
study period, while Chula Vista supply costs (per kWh) increase by only 8% due to low gas
price escalation. This divergence results in a lower cost resource for the City.
. Exit fees are likely to decline over time as eJdsting obligations are restructured or expire.
Lower exit fees will result in greater savings to the City.
. It would be helpful to have a discussion of economic effect of customers opting out of CCA,
since it is unlikely that there will be 100% participation.
Methodology
. No comments.
Conclusions and Recommendations
. A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
. Exit fees are likely to decrease with time as eJdsting obligations are restructured or expire.
Lower exit fees will result in greater savings to the City.
. Something less than 100% participation should be assumed in the CCA Base Case analysis,
since it is unlikely that no customers will opt out of the CCA program.
. There should be more consistency in power supply costs between SOG&E and Chula Vista
(at a minimum in a sensitivity analysis).
Greenfield Development (GD)
Assumptions
. An assumption contained in the Feasibility Analysis for GO capital costs is that service
installation will be paid by the City. It is common industry practice for developers to pay for
most costs associated with utility service to new development. To the extent that some or all
of these costs are funded by developers, the economics of this business case will be
improved.
Methodology
. There are potential reliability issues with spot systems that are served through one facility.
Failure of a single facility can result in longer outages, unless there are other options for
routing service, such as loop feeds. Generally, the more redundancy that is designed into the
service, the greater the cost. Utilities have a rather wide range of practice when it comes to
distribution system design.
Mr. Glen Googins
April 8, 2004
Page 5
Conclusions and Recommendations
8 There is a fairly long lead time before GO becomes economic. Such a lengthy gap between
implementation and savings creates risk to the City, particularly if the CCA or MOO options
fail to be implemented.
8 Developer funding of GO utility in/Tastructure should be equal to what would be contributed
to SOG&E.
8 There should be discussion of adverse reliability issues in GD due to limited ability or
additional costs to loop feed to spot systems.
8 The City should make certain that it will move forward and likely be successful with the
implementation of either CCA and/or MOO before committing to this option.
8 A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
Combined (CCAlGD)
Assumptions
8 A key assumption in the Feasibility Analysis is that SDG&E will meet power supply /Tom
the market and pay a 5% premium to market, while Chula Vista generates 80% of its supply.
A more conservative approach for planning purposes would be to assume SOG&E power
supply costs at market prices or that SOG&E develops a power supply portfolio that includes
ownership of generation. Sensitivity could then be analyzed assuming variation of SOG&E
cost either above or below market.
8 Power plant costs for Chula Vista appear to be optimistic given R. W. Beck's experience.
Cost Element Analysis R. W. Beck
Capital cost $600/kW $850/kW
Variable O&M $2IMWh $2IMWh
Fixed O&M - $4/MWh
Heat rate 7,000 MMBtu/kWh 7,500 MMBtu/kWh
Gas price escalation +O.7%/yr 2.3%Jyr
Costs can vary, depending on various conditions, including location, existing inftastructure,
access to fuel, electrical transmission facilities, water supply, and emission restrictions.
8 SOG&E prices are based on market prices that are projected to increase by 35% over the
study period, while Chula Vista supply costs (per kWh) increase by only 8% due to low gas
price escalation. This divergence results in a lower cost resource for the City.
Mr. Glen Googins
April 8,2004
Page 6
. Exit fees are likely to decline over time as existing obligations are restructured or expire.
Lower exit fees will result in greater savings to the City.
. It would be helpful to have a discussion of economic effect of customers opting out of CCA,
since it is unlikely that there will be 100% participation.
. An assumption contained in the Feasibility Analysis for GD capital costs is that service
installation will be paid by the City. It is common industry practice for developers to pay for
most costs associated with utility service to new development. To the extent that some or all
of these costs are funded by developers, the economics of this business case will be
improved.
Methodology
. There are potential reliability issues with spot systems that are served through one facility.
Failure of a single facility can result in longer outages, unless there are other options for
routing service, such as loop feeds. Generally, the more redundancy that is designed into the
service, the greater the cost. Utilities have a rather wide range of practice when it comes to
distribution system design.
Conclusions and Recommendations
. Developer funding of GD utility in/Tastructure should be equal to what would be contributed
to SDG&E.
. There should be discussion of adverse reliability issues in GD due to limited ability or
additional costs to loop feed to spot systems.
. The City should make certain that it will move forward and likely be successful with the
implementation of either CCA and/or MDU before committing to the GD option.
. A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
. There should be more consistency in power supply costs between SDG&E and Chula Vista
(at a minimum in a sensitivity analysis).
Municipal Distribution Utility (MDU)
Assumptions
. A key assumption in the Feasibility Analysis is that SDG&E will meet power supply /Tom
the market and pay a 5% premium to market, while Chula Vista 80% of its supply. A more
conservative approach for planning purposes would be to assume SDG&E power supply
costs at market prices or that SDG&E develops a power supply portfolio that includes
ownership of generation. Sensitivity could then be analyzed assuming variation of SDG&E
cost either above or below market.
Mr. Glen Googins
April 8, 2004
Page 7
8 Power plant costs for Chula Vista appear to be optimistic given R. W. Beck's experience.
Cost Element Analysis R. W. Beck
Capital cost $600/kW $850/kW
Variable O&M $2IMWh $2/MWh
Fixed O&M - $4/MWh
Heat rate 7,000 MMBtu/kWh 7,500 MMBtu/kWh
Gas price escaiation +0.7%/yr 2.3%/yr
8 SDG&E prices are based on market prices that are projected to increase by 35% over the
study period, while Chula Vista' supply costs (per kWh) increase by only 8% due to low gas
price escalation. This divergence results in a lower cost resource for the City.
8 Exit fees are likely to decline over time as existing obligations are restructured or expire.
Lower exit fees will result in greater savings to the City.
8 A cost of $15 million for acquisition fees, severance, and start-up is likely very low.
8 Human Resource cost calculations assume fringes of 15% - public agencies' fringe costs are
generally closer to 40% or more.
8 Human resource requirements appear to exclude purchasing, warehousing, buildings &
ground, security, mail, legal, human resource, secretaries, and reception.
Methodology
8 No comments.
Conclusions and Recommendations
8 No reason given for consideration of using a Municipal Utility District or JPA.
8 A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
8 There should be more consistency in power supply costs between SDG&E and Chula Vista
(at a minimum in a sensitivity analysis).
Gas Case
Assumptions
8 No comments.
Methodology
8 There is discussion of pass-through of gas supply cost, but no discussion of carrying costs,
storage, or risk management.
Mr. Glen Googins
April 8, 2004
Page 8
Conclusions and Recommendations
. Consideration should be given to the assumption/methodology comments.
. A discount rate of 6% to 7% would be more reasonable for the City. As the discount rate is
decreased, savings to the City would increase.
Sincerely,
R. W. BECK, INc.
;JtÞ tl. &ø
Michael A. Bell
Principal and Senior Director of Client Services
c: Ken Mellor
09-00370-01000-00011121014 I 004238 R:\SacramentolProjects\Chula Vi'ta\O2e-00370.doc
Attachment 2
Cross border Energy
Comprehen.<ive Consulting for the North American Energy Industry
FINAL REPORT
Evaluation of N avigant Consulting's
Long-term SDG&E Rate Forecast
Prepared for the City of Chula Vista, California
MARCH 24, 2004
Principal Authors: R, Thomas Beach, Principal
Patrick G, McGuire, Policy Advisor
2560 Ninth Street. Suite 316 . Berkeley CA 94710 . (510) 649-9790 fax (510) 649-9793
Table of Contents
INTRODUCTION AND SUMMARY ............................................. 1
EVALUATION METHOD. . . . . . .. ....... .................................3
Constraints.............................................................3
Caveats................................................................3
KEY ASSUMPTIONS......................................... .................4
Natural Gas Price Forecast, as a Key Driver of Wholesale Power Costs in California. . .4
Natural gas prices at the California/Arizona border. . . . . . . . . . . . . . . . . . . . . . .4
Intrastate transportation costs and the fate of the Sempra-wide electric generation
rate.... ... ......... ....... ......... ........... ..... ...... .6
SoCalGas I SDG&E transportation charges for a City-owned gas utility. . . . . . . 8
New LNG supplies will impact gas prices in San Diego. . . . . . . . . . . . . . . . . . . . 9
Bypass potential in ChulaVista ......................................12
Wholesale Market Cost of Electric Power...... .......... ............... .....13
Cost and Composition of the Utility's Generation Portfolio over Time
...... ... . ... . ....... . .... ....... ....... ... ...... ........... . ..13
SONGS ................... ........ ........ ....... .............13
QFs............................................................ 14
DWRlong-teffilcontractpower.. ....... .......... ....... ..... .......14
Inter-utilitycontracts ..............................................15
Newrenewableorgas-firedpurchases ................................15
Sempra-ownedgeneration ..........................................16
Market purchases for the residual net short .............................16
ResourceMix....................................................16
AverageGenerationRates ..........................................16
Non-GenerationRates ...................................................17
Inflationrate.....................................................18
Productivity assumptions................................. ..........18
Conclusion......................................................19
Other Rate Elements ....................................................19
OTHER POSSIBLE FACTORS AFFECTING SDG&E'S RATES. . . . .. . . . . . .. . . . . . . . . . 20
Changes in Cost Allocation among the Customer Classes. . . . . . . . . . . . . . . . . . . . . . . 20
Changes in Rate Design Methodology... ......... ........ ............ ...... .20
Evaluation of Navigant Consulting's Long-term SDG&E Rate Forecast
I. INTRODUCTION AND SUMMARY
This report evaluates a long-tenn forecast of San Diego Gas and Electric's natural gas and
electric rates. Navigant Consulting (Navigant) prepared this forecast as a key component in the
municipal energy utility (MEU) feasibility analysis that it prepared for the City of Chula Vista
(City). The City has asked us to validate the key assumptions in the forecast and to conunent on
the reasonableness of the forecast results.
The following are the key conclusions of our review. We separate our findings into those
that apply to an electric MEU and those that apply to a natural gas MEU.
Electric MEV
. Navigant's projection of future natural gas prices is a key driver of its forecast of
SDG&E's future electric rates. Navigant's long-tenn forecast of natural gas prices is
reasonable, and is within 8% of similar recent forecasts that our finn and the California
Energy Conunission have prepared. However, Navigant also should perfonn sensitivity
analyses that reflect California border natural gas prices that are both 20% above
and 20% below the levels projected in their study, in order to bracket the likely range
of future gas market conditions and to further refine the analysis. We anticipate that at
lower natural gas prices the option for Chula Vista to develop its own gas-fired
generation within the City will be more attractive than Navigant portrays. The converse
will be true at higher gas prices.
. Navigant's forecast of natural gas transportation rates on the SoCalGas / SDG&E
system is too low, particularly for electric generators. Navigant's forecast does not
reflect the potential end to the Sempra-wide electric generation rate or the possible move
to a new cost allocation methodology. Assuming higher natural gas transportation rates
for electric generators in the San Diego area would slightly reduce the attractiveness of
the City owning its own gas-fired power plant.
. Navigant's forecast of wholesale electric prices is reasonable, given current and
expected future conditions in the wholesale electric market that serves California.
Natural gas prices are the key driver of Navigant' s forecast of wholesale electric prices.
. Navigant should verify that it has included direct access exit fee revenues as an offset to
SDG&E's cost ofDWR power. SDG&E direct access loads approach 20% of its overall
demand, and thus the utility will derive substantial revenues from its direct access exit
fee. We believe that Navigant has included these revenues, but its report is unclear on
this point.
-1- Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
. Using reasonable assumptions for SDG&E's resource mix and generation costs, we were
able to reproduce Navigant's results, to within one percent, for the generation portion of
SDG&E's rates over the period 2006 - 2011. This validates Navigant's projection of
the generation portion ofSDG&E's electric rates.
. Navigant's long-term inflation forecast is too high by almost 1%, Assuming a long-
tenn inflation forecast of 2.0% and a productivity factor of 1.5%, SDG&E's non-
generation rates should increase by no more than 0,5%, significantly less than
Navigant's assumed 1.3% annual escalation. Making this change in Navigant's forecast
of SDG&E' s future electric rates should not change the results of the Community Choice
Aggregation (CCA) scenarios (which assume that SDG&E continues to provide non-
generation services such as transmission and distribution), but may decrease the
economic benefits of the Greenfield Development or full-fledged municipal utility
options.
Natural Gas MEU
. Navigant erroneously forecasts that Chula Vista's cost to serve a gas-fired power plant
within the City would be higher than if SDG&E served the plant. Correcting just this one
error indicates that the NPV of a city-owned gas utility is close to zero. We conclude that
a more careful analysis of the potential benefits of a City-owned gas utility is
warranted,
. Navigant's analysis does not consider the potential benefits of Chula Vista's location
close to a potential major new source of liquified natural gas (LNG) supplies for both
upper and lower California. Chula Vista is uniquely situated to realize substantial
benefits from its proximity to the LNG tenninals proposed to be built in Baja California.
If an LNG tenninal is developed in Baja, as both Navigant and Crossborder expect to
happen, the cost of gas at the Otay Mesa border crossing will be competitive with
California / Arizona border prices. In this event, Chula Vista's close proximity to this
border crossing should give it the competitive leverage to obtain gas supplies at prices
that are significantly lower than supplies moved over the traditional route through the
SoCalGas and SDG&E systems. In this scenario, the potential net present value of the
benefits of a City-owned gas utility could be in the range of $42 to $73 million (with the
range of results depending on future SDG&E gas transportation rates). The City should
monitor closely the progress of the proposed LNG terminals and the regulatory
developments that will detennine how those new gas supplies can reach customers in
California. Finally, the potential availability of a low-cost source of natural gas for City-
owned gas-fired generation could have a significant beneficial impact on those MEV
scenanos.
-2- Crossborder Energy
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
II. EVALUATION METHOD
A. Constraints
Navigant did not provide us with a copy of the model that it used to prepare its SDG&E
rate forecast, due to confidentiality concerns. Navigant's Technical Appendix C, Section II.A,
does provide a broad description of how Navigant modeled future SDG&E rates. Because we
have not had access to the details ofNavigant's model, of necessity our evaluation has focused
on the material that is available for our review ~ the input assumptions used in the model and the
output that the model produces. We have also used our own data sources and energy price
projections, as well as data on SDG&E's rates produced in various CPUC proceedings. With the
data available to us, we have been able to duplicate Navigant's results for the generation
component ofSDG&E's electric rates, which is the key element ofNavigant's projection of
future SDG&E rates.
Finally, we recognize that Navigant completed its study in October 2003. As a result,
Navigant's projection does not reflect certain recent developments that have occurred in the past
several months, after the study was finalized. We indicate below several possible developments
that the City may want to include in any future updates to Navigant's work.
ß, Caveats
Our work has focused on whether Navigant's SDG&E rate forecast is based on the best
available infonnation for the key assumptions that will drive that forecast. The initial draft of our
report was prepared in November and December 2003, and reflects market conditions and
regulatory developments at that time. Many of the assumptions that both we and Navigant have
used involve projections of future prices in energy markets that are volatile and that can change
in ways that are difficult to predict. If energy market conditions change significantly, we
recommend that the City update and re-visit the results of the Navigant study to reflect the new
conditions. We also suggest a number of sensitivity studies that the City may wish to have
Navigant perfonn in order to understand how Navigant's results may change if certain key
assumptions are varied. These sensitivity analyses are important if the City is to understand the
robustness ofNavigant's findings under changing market conditions.
-3- Crossborder Energy
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
III. KEY ASSUMPTIONS
A, Natnral Gas Price Forecast, as a Key Driver of Wholesale Power Costs in
California,
Navigant's forecast of delivered natural gas prices in the SDG&E service territory is a key
driver of its forecast of the generation component of SDG&E's electric rates. The gas price
forecast, including SDG&E and SoCalGas rates to transport gas across their pipeline systems,
also plays a key role in Navigant's evaluation of the potential economic benefits of the City's
development of a municipal gas utility. The delivered cost of natural gas has two principal
components - first, the market price of gas at the California border and, second, the
transportation costs required to deliver gas /Tom the border to the end user's burner-tip across
various pipeline systems. We evaluate each of these components ofNavigant's gas price forecast
separately.
1. Natural gas prices at the California/Arizona border,
Navigant forecasts an average California border price of $4.90 per MMBtu for the period
from 2006 to 2023. This appears to be a reasonable forecast given today's market outlook and
conditions.
To judge the reasonableness ofNavigant's forecast, we compare it to other market
forecasts. We have assembled our own forecast of gas prices, based on (I) recent prices in the
NYMEX Henry Hub, Louisiana gas futures market and (2) our analysis of historical and likely
future basis differentials! between the Henry Hub and the southern California border. We have
also reviewed gas price projections contained in the California Energy Commission's August
2003 Natural Gas Market Assessment.
Navigant's forecast was assembled in June 2003, at a time when both spot and futures
prices were over $1.00 per MMBtu higher than the November 2003 prices used in our forecast.
Nevertheless, Navigant's forecast for California appears to be reflective of recent market
conditions in California. This is probably the result of Navigant' s assumption of a much larger
(negative) basis differential for the southern California border. For example, Figure 2 (page 104)
! The "basis differential" is the price difference for a commodity between a reference
market and a market in another location. Thus, the basis differential provides the market value of
transporting the commodity between the two markets. In this case, the reference market is the
NYMEX gas futures market located at the Henry Hub in Louisiana. The second market is at the
Southern California / Arizona border at Topock, Arizona. The basis differential is the difference
in prices between the two markets.
-4- Crossborder Energy
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
ofNavigant's Technical Appendix indicates a ($0.66) basis differential (i.e. Henry Hub $5.99 per
MMBtu vs. Topock $5.33 per MMBtu) for the period January to June, 2003.
Our current forecast of California border prices in the 2006-2023 time frame averages
$5.08 per MMBtu - a 4% increase over Navigant's border price forecast. Our forecast reflects
November 2003 futures market conditions2 For the basis differential we have assumed ($0.21)
per MMBtu, based on the historical relationship between the Henry Hub and Topock over the
period from 1994 to 2003. We excluded the natural gas "crisis" year of2001, which reflected
extremely high gas prices and severe pipeline constraints to California.
The historical basis differential between the Henry Hub and the southem California
border is portrayed in Figure 1. Navigant's report also provides a useful summary of historical
gas prices and basis differentials. Figure I illustrates how high basis differentials have spurred
the construction of new pipeline capacity to California. The added capacity then depresses the
basis differential until demand growth constrains the pipelines and the basis differential
increases. For example, from 1988 - 1993, California border prices exceeded the Henry Hub by
$0.39 per MMBtu. After the completion of the 700 MMcf/d Kern River pipeline in March 1992,
prices in California decreased to the level of Henry Hub prices, and even fell below the Henry
Hub at times. Similarly, the pipeline capacity serving California has expanded by 1.6 Bcf/d since
the "basis blow-out" of the 2000 - 2001 energy crisis. As a result, Topock prices today are again
at or below the Henry Hub benchmark. With the expected addition of major new LNG supplies
to the California market by 2007, we expect basis differentials for the California market to
remain low or slightly negative to the Henry Hub. The historical basis differentials are
summarized in Table I, below.
Table I - Historical Gas Prices and Basis Differential
Period Henrv Hub ToDock Basis
1989-1993 $1.75 $2.14 $0.39
1994-] 996 $2.12 $1.71 ($0.41)
1997-1999 $2.29 $2.37 $0.07
2000-2001 $4.]5 $7.10 $2.95
2002-2003 $4.34 $4.00 ($0.35)
2 We recognize that gas prices have continued to rise in December 2003. Today's gas
futures would support a forecast as much as $0.50 per MMBtu higher than presented here. The
recent increases appear to have been driven largely by a major early-winter snowstonn on the
Eastern Seaboard that has raised expectations for a colder-than-anticipated winter. We anticipate
that prices will moderate as more seasonable weather returns.
-5- Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
Our forecast of southern California border prices, at Topock, is shown in Table 2. Again,
we have used November futures market prices with a ($0.21) per MMBtu basis differential. The
average price for the period 2006 to 2023 is $5.08 per MMBtu.
Table 2 - Cross border Gas Price Forecast (2003 $ per MMBtu)
2006 2007 2008 2009 2010 2illl 2012 2013 2014
$4.41 4.49 4.50 4.51 4.58 4.68 4.79 4.89 5.00
2015 2016 2017 2018 2019 2020 2021 2022 2023
5.09 $5.20 $5.22 5.40 5.51 5.61 5.72 5.86 $6.01
An additional source of gas price forecasts is the California Energy Commission (CEC),
which in August 2003 released its Natural Gas Market Assessment. This market assessment
includes a gas price forecast in constant 2000 dollars. The CEC forecasts natural gas prices using
a large-scale model of gas production, pipelines, and demand across the entire North American
continent. When adjusted to 2003 $ per MMBtu, the CEC forecast for Topock for the period
2006 to 2023 is $4.52 per MMBtu. Thus, the CEC forecast is lower than Navigant's forecast by
approximately 8%.
We conclude that Navigant's forecast is reasonably close to current price expectations.
We do recommend that Navigant prepare sensitivity analyses that reflect natural gas prices that
are both 20% above and 20% below the levels projected in Navigant's study. These sensitivity
analyses should bracket the likely range of future gas market conditions. Understanding the
impacts of the high gas price sensitivity case is particularly important, because we understand
that MEU benefits will decline as gas prices increase.
2, Intrastate transportation costs and the fate of the Sempra-wide
electric generation rate,
Navigant has assumed a transportation rate of$0.28 per MMBtu for electric generation
customers (EG) to move their gas supplies from the California border to their plants on the
SDG&E or SoCalGas systems. If the CPUC implements a restructuring of the rates and services
on the SoCalGas system known as the Comprehensive Settlement Agreement (CSA), Navigant
projects a slightly lower EG rate of $0.24 per MMBtu. As explained below, there are two
reasons why we think that these forecasted transportation rates are too low.
An End to the "Sempra-wide" EG Rate, First, Navigant assumes the continuation of the
"Sempra-wide" EG rate on the SoCalGas and SDG&E systems. In April 2000, the CPUC made
the surprising, and very controversial, decision to equalize transportation rates to electric
-6- Cross border Energy
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Nav;gant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
generation customers on the SoCalGas and SDG&E systems. As both SoCalGas and SDG&E
are affiliates of Sempra Energy, the resulting policy is called the "Sempra-wide" EG rate.
Historically, for at least the decade prior to April 2000, EG rates have been much higher
on the SDG&E system than on the SoCalGas system, because gas bound for San Diego must
flow through the SoCalGas system before reaching SDG&E. EG volumes moving to power
plants in San Diego had to pay separate transportation charges on both the SoCalGas and
SDG&E systems. This "pancaking" of a SoCalGas wholesale rate plus the SDG&E EG retail
rate produced a total rate for power plants in San Diego that was typically $0.15 to $0.20 per
MMBtu higher than the retail EG rates paid on the SoCalGas system by EG customers located in
the Los Angeles Basin. Electric generators in the San Diego area mounted a major, and
successful, campaign in the CPUC's last SoCalGas biennial rate proceeding (BCAP) to remove
this rate "pancaking," and to equalize EG rates across all southern California. They argued that
all generators in southern California must compete in the same electric market (the California
Power Exchange [PX]), and that the "pancaking" of gas rates discouraged the development of
much-needed new electric generation in the San Diego area.
Whether to continue the Sempra-wide EG rate will be a major issue in the SoCalGas
BCAP that the CPUC will conduct in 2004, to set new rates effective January 1,2005. The
Sempra-wide EG "subsidy" increases SoCalGas' EG rate by about $0.06 per MMBtu, or 12%.
We are certain that electric generators in the Los Angeles area will urge the CPUC to end this
subsidy of San Diego generators by LA. generators. In our view, the California energy crisis has
undennined the arguments in favor of the Sempra-wide EG rate. The California PX is defunct,
and there is no longer a large, centralized electric market out of which the electric utilities must
buy all of their power. Furthennore, the California electric utilities have resumed their historic
roles of buying the power for their individual service territories. Finally, significant new power
plants have been completed or are under construction in the San Diego area and northern Baja
California, Mexico. These plants are likely to be served from the new North Baja interstate
pipeline and from future liquified natural gas (ING) supplies. Thus, the need for a special gas
rate on the SDG&E system to encourage new generation in the San Diego area is much less
pressing today than in 2000.
For these reasons, we believe that there is a 50% chance that the Sempra-wide rate will be
repealed effective January 1,2005. ¡fthe Sempra-wide EG rate is eliminated, distinct EG rates
for SDG&E and SoCalGas would be established, resulting in an increase in the SDG&E EG rate
of as much as an 65%. Table 3 shows the impacts of repeal of the Sempra-wide EG rate, based
on SDG&E's recent BCAP filing (A. 03-09-031, September 17,2003). The table shows these
impacts under both long-run marginal cost (LRMC) and embedded cost rate methodologies,
which we discuss in the next section.
-7- Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
Table 3 -Impact of/he Sempra-Wide EG Rate Methodology ($ per MMBtu)
LRMC Embedded
UI[J IILlJ] ,-' I L,jJL
IIi II 1111'11 II I
'I II I
percent 65% 45%
A Move to an Embedded Cost Allocation. The second factor that may increase
SDG&E's gas transportation rates is a change in the methodology that SDG&E uses to allocate
the costs of its gas system among its customer classes. In their recent BCAP filings in September
2003, SDG&E and SoCalGas have asked the CPUC for pennission to change their cost
allocation methodology. The utilities propose to use an "embedded cost" allocation instead of
the current allocation based on long-run marginal costs (LRMC). In essence, this change would
shift costs from small "core" customers (residential and small business) to large "noncore"
customers such as industrial and electric generation users. In addition, with higher noncore rates
under the embedded cost method, the end to the Sempra-wide rate would have a magnified
effect.
We believe that there is a 50/50 chance that the CPUC will move to the use of embedded
costs. Combining this with a 50% probability of ending the Sempra-wide EG rate, we obtain a
projected EG rate for the combined SoCalGas/ SDG&E system of $0.60 per MMBtu. This rate
is calculated as an average of the rates shown in Table 3 above. We recognize that this rate
includes a large noncore balancing account undercollection that we expect to be amortized by the
end of2005. This undercollection amounts to $0.13 per MMBtu. Thus, our projection of the
2005 SDG&E EG rate excluding this undercollection is $0.47 per MMBtu. This expected
SDG&E EG rate is significantly higher than Navigant's assumed EG rate of $0.28 per MMBtu.
3. SoCalGas / SDG&E transportation charges for a City-owned gas
utility,
Navigaot assumes that a City-owned gas utility would pay a combined SoCaIGas/SDG&E
transportation rate of$0.41 per MMBtu for service to an electric generation facility in the City
(see Pro Fonna analysis, page 94). This rate consists of an $0.18 per MMBtu wholesale rate on
the SoCalGas system and a $0.23 per MMBtn wholesale rate on the SDG&E system. IfSDG&E
remains the serving utility, this generator is assumed to pay just the Sempra-wide EG rate of
$0.28 per MMBtu. This transportation rate disparity appears to be a major reason why Navigant
concludes that it would not be economic for the City to pursue the creation of a gas utility.
We think that this assumed rate disparity is wrong. There is already a precedent for the
rate that applies ifboth SoCalGas and SDG&E transport gas across their systems to an electric
generator not on the SDG&E system. This precedent is Sempra's service to the Mexican power
-8- Crossborder Energy
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
plant at Rosarito. The CPUC has required Sempra to charge the Sempra-wide EG rate for this
service3 There is little difference between this service and the service that SoCalGas and
SDG&E would provide to an electric generator in Chula Vista that is served from a City-owned
gas system.
Simply correcting this one erroneous assumption produces a significant change in the
results ofNavigant's pro forma analysis of a City-owned gas utility, as shown in Attachment A
to this report. The net present value (NPV) shown in Navigant's pro forma analysis increases by
$23 million if the EG rate difference between service from the City versus SDG&E is eliminated.
This offsets most of the $24 million NPV in losses assumed by Navigant if a City-owned EG
must pay a "pancaked" SoCalGas/SDG&E rate of $0.41 per MMBtu. Moreover, the revised pro
forma analysis shown in Table 4 indicates that there are benefits for roughly the first nine years.
This tells us that a more careful analysis of the potential benefits of a City-owned gas utility is
warranted.
4, New LNG supplies will impact gas prices in San Diego,
It should also be emphasized that natural gas prices in the San Diego area could decrease
significantly as a function of new LNG supplies entering the California market starting in 2007.
Five major energy companies are competing to build an LNG tenninal in Baja California,
Mexico. Other proposals would site the tenninal in Long Beach or offshore ITom Ventura,
California.
Given the number of developers active south of the border, Baja California appears to be
the most likely location for the first LNG tenninal on the West Coast. An initial LNG tenninal
would be able to deliver 700 MMcf/d to 1 Bcf/d. From a Baja tenninal, LNG supplies could
flow either north on the TGN pipeline to the SDG&E system at the Otay Mesa international
border crossing, or north and east via the TGN and North Baja pipelines to the El Paso /
SoCalGas interconnect at Ehrenberg / Blythe on the California / Arizona border.
SDG&E has indicated that, at minimal cost, it can accept up to 400 MMc£'d of LNG into
its system at Otay Mesa for delivery to SDG&E or SoCalGas customers. We also expect 300
MMc£'d to serve Mexican power plant loads in the Tijuana / Mexicali area. LNG would
completely displace gas that today flows south and west on the North Baja and SoCalGas /
SDG&E systems to serve these San Diego and Mexican markets. Any LNG that does not serve
San Diego or Mexican loads could flow east on North Baja to the California / Arizona border
market at Blythe.
3 This policy was established in CPUC D. 99-09-071 (September 16, 1999).
-9- Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
In our opinion, southern California - and San Diego in particular - is clearly the
preferred market for LNG from an initial terminal in Baja. LNG would provide a long-sought
second source of gas supply for the San Diego area, which has always paid higher rates for gas
service due to its location "behind" the SoCalGas system. Both LNG suppliers and consumers
should prefer that LNG supplies flow to the Sempra / SDG&E system at Otay Mesa rather than
over North Baja to the California/Arizona border market, because the SDG&E option avoids
transportation charges on North Baja (on the order of $0.25 per MMBtu). In addition, gas
customers in SDG&E's territory would gain a new source of gas supplies that does not require
transportation over the SoCalGas system, thus also avoiding SoCalGas' wholesale transportation
costs (now about $0.18 per MMBtu, but expected to rise substantially in 2005 as a result of the
new SoCalGas BCAP case). An LNG supplier would greatly prefer to sell gas at the OtayMesa
border crossing to a customer in San Diego, where the competing sources of gas are supplies
delivered over the SoCalGas system at the California border price Jllilli $0. I 8 per MMBtu for
wholesale transportation on SoCalGas. The LNG supplier's other option (except for local
markets in Baja) would be to move gas over North Baja to the California border at Ehrenberg, for
which the supplier would receive the California border price minus the $0.25 per MMBtu
backhaul charge on North Baja. On a short-term basis, if there is spare capacity to move gas east
on North Baja, then the market price in Tijuana may be just slightly below the Topock border
price, due to the low market value of North Baja capacity. In sum, although Sempra has yet to
establish Otay Mesa as a receipt point for gas flowing into the SDG&E system, we believe that
state policymakers would be foolish not to force Sempra to do so, because that is the most direct
and most economical means to move new LNG supplies to the southern California market.
Given these market dynamics, ifthe LNG supplies delivered to a terminal in Baja
California exceed the capacity of local markets and the SDG&E system to absorb them, we
expect the price for gas at the Otay Mesa border crossing to be less than the southern California
border price at Topock, Arizona. LNG supplies would fit into the economic landscape in such a
way that the netback price for LNG is equal to the Topock market less the market value of
transportation on the North Baja pipeline. Thus, if an LNG terminal is built in Baja California,
we expect that gas prices at the Otay Mesa border crossing will be competitive with California /
Arizona border prices. Thus, customers in Chula Vista should be able to obtain gas supplies in
the Otay Mesa market at prices at or below the benchmark Topock price, and simply pay a
transportation charge to SDG&E to deliver this gas (and perhaps a charge for receipt point access
at Otay Mesa, as discussed below), thus avoiding the SoCalGas wholesale transportation costs
that all customers on the SDG&E system must pay today.
We believe the case described above to be the most likely. However, it should be noted
that to the extent LNG supplies initially enter the market in small amounts, or to the extent that
LNG supply is initially dominated by a single supplier (e.g. a market power scenario), gas at the
Otay Mesa could be priced on a net-forward basis, such that the end-use customer (e.g. Chula
Vista) would face a price equal to the California border price Jllilli the market transportation rate
-]0- Crossborder Energy
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
on either North Baja or the Sempra system. In this scenario, the customer would be confined to
negotiating a small discount to service from the price of otherwise available supplies on the
SoCaIGas/SDG&E system. We do not expect this scenario to materialize so long as multiple
suppliers of LNG and conventional supplies compete with each other to serve customers in the
Baja California / San Diego area and a single LNG supplier is not allowed to monopolize the
receipt point capacity into the SDG&E system at Otay Mesa.
We also anticipate that SoCalGas and SDG&E will implement a system of fion capacity
rights at the receipt points where gas enters the Sempra system. This system may be the CSA
that the CPUC is now considering whether to implement; or it may be a revised system of fion
rights that is implemented in 2006. Under any such scheme, we expect that there will be a charge
for receipt point access into the SDG&E system at Otay Mesa in the range of $0.06 to $0.08 per
MMBtu.'
Once gas enters the SDG&E system at Otay Mesa, the charge for transportation to end
users should be less than the current transportation rates for service over the combined SoCalGas
and SDG&E systems. We note that the SDG&E system today provides a rate for transportation
only on the SDG&E system to EGs located within San Diego County (Schedule EG-SD) of
approximately $0.10 per MMBtu.' Even with an additional receipt-point access charge of$0.08
per MMBtu, this rate would be much lower than the current combined SoCalGas / SDG&E EG
rate of $0.27 per MMBtu. Thus, to the extent that electric generation in Chula Vista takes gas
service from the California/Mexico border, the cost of transportation on the SDG&E system from
Otay Mesa should be lower than SDG&E's traditional rates that combine transportation over
both the SoCalGas and SDG&E systems. This should remain true even ifSDG&E's
transportation rates rise in the upcoming BCAP case due to the end to the Sempra-wide subsidy
or a change to an embedded cost allocation.
In sum, Navigant's analysis does not consider the potential benefits ofChula Vista's
location close to a potential major new source of natural gas supplies for both upper and lower
California. We anticipate that the cost of gas at the Otay Mesa border crossing will be
4 The CPUC will make this choice early in 2004.
, Under the CSA, the charge for fion receipt point capacity is 7.8 c/MMBtu. SoCalGas
recently suggested a lower charge of 6 c/MMBtu as one of certain changes to the CSA that it
proposed earlier this fall.
, This rate currently applies only to deliveries only from the SoCalGas / SDG&E
interconnect at Rainbow. We assume that the CPUC also will approve such a rate for deliveries
from the international border at Otay Mesa.
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
competitive with California / Arizona border prices. We also expect that the cost of moving
supplies from Otay Mesa to customers on the SDG&E system with be the cost of receipt point
access at Otay Mesa plus an unbundled rate for transportation on the SDG&E system alone.
5, Bypass potential in Chula Vista,
The fact that gas prices at the California/Mexico border may be the same as or even lower
than prices at the California/Arizona border, once LNG supplies enter the market, presents a
bypass opportunity for Chula Vista. Even if the City does not actually build a bypass pipeline,
the threat of bypass may exert significant leverage on SDG&E at least to discount its gas
transportation rates to the cost of bypass service.
Table 4 presents a preliminary analysis of the possible cost to bypass the SDG&E system
via a pipeline to the Otay Mesa border crossing. The distance from the South Bay power plant to
the Otay Mesa border crossing is no more than IS miles. SDG&E local transmission pipelines
(eight- and ten-inches in diameter) already run along most of the route (roughly parallel to
Highway 905 and Interstate 5). A conservative, order-of-magnitude estimate for the cost of a
pipeline to bypass SDG&E's service to South Bay and Chula Vista is $32 million ($2 million per
mile plus $2 million for meter stations'), for construction in a heavily-developed urban and
suburban environment. We have used a Pacific Gas and Electric pipeline cost-of-service model
to estimate O&M and A&G costs for operating this pipeline. Consistent with the Navigant study,
we assume that the City finances this project over 20 years at an interest rate of 5.5%. With
assumed City gas volwnes of90,800 MMBtu per day, or 33,157 M3Btu per year as shown on the
gas utility pro-fonna, the resulting transportation rate for a City-owned power plant at the South
Bay site is $0.14 per MMBtu, which is very competitive even with today's Sempra-wide EG
transportation rate of$0.27 per MMBtu. As shown in the revised pro-forma that is Attachment
B, at a $0.14 per MMBtu rate for 100% ofChula Vista's projected gas loads, plus Navigant's
assumed distribution costs within Chula Vista, the NPV benefit of a municipal gas utility is on
the order of$73 million assuming our expected SDG&E EG transportation rate of $0.47 per
MMBtu. Even using the current Sempra-wide EG rate of$0.27 per MMBtu, which we believe is
too low, the gas MEV benefits are $42 million if the City can bypass the SDG&E system.
, We reviewed the costs ofPG&E's expected 2004 local transmission pipeline projects
(16 to 24-inch pipelines) in its Gas Accord II application to the CPUC (A. 01-10-011). All of
these projects had costs that ranged from $1.0 to $2.0 million per mile. To be conservative, we
use the upper end of this range. These costs are also consistent with SDG&E system expansion
costs reported in the utility's 1999 BCAP case, A. 98-10-031. SDG&E's large Otay Mesa meter
station cost $1.3 million in 1999 $.
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Table 4
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option -- Cost to Bypass SDG&E
Pipeline Capital $ 32,000,000
Interest 5.5%
Term 20 years
Annual Bond Charge $ 2.677.739
Annual O&M @ 3.2% $ 1.024,000
Annual A&G @ 3.0% $ 960.000
Total Annual Costs $ 4.661.739
Throughput 33,157 M3Btu
90.8 M3Btu per day
Bypass Rate $ 0.141 perMMBtu
Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
B. Wholesale Market Cost of Electric Power
Navigant's electricity spot market forecast for 2006 to 2023 reflects an average price of
$49 per MWh. Navigant has told us that they did not use a production cost or market simulation
model to forecast electric market prices. Instead, they appear to have calculated wholesale
electric prices by applying a market heat rate of approximately 9,000 Btu per kWh, and a variable
O&M adder of $2 per MWh, to their burner-tip gas price forecast. This is a common forecasting
methodology that reflects the fact that natural gas-fired generation is typically the marginal,
market-clearing source of electricity in California.
In 2003 Dow Jones has reported California spot market prices for electricity of roughly
$45 per MWh. Gas prices have been high in 2003, however, and thus the "market heat rate"
reflected in the Dow Jones day-ahead spot prices has been close to 8,500 Btn!kWh. During the
energy crisis of2000 - 2001, market heat rates were much higher. However, given the
determination of both state and federal regulators to avoid similar disasters in the future, we
expect capacity reserve margins to be planned so as to avoid price spikes, with most merchant
generators depending on long-term contracts to recover average costs. Thus, in this environment,
we would expect the market heat rate to remain at values in the range of 8,500 to 9,000 Btu per
kWh. This notion is supported by Navigant's own assumptions for the heat rates of new gas-
fired combined-cycle plants (7,000 BtulkWh) versus older, less efficient gas-fired generation (at
10,000 BtulkWh). As older generation is gradually displaced by newer generation, we would
expect the market heat rates to move towards the 7,000 Btn!kWh value slowly over time,
assuming that enough new plants are built at least to offset electric load growth.
Thus, we find that Navigant's projection of wholesale electric market prices is
reasonable, given its underlying gas price forecast.
C. Cost and Composition of the Utility's Generation Portfolio over Time,
We have reviewed the reasonableness ofNavigant's projection ofSDG&E's generation
costs. Because Navigant did provided a breakdown of its assumed SDG&E resource mix into the
volumes and costs for each of its component resources, we did our own projection ofSDG&E's
likely future resource mix, using both the input data that Navigant provided as well as our own
data sources.
1. SONGS
Navigant has used data from SDG&E's 2003 Cost-of-Service case and from the current
Southern California Edison (Edison) general rate case to project SDG&E's 20% share of SONGS
costs. We have reviewed the sources for this data, and concur that Navigant has used the best
available data.
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Navigant's SDG&ERate Forecast FINAL REPORT
March 24, 2004
We used data on expected SONGS production from Edison filings before the CPUC.
2, QFs
Navigant used 2002 FERC Fonu 1 data to project SDG&E's cost of power /Tom the
qualifying facilities that sell to SDG&E. Navigant assumes that 67% ofSDG&E's QF costs are
linked to natural gas prices.
We disagree with Navigant's assumption that QF contract quantities will decrease over
time. Navigant cites its October 2002 consultant's report supporting the DWR bond financing
(Consultant Report) as the source for this assumption. In the long-tenu electric procurement plan
that SDG&E filed in the summer of 2003 in the CPUC's procurement docket (R. 01-10-024),
SDG&E stated that it expects to re-contract with the QFs on its system, when the QFs' original
power purchase contracts expire.' Most of SDG&E's QF power comes from four large
cogeneration facilities. Based on our knowledge of these facilities, we expect that they will
continue to operate over the forecast period, particularly if SDG&E continues to be willing to
purchase their output. Thus, we have assumed no decline in QF contract quantities over the
forecast period. This is a minor change in Navigant's assumptions, as the decline that Navigant
has assumed is not great.
We have made our own estimates ofNavigant's assumed QF costs over time, based on
SDG&E's short-run avoid cost (SRAC) energy pricing fonuula, which is linked to natural gas
prices. We also assumed that SDG&E will pay $20 per MWh in finu capacity payments to its
QFs.
3, DWR long-term contract power
As a primary consultant to the DWR, we understand that Navigant has significant
expertise modeling the quantities and costs of the DWR long-tenu contracts. We have used data
from the CPUC's exit fee proceeding (R. 02-01-011) on the expected costs and volumes for the
DWR contracts assigned to SDG&E.
We are unclear on whether Navigant has included direct access exit fee revenues as an
offset to SDG&E's cost of DWR power. This is an important point to verify with Navigant,
because SDG&E has a high percentage of direct access loads (approaching 20%) and thus will
derive substantial revenues from its direct access exit fee. Our projection of SDG&E's
8 See "Direct Testimony of Robert J. Resley" filed on behalf of SDG&E in R. 01-10-024
(April 30, 2003), at pages 14-15.
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
generation rates for bundled customers assumes that exit fee revenues are used to reduce those
rates.
4, Inter-utility contraçts
Navigant used 2002 FERC Fonn 1 data to project SDG&E's cost of power from its inter-
utility contracts. It is our understanding that these contracts expire at the end of 2003, except for
the contract with Portland General Electric (PGE) for a share of the output of the Boardman coal-
fired plant in Oregon. We included only the PGE contract in SDG&E's resource mix after 2003.
5, New renewable or gas-fired purchases
California's recently-enacted Renewables Portfolio Standard (RPS) charts an ambitious
course for expanding the amount of renewable electric generation in the state. The key element
of the RPS legislation, SB 1078, requires the state's investor-owned utilities, including SDG&E,
to increase the renewable portion of their energy mix each year by at least 1% of total retail sales,
with a goal of 20% renewable generation by 2017. Renewable generation projects will compete
with each other to supply the ¡ODs, with the CPUC establishing a process to select the "least-
cost, best fit" projects. lfthe costs of new renewable power exceeds certain CPUC-established
benchmark prices, the above-benchmark costs will be paid from a limited pool of "public goods"
funds (which ratepayers also pay as a surcharge on all utility rates). Ratepayers will pay directly
for the costs of new renewables up to the benchmark price.
Unlike the two larger electric ¡ODs, SDG&E's resource portfolio today has little
renewable power. We understand that SDG&E has already signed a number of power purchase
contracts with new renewable projects, mostly wind fanns. According to a recent CEC report,'
even considering these recent purchases, SDG&E still will need to almost quadruple the amount
of renewable power that it expects to buy in 2004 in order to meet the RPS standard of 20%
renewable supplies by 2017. Thus, SDG&E will need to devote a significant portion of its
resource portfoJio to purchases from new renewables.
Navigant's forecast does not appear to consider SDG&E's required renewable purchases
separately /Tom its market purchases, although Navigant does model renewable contracts as a
potential source of supply for the possible MEU. Navigant assumes that new renewable
contracts will be priced at $3 per MWh above the cost of comparable, generic wholesale power
(Appendix C, page 65). Navigant based this premium on a study of "green ticket" prices for
renewable power reported by the Automated Power Exchange (APX).
9 CEC, "Renewable Resources Development Report" (November, 2003), at 6. This
report is available at www.energy.ca.gov/reports/2003-ll-24_500-03-080F.PDF.
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
6. Sempra-owned generation
Navigant completed its study for the City prior to SDG&E's announcements that, first, it
has negotiated a long-term power purchase agreement for the output ofCalpine's 510 MW Otay
Mesa power plant and, second, SDG&E plans to acquire the 500 MW Palomar project in
Escondido from its Sempra affiliate. SDG&E will operate Palomar as a utility-owned resource.
This acquisition of more than 1,000 MW of efficient, local, combined-cycle generation will
significantly reduce SDG&E's need to import power from markets outside of its service territory.
This new gas-fired generation will displace market purchases in SDG&E's generation
portfolio. Generally, Navigant's assumed cost of wholesale power, based on a market heat rate
of9,000 Btu per kWh and an O&M adder of $2 per MWh, is lower than the "all-in" costs of a
new combined cycle plant such as Otay Mesa or Palomar. If SDG&E proceeds to buy power at
cost from Palomar and I or Otay Mesa, SDG&E's generation costs may well be higher than
Navigant has assumed.
7, Market purchases for the residual net short
Navigant has assumed that SDG&E will purchase power at market prices for its "residual
net short" - the difference between its system demand and the power produced by the resources
that it owns or has under long-term contract (also known as "utility-retained generation" or
URG). In Navigant's model URG appears to include SDG&E's share of SONGS, QF power,
existing interutility contracts, and the DWR contracts allocated to SDG&E. We are uncertain
whether Navigant considered the purchase of renewable power under the RPS program. As
noted in Section m.B above, we concur with Navigant's forecast of wholesale power prices for
the market purchases that SDG&E will make to fill its net short requirements.
8. Resource Mix
We have reproduced Navigant's projection of the generation component ofSDG&E's
rates, using the SDG&E energy balance for 2006 - 2011 contained in the Navigant Consultant
Report. This shows SDG&E's future energy mix as a combination of SDG&E's share of
SONGS, QF power, the PGE interutility contract, SDG&E's allocated DWR contracts, and
market purchases for the residual net short. The consultant report also shows SDG&E's
expected amounts of direct access loads.
9, Average Generation Rates
Using the resource mix from the Consultant's Report, we have estimated SDG&E's
average generation rate for 2006 - 2011. We have used SONGS costs from the SDG&E cost-of-
service case, our own projection ofQF costs, PGE contract costs based on 2002 FERC Form I
-]6- Crossborder Energy
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
data, and the DWR contract costs that Navigant projected in Scenario 14 of the CPUC direct
access exit fee case (R. 02-01-0 II), which Navigant references on page 73 of Appendix c.W The
CPUC's D. 03-07-030 found this to be the "most reasonable" scenario for future exit fees.lJ We
have also assumed that the exit fee revenues based on Scenario 14 are used to reduce SDG&E's
generation rates for bundled customers. We priced the utility's residual net short purchases at
Navigant's assumed wholesale power costs (without a premium for new renewable purchases).
Under these assumptions, which we believe are reasonable, we were able to reproduce
Navigant's results (to within one percent) for the generation portion ofSDG&E's rates over the
period 2006 - 2011.12 In our opinion, this validates Navigant's projection of the generation
portion ofSDG&E's electric rates.
D. Non-Generation Rates
Navigant has taken a simple approach to projecting the non-generation portion of
SDG&E's rates. These include transmission, distribution, and public purpose program costs.
Navigant has assumed that these portions of SDG&E's rates will escalate at 1.3% per year from a
base of the existing June 2003 non-generation rates.
Navigant appears to assume that SDG&E's non-generation rates will continue to be set
under a perfonnance-based ratemaking (PBR) program. Since the mid-1990s, the CPUC has
used such programs to set the non-generation rates for the California energy utilities. Essentially,
a PBR program replaces the traditional biennial or triennial general rate case with a pre-set
fonnula that allows the utility to change its rates (or its allowed revenue requirement) every year
by an inflation factor less an assumed productivity rate. PBR programs are intended to provide
the utility with a strong incentive to operate efficiently, by allowing shareholders to keep a
significant share of the savings if the utility can reduce its costs below those allowed under the
PBR fonnula. The assumption that SDG&E will continue to operate under a PBR mechanism
10 We adjusted these DWR contract costs based on the difference between the gas price
forecast used in R. 02-01-011 and our own gas price forecast prepared for this report.
II We concur in this CPUC finding, which is consistent with the position that we took in
this case on behalf of the California Manufacturers & Technology Association.
12 Navigant does not provide a table showing its forecast for the generation portion of
SDG&E's rates. However, we were able to derive them by taking the difference between
Navigant's forecast of bundled SDG&E rates and its projection ofSDG&E's non-generation
rates shown in the Community Choice Aggregation pro formas.
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, -,-- '----',------------'-'-----'--
Navigant's SDG&E Rate Forecast FINAL REPORT
March 24. 2004
simplifies the forecasting of future non-generation rates, because one can use available inflation
forecasts and productivity projections.
However, it is important to recognize that, since the California energy crisis, the CPUC
has been moving away from the use ofPBR mechanisms. In fact, the Commission has required
all of the major energy utilities, including SDG&E, to file new general rate cases or cost-of-
service proceedings. It is unclear whether the CPUC intends to move back to standard rate cases
at regular intervals or simply to use the results of the new rate cases to set new base years for
renewed PBR mechanisms.
In the pending SDG&E cost-of-service case, the utility has proposed to return to the use
of a PBR mechanism with the results of the current case setting the base year rates. SDG&E has
also proposed an inflation index and a productivity factor of 0.52%. Navigant appears to have
derived its assumed escalation rate of 1.3% as the difference between an inflation forecast of
2.9% and the utility's currently adopted 1.6% productivity factor under its existing PBR
mechanism.
We note that Navigant has used this 1.3% escalation rate for all ofSDG&E's non-
generation costs, including transmission, distribution, and public purpose program costs, even
though SDG&E's PBR program applies only to the utility's distribution costs. Transmission
costs are now FERC-regulated and are set in FERC transmission rate cases. However, SDG&E's
distribution costs are much larger than its transmission or public purpose program costs, and it
does not appear unreasonable to apply the escalation rate for electric distribution to all three cost
categones.
1. Inflation rate
Navigant appears to assume a long-term inflation rate for electric distribution costs of
2.9%. Navigant told us that this figure is taken from SDG&E's cost-of-service testimony, which
shows both historical and forecasted inflation rates from 1997 - 2004. Our review of that data
could not verity the source for the 2.9% figure. The closest number appears to be SDG&E's
assumed inflation rate for 2004 - 3.1%. However, we note that the 3.1% inflation assumed for
2004 is high by recent historical standards. SDG&E's longer-term average inflation rate /Tom
1997 - 2004 is 2.2%; over this same period general inflation (the GDP implicit price deflator) has
risen by less than 2% per year, and long-term inflation forecasts going forward are now in the
2.0% range. Thus, we believe that Navigant's long-term inflation forecast is high by almost 1%.
2, Productivity assumptions
Navigant used the Commission's currently-authorized productivity adjustment of 1.62%
for SDG&E's electric distribution system. The Commission adopted this figure in D. 99-05-030.
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Navjgant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
SDG&E is proposing a much lower figure, 0.52%, in its pending cost-of-service case. This
figure is based on national electric utility productivity trends. Generally, however, the CPUC has
adopted productivity adjustments for PBR mechanisms that include a "stretch" factor above
industry productivity trends. These "stretch" factors are typically in the range of 0.5% to 1.5%.
As a result, Navigant's use of the current 1.62% productivity adjustment appears to include a
"stretch" factor of about 1.1 %. SDG&E argues in its cost-of-service case that productivity
improvements will be more difficult in the future, and thus the CPUC should no longer adopt
"stretch" factors. Nonetheless, given the continued strong growth of productivity in the U.S.
economy, we anticipate that the CPUC will continue to adopt "stretch" factors of 1.0% and
overall productivity factors of 1.5%.
3, Conclusion
With a long-term inflation forecast of 2.0% and a productivity factor of 1.5%, we expect
SDG&E's non-generation rates to increase by no more than 0.5%, significantly less than
Navigant's assumed 1.3%. Making this change in Navigant's forecast of SDG&E's future
electric rates should not change the results ofNavigant's Community Choice Aggregation (CCA)
scenarios, which assume that SDG&E continues to provide non-generation services such as
transmission and distribution. However, a lower forecast of SDG&E transmission and
distribution rates should decrease the economic benefits of the scenarios in which the City
provides these non-generation services (i.e. the Greenfield Development or full-fledged
municipal utility options).
E. Other Rate Elements
Navigant's forecast also includes several other rate elements. First, SDG&E is still
amortizing the electric procurement cost underoollection that it accumulated during the energy
crisis. This is known as the "AB 265 undercollection," after the legislation that required SDG&E
to freeze its rates during the crisis. Navigant expects SDG&E to complete the amortization of
this undercollection by the end of 2004. We have reviewed Navigant's assumptions, and agree
with this projection.
Second, SDG&E's rates now include the repayment of the bonds that were issued to
provide small ratepayers with a 10% rate reduction under the electric restructuring program.
These so-called "Fixed Transition Amounts" are expected to expire in 2007. As the amount of
these bonds is fixed and the repayment is relatively certain, we do not disagree with this forecast
element.
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Navigant's SDG&E Rate Forecast FINAL REPORT
March 24, 2004
IV. OTHER POSSIBLE FACTORS AFFECTING SDG&E'S RATES
There are several factors that could have a significant impact on a long-range SDG&E
rate forecast that Navigant did not consider explicitly. This section discusses these factors.
A, Changes in Cost Allocation among the Customer Classes
Navigant's forecast of non-generation rates is based on escalating the June 2003 non-
generation rate components for each of SDG&E's rate schedules. hnplicit in this method is the
assumption that the allocation of costs between the various customer classes will not change over
time. Obviously, it is difficult to forecast such changes. Such changes are less likely if there are
no obvious inequities in SDG&E's rate structure. As an example of such an inequity, we cite
Southern California Edison's current cost allocation, which now results in large conunercial rates
that are higher than residential and small commercial rates. Based on our experience in electric
rate design, we do not see any such obvious inequities in SDG&E's current rate structure.
We also note that the mix of electric customers in Chula Vista is very similar to the
overall mix in SDG&E's service territory, as shown in the table on page 8 of Section II of the
main Navigant study. As a result, SDG&E is unlikely to be able to use changes in its cost
allocation as a means to reduce the City's incentive to pursue a municipal utility. We conclude
that this similarity will minimize the impact of future cost allocation changes on the overall
economics of the City's pursuit of its own utility system.
B. Changes in Rate Design Methodology
Navigant's analysis seems to use class average electric rates. Class average rates are
influenced not only by the underlying cost allocation, but also by the rate design used to recover
costs. Rate design changes that shift costs between fixed monthly charges, demand charges, and
energy rates can change class average rates. As an example, Southern California Edison has
floated a proposal in the rate design phase of its ongoing general rate case to make a major shift
to recover more costs through fixed monthly charges. This proposal has met stiff resistance, and
Edison recently backed away from it. With no major shifts in SDG&E's rate design on the
horizon, it is our judgement that Navigant's use of class average rates is reasonable.
We conclude that Navigant made reasonable assumptions concerning cost allocation and
rate design on the SDG&E system. However, the City may need to re-evaluate the economics of
its MEV endeavors if SDG&E makes significant rate changes in the future.
-20- Crossborder Energy
Attachment A
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(No Cost Penalty to Serve EGs)
NPV 2002 2003 2004 2005 2006
Customer Accounts
Residential 62,500 64,925 67,349 69,774 72.199
Core Commercial 3,370 3,411 3,513 3,735 3,784
Noncere Commercial 20 20 21 22 22
Noncore Industrial 10 10 10 10 10
Electric Generation 1 1 1 1 1
Total 65,901 68,367 70.894 73,542 76,016
Gas Requirements (Mth)
Residential 20,600 21.293 21.977 22.655 23,395
Core Commercial 6,366 6,475 6,702 7.161 7,291
Noncore Commercial 5,000 5.086 5,264 5.625 5,727
Noncore Industrial 34.778 34.778 34,778 34.778 34,778
Subtotal RlC/I 66.744 67.632 68,721 70,219 71.191
Electric Generation 110.184 113,489 116,894 120,401 124,013
Total 176,928 181,121 185,615 190,620 195,204
% Increase 2.4% 2,5% 2,7% 2,4%
Estimated SDG&E Delivery Rates ($rrherm) (including SoCalGas charges)
Residential 0,394 0,429 0.436 0,443 0,451
Core Commercial 0,420 0,405 0.412 0.419 0.426
Noncore Commercial 0,078 0,088 0,089 0,091 0,092
Noncore Industrial 0,078 0,088 0,089 0,091 0,092
Electric Generation 0,019 0,027 0,028 0,028 0,029
change 1.7% 1.7% 1.7%
Estimated SDG&E Non-Gas Revenue ($000) (including SoCalGas charges)
Residential $8.112 $9.129 $9,580 $10,040 $10,541
Core Commercial $2.671 $2.625 $2,762 $3,000 $3.106
Noncere Commercial $388 $446 $469 $510 $528
Noncore Industrial $2,700 $3,050 $3.101 $3,153 $3,206
Subtotal RlCII $13,871 $15,250 $15.912 $16.703 $17,381
Average RlCII ($rrherm) 0.208 0.225 0.232 0.238 0.244
Eleclric Generation $2,093 $3,118 $3,265 $3,419 $3,580
Total $15,964 $18.368 $19,177 $20,122 $20,961
Averge ($rrherm) $0,090 $0,101 $0,103 $0,106 $0,107
Estimated Chula Vista Operatin9 Expenses (including SoCalGas charges with no cost penatty to serve EGs)
CV Delivery Cost to RlCII 0,152 0,157 0,161 0.166
CV Cost to Serve RIC/I ($000) $10.294 $10.774 $11,339 $11,841
Est Cost to Serve Power Plant ($rrh) 0,0010 0,0010 0,0011 0,0011
CV Cost to Serve PP ($000) $1.998 $113 $120 $128 $136
SoCalGas Wholesale Rate ($rrh) 0,018 0,018 0,018 0,0184
Est SDG&E Trans, Rate ($rrh) 0,023 0,023 0,024 0,024
Total Rate RICII SoCal & SDG&E ($rrh) 0,041 0,041 0,042 0,043
Total EG Rate SoCal & SDG&E ($rrh) 0,027 0,028 0,028 0,029
SoCaIGas¡SDG&E Cost to C.V. $5.867 $6,104 $6,369 $6.621
Capital Expense ($000) $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958
Total Expenses $17,650 $18,374 $19,212 $19.974
Total $rrherm 0,097 0,099 0,101 0,102
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $6.087 $718 $803 $910 $987
Lost Franchise Fee $7.244 $657 $681 $689 $709
Net BeneflU(Cost) ($1,1571 $61 $122 $221 $278
Discount Rate 9,73%
Page 1 014 Crossborder Energy
- ----------------------'
Attachment A
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(No Cost Penalty to Serve EGs)
2007 2008 2009 2010 2011 2012
Customer Accounts
Residential 74.624 76.643 78,663 80,683 81,248 81.813
Core Commercial 3,833 3,882 3,954 4,045 4.069 4.092
Noncore Commercial 23 23 23 24 24 24
Noncore Industrial 10 10 10 10 10 10
Electric Generation 1 1 1 1 1 1
Total 78,491 80,559 82.651 84.763 85,352 85,940
Gas Requirements (Mth)
Residential 24,132 24,786 25,439 26.092 26,275 26,457
Core Commercial 7,422 7,556 7,734 7.952 8,038 8.125
Noncore Commercial 5.830 5,935 6,075 6.246 6,314 6.382
Noncore Industrial 34,778 34,778 34,778 34,778 34.778 34,778
Subtotal RlC/I 72,162 73,055 74,026 75,068 75,405 75.742
Electric Generation 0 0 257,544 257,544 257,544 257.544
Total 72,162 73,055 331,570 332,612 332,949 333.286
% Increase -63.0% 1.2% 353.9% 0.3% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($/Therm)
Residential 0.458 0.466 0.473 0.481 0.489 0.497
Core Commercial 0.433 0.440 0.448 0.455 0.462 0.470
Noncore Commercial 0.094 0.095 0.097 0.098 0.100 0.102
Noncore Industrial 0.094 0.095 0.097 0.098 0.100 0.102
Eleciric Generation 0.029 0.030 0.030 0.031 0.031 0.032
change 0.5% 3.4% 1.1% 1.7% 1.6% 1.6%
Estimated SDG&E Non.Gas Revenue ($000)
Residential $11.054 $11,542 $12.043 $12,558 $12,850 $13.147
Core Commercial $3,214 $3,327 $3,462 $3,618 $3.716 $3.817
Noncore Commercial $546 $565 $588 $615 $632 $649
Noncore Industrial $3,259 $3,313 $3.368 $3,424 $3,479 $3.535
Subtotal RlC/I $18,073 $18,747 $19,461 $20,215 $20,677 $21.148
Average RlC/I ($/Therm) 0.250 0.257 0.263 0.269 0.274 0.279
Electric Generation $0 $0 $7.812 $7,942 $8,070 $8.200
Total $18,073 $18,747 $27,273 $28,157 $28.747 $29,348
Averge ($/Therm) $0.250 $0.257 $0.082 $0.085 $0.086 $0.088
Estimated Chula Vista Operating Expenses
C.v. Delivery Cost to RlC/I 0.171 0.176 0.182 0.187 0.193 0.199
C.v. Cost to Serve R/C/I ($000) $12.363 $12.891 $13,454 $14,053 $14,539 $15,042
Est Cost to Serve Power Plant ($/Th) 0.0011 0.0011 0.0012 0.0012 0.0013 0.0013
C.v. Cost to Serve PP ($000) $0 $0 $308 $317 $326 $336
SoCalGas Wholesale Rate ($/Th) 0.019 0.019 0.019 0.020 0.020 0.020
Est SDG&E Trans. Rate ($/Th) 0.025 0.025 0.025 0.026 0.026 0.027
Total Rate R/C/I SoCal & SDG&E ($/Th) 0.043 0.044 0.045 0.046 0.046 0.047
Total EG Rate SoCal & SDG&E ($/Th) 0.029 0.030 0.030 0.031 0.031 0.032
SoCaIGas/SDG&E Cost to C.V. $3,133 $3.225 $11,134 $11.367 $11,565 $11.768
Capital Expense ($000) $418 $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958 $958
Total Expenses $16,872 $17,492 $26.272 $27,113 $27,806 $28.522
Total $/Therm 0.234 0.239 0.079 0.082 0.084 0.086
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $1.201 $1.255 $1,001 $1,044 $941 $826
Lost Franchise Fee $650 $679 $858 $885 $905 $924
Net BenefiU(Cost) $551 $576 $143 $159 $36 ($98)
Discount Rate
Page20f4 Crossborder Energy
Attachment A
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(No Cost Penalty to Serve EGs)
2013 2014 2015 2016 2017 2018
Customer Accounts
Residential 82,378 82,944 83,509 84,074 84.640 85,205
Core Commercial 4,116 4,190 4,377 4.413 4.449 4.485
Noncore Commercial 24 25 26 26 26 27
Noncore Industrial 10 10 10 10 10 10
Electric Generation 1 1 1 1 1 1
Total 86,529 87.170 87,923 88.524 89,126 89.728
Gas Requirements (Mth)
Residential 26,640 26.823 27.006 27,189 27,371 27,554
Core Commercial 8,212 8.402 8.822 8,938 9,056 9,175
Noncore Commercial 6.450 6.600 6.930 7,021 7,113 7.207
Noncore Industrial 34,778 34,778 34.778 34,778 34,778 34,778
Subtotal RlC/I 76,080 76,603 77.536 77,926 78.318 78,714
Electric Generation 257,544 257,544 257.544 257,544 257,544 257,544
Total 333,624 334,147 335,080 335,470 335,862 336,258
% Increase 0.1% 0.2% 0.3% 0.1% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($/Therm)
Residential 0.505 0.513 0.521 0.530 0.538 0.547
Core Commercial 0.477 0.485 0.493 0.501 0.509 0.517
Noncore Commercial 0.103 0.105 0.107 0.108 0.110 0.112
Noncore Industrial 0.103 0.105 0.107 0.108 0.110 0.112
Electric Generation 0.032 0.033 0.033 0.034 0.034 0.035
change 1.6% 1.6% 1.6% 1.6% 1.6% 1.6%
Estimated SDG&E Non-Gas Revenue ($000)
Residential $13.451 $13,761 $14,078 $14,401 $14.730 $15,067
Core Commercial $3,920 $4,075 $4.348 $4.476 $4.607 $4,743
Noncore Commercial $666 $693 $739 $761 $783 $806
Noncore Industrial $3,592 $3,650 $3.709 $3,768 $3.829 $3,890
Subtotal RlC/I $21,629 $22,179 $22,874 $23.406 $23,949 $24.506
Average R/C/I ($/Therm) 0.284 0.290 0.295 0.300 0.306 0.311
Electric Generation $8.332 $8.466 $8,602 $8.740 $8,880 $9.023
Total $29,961 $30,645 $31,476 $32.146 $32,829 $33,529
Averge ($/Therm) $0.090 $0.092 $0.094 $0.096 $0.098 $0.100
Estimated Chula Vista Operating Expenses
C.v. Delivery Cost to RlC/I 0.205 0.211 0.217 0.224 0.230 0.237
C.V. Cost to Serve R/C/I ($000) $15,563 $16.140 $16,827 $17,418 $18.031 $18,666
Est. Cost to Serve Power Plant ($/Th) 0.0013 0.0014 0.0014 0.0015 0.0015 0.0016
C.V. Cost to Serve PP ($000) $346 $357 $367 $378 $390 $401
SoCalGas Wholesale Rate ($/Th) 0.021 0.021 0021 0.022 0.022 0.022
Est. SDG&E Trans. Rate ($/Th) 0.027 0.027 0.028 0.028 0.029 0.030
Total Rate RlC/I SoCal & SDG&E ($/Th) 0.048 0.049 0.049 0.050 0.051 0.052
Total EG Rate SoCal & SDG&E ($lTh) 0.032 0.033 0.033 0.034 0.034 0.035
SoCatGas/SDG&E Cost to C.V. $11,973 $12,191 $12,433 $12,652 $12.875 $13,103
Capital Expense ($000) $418 $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958 $958
Total Expenses $29.258 $30.064 $31.003 $31,824 $32,672 $33,546
Total $/Therm 0.088 0.090 0.093 0.095 0.097 0.100
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $703 $581 $473 $322 $157 ($17)
Lost Franchise Fee $938 $956 $978 $989 $1,002 $1,031
Net BenefiU(Cost) ($375) ($505) ($667) ($845) ($1.048)
Discount Rate
Page30f4 Crossborder Energy
Attachment A
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(No Cost Penalty to Serve EGs)
2019 2020 2021 2022 2023
Cuslomer Accounls
Residential 85,770 86.335 86,496 86,656 86,816
Core Commercial 4,521 4,556 4,599 4,642 4,685
Noncore Commercial 27 27 27 28 28
Noncore Industrial 10 10 10 10 10
Electric Generation 1 1 1 1 1
Total 90,329 90,929 91,133 91,337 91,540
Gas Requirements (Mth)
Residential 27,737 27,920 27,972 28,023 28,075
Core Commercial 9,295 9,414 9,550 9,687 9,827
Noncore Commercial 7,301 7,395 7,501 7,609 7,719
Noncore Industrial 34,778 34,778 34,778 34,778 34,778
Subtotal RIC/I 79,111 79,507 79,801 80,097 80,399
Electric Generation 257,544 257,544 257,544 257.544 257.544
Total 336,655 337,051 337,345 337,641 337.943
% Increase 0.1% 0.1% 0.1% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($ITherm)
Residential 0.556 0.564 0.574 0.583 0.592
Core Commercial 0.525 0.534 0.542 0.551 0.560
Noncore Commercial 0.114 0.115 0.117 0.119 0.121
Noncore Industrial 0.114 0.115 0.117 0.119 0.121
Electric Generation 0.036 0.036 0037 0.037 0.038
change 1.6% 1.6% 1.6% 1.6% 1.6%
Estimated SDG&E Non-Gas Revenue ($000)
Residential $15,410 $15,760 $16,042 $16.329 $16.621
Core Commercial $4,882 $5,024 $5,178 $5.336 $5,500
Noncore Commercial $830 $854 $880 $907 $935
Noncore Industrial $3,953 $4,016 $4,080 $4,146 $4,212
Subtotal RICII $25,075 $25,654 $26,180 $26,718 $27.268
Average RICII ($lTherm) 0.317 0.323 0.328 0.334 0.339
Electric Generation $9,167 $9,314 $9,463 $9,615 $9,769
Total $34,242 $34,968 $35,643 $36.333 $37.037
Averge ($ITherm) $0.102 $0.104 $0.106 $0.108 $0.110
Estimated Chula Vista Operating Expenses
C.V. Delivery Cost to RIC/I 0.244 0.252 0.259 0.267 0.275
C.v. Cost to Serve RICII ($000) $19,323 $20,002 $20,679 $21,378 $22.102
Est. Cost to Serve Power Plant ($lTh) 0.0016 0.0017 0.0017 0.0018 0.0018
C.V. Cost to Serve PP ($000) $413 $426 $438 $452 $465
SoCalGas Wholesale Rate ($lTh) 0.023 0.023 0.024 0.024 0.024
Est. SDG&E Trans. Rate ($lTh) 0.030 0.030 0.031 0.031 0.032
Total Rate RIC/I SoCal & SDG&E ($lTh) 0.053 0.054 0.054 0.055 0.056
Total EG Rate SoCal & SDG&E ($lTh) 0.036 0.036 0.037 0.037 0.Q38
SoCaIGas/SDG&E Cost to C.V. $13,333 $13,568 $13.801 $14.039 $14.280
Capital Expense ($000) $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958
Total Expenses $34,445 $35,372 $36.294 $37,245 $38,223
Total $lTherm 0.102 0.105 0.108 0.110 0.113
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost ($203) ($404) ($651) ($912) ($1.186)
Lost Franchise Fee $1,055 $1,078 $1,104 $1.133 $1.146
Net BenefiV(Cost) ($1.258) (51.482) (51,755) ($2045) ($2,332)
Discount Rate
Page 4 of 4 Crossborder Energy
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Attachment B
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(SDG&E System Bypass)
NPV 2002 2003 2004 2005 2006
Customer Accounts
Residential 62.500 64,925 67,349 69,774 72,199
Core Commercial 3,370 3,411 3,513 3,735 3,784
Noncme Commecclal 20 20 21 22 22
Noncore Industrial 10 10 10 10 10
Electric Generation 1 1 1 1 1
Total 65,901 68,367 70,894 73,542 76,016
Gas Requirements (Mth)
Residential 20,600 21,293 21,977 22,655 23,395
Core Commercial 6,366 6,475 6,702 7,161 7,291
Noncore Commercial 5,000 5,086 5,264 5,625 5,727
Noncore Industrial 34,778 34,778 34,778 34,778 34,778
Subtotal RICII 66,744 67,632 68,721 70,219 71,191
Electric Generation 110,184 113,489 116,894 120,401 124,013
Total 176,928 181,121 185,615 190,620 195,204
% Increase 2.4% 2,5% 2.7% 2.4%
Estimated SDG&E Delivery Rates ($fTherm) (Including SoCalGas charges)
Residential 0.394 0.429 0.436 0.443 0.451
Core Commercial 0.420 0.405 0.412 0,419 0.426
Noncore Commercial 0.078 0.088 0.089 0,091 0.092
Noncore industrial 0.078 0.088 0.089 0.091 0.092
Electric Generation 0.019 0,027 0.047 0.048 0.049
change 1.7% 1.7% 1.7%
Estimated SDG&E Non.Gas Revenue ($000) (including SoCalGas charges)
Residential $8,112 $9,129 $9,580 $10,040 $10.541
Core Commercial $2,671 $2,625 $2,762 $3,000 $3,106
Noncore Commercial $388 $446 $469 $510 $528
Noncore Industrial $2,700 $3,050 $3,101 $3.153 $3.206
Subtotal RICII $13,871 $15.250 $15,912 $16.703 $17,381
Average R/CII ($fTherm) 0.208 0.225 0.232 0.238 0.244
Eleclric Generalion $2,093 $3.118 $5,494 $5.753 $6.024
Total $15,964 $18.368 $21,406 $22,456 $23,405
Averge ($fTherm) $0.090 $0.101 $0,115 $0.118 $0.120
Estimated Chula Vista Operating Expenses (including charges to bypass SDG&E)
C.v. Delivery Cost to RICII 0.152 0.157 0.161 0.166
C.v. Cost to Serve RICII ($000) $10,294 $10.774 $11.339 $11,841
Est Cosllo Serve Power Planl ($fTh) 0.0010 0.0010 0.0011 0,0011
G.V. Cost to Serve PP ($000) $1,998 $113 $120 $128 $136
Bypass Transmission Rate ($fTh) 0.014 0.014 0.014 0.015
Bypass Cost to C.V. $2,554 $2,617 $2,733 $2,845
Capital Expense ($000) $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958
Total Expenses $14,337 $14,887 $15,576 $16.198
Total $lTherm 0.079 0.080 0,082 0.083
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $80,617 $4,031 $6,519 $6.881 $7.207
Lost Franchise Fee $7,244 $657 $681 $689 $709
Net BenefiV(Cosl) $73,373 $3,374 $5,838 $6.192 $6,498
Discount Rate 9.73%
Page 1 of4 Crossborder Energy
.-- ...__.._.
Attachment B
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(SDG&E System Bypass)
2007 2008 2009 2010 2011 2012
Customer Accounts
Residential 74,624 76.643 78,663 80,683 81,248 81.813
Core Commercial 3.833 3,882 3,954 4,045 4.069 4,092
Noncore Commercial 23 23 23 24 24 24
Noncore Industrial 10 10 10 10 10 10
Electric Generation 1 1 1 1 1 1
Total 78,491 80,559 82,651 84.763 85,352 85,940
Gas Requirements (Mth)
Residential 24,132 24,786 25,439 26,092 26,275 26,457
Core Commercial 7,422 7,556 7,734 7,952 8,038 8,125
Noncore Commercial 5,830 5,935 6,075 6,246 6,314 6,382
Noncore Industrial 34.778 34.778 34,778 34,778 34,778 34.778
Subtotal RlCIl 72.162 73,055 74,026 75,068 75,405 75,742
Electric Generation 0 0 257,544 257,544 257,544 257,544
Total 72.162 73,055 331,570 332,612 332,949 333,286
% Increase -63.0% 1.2% 353.9% 0.3% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($lThenn)
Residential 0.458 0.466 0.473 0.481 0.489 0.497
Core Commercial 0.433 0.440 0.448 0,455 0.462 0.470
Noncore Commercial 0.094 0.095 0.097 0.098 0.100 0.102
Noncore Industrial 0.094 0.095 0.097 0.098 0.100 0.102
Electric Generation 0.049 0,050 0.051 0.052 0.053 0,054
change 0.5% 3.4% 1.1% 1.7% 1.6% 1.6%
Estimated SDG&E Non.Gas Revenue ($000)
Residential $11,054 $11,542 $12,043 $12.558 $12.850 $13,147
Core Commercial $3.214 $3,327 $3,462 $3.618 $3,716 $3,817
Noncore Commercial $546 $565 $588 $615 $632 $649
Noncore Industrial $3,259 $3,313 $3.368 $3,424 $3,479 $3,535
Subtotal RlCII $18.073 $18,747 $19,461 $20.215 $20,677 $21,148
Average RlCII ($lThêrm) 0.250 0.257 0.263 0.269 0.274 0.279
Electric Generation $0 $0 $13,145 $13,364 $13,579 $13.798
Total $18,073 $18.747 $32,606 $33,579 $34,256 $34.946
Averge ($lTherm) $0.250 $0.257 $0.098 $0.101 $0.103 $0.105
Estimated Chula Vista Operating Expenses
C.v. Delivery Cost to RlCII 0.171 0.176 0.182 0.187 0.193 0.199
C.V. Cost to Serve RlG/I ($000) $12,363 $12,891 $13,454 $14.053 $14,539 $15,042
Est. Cost to Serve Power Plant ($lTh) 0.0011 0.0011 0.0012 0.0012 0.0013 0.0013
C.v. Cost to Serve PP ($000) $0 $0 $308 $317 $326 $336
Bypass Transmission Rate ($lTh) 0.015 0.015 0.015 0.016 0.016 0.016
Bypass Cost to C.V. $1.056 $1,106 $5.077 $5,178 $5,267 $5,357
Capital Expense ($000) $418 $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958 $958
Total Expenses $14.795 $15,373 $20,215 $20,924 $21,508 $22.111
Total $lTherm 0.205 0.210 0.061 0.063 0.065 0.066
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $3,276 $3,374 $12,391 $12,655 $12,749 $12.635
Lost Franchise Fee $650 $679 $858 $885 $905 $924
Net BenefiU(Gost) $2.62B $2,695 $11 ,533 $11,770 $11,844 $11,911
Discount Rate
Page 2 of 4 Crossborder Energy
.. -_._.._-~---------_.._.._---_._-----
Attachment B
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(SDG&E System Bypass)
2013 2014 2015 2016 2017 2018
Customer Accounts
Residential 82,378 82,944 83,509 84.074 84.640 85,205
Core Commercial 4,116 4,190 4,377 4.413 4.449 4.485
Noneore Commercial 24 25 26 26 26 27
Noncore Industrial 10 10 10 10 10 10
Electric Generation 1 1 1 1 1 1
Total 86,529 87,170 87,923 88.524 89.126 89,728
Gas Requirements (Mth)
Residential 26,640 26,823 27,006 27.189 27.371 27,554
Core Commercial 8,212 8.402 8.822 8.938 9.056 9.175
Noncore Commercial 6.450 6,600 6,930 7.021 7.113 7.207
Noncore Industrial 34,778 34,778 34.778 34.778 34.778 34,778
Subtotal RlCII 76.080 76,603 77.536 77,926 78.318 78,714
Electric Generation 257,544 257,544 257.544 257,544 257.544 257,544
Total 333,624 334,147 335.080 335,470 335.862 336.258
% Increase 0.1% 0.2% 0.3% 0.1% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($/Therm)
Residential 0.505 0.513 0.521 0,530 0.538 0,547
Core Commercial 0.477 0.485 0.493 0.501 0.509 0.517
Noncore Commercial 0.103 0.105 0.107 0,108 0.110 0,112
Noncore Industrial 0.103 0.105 0.107 0.108 0,110 0.112
Electric Generation 0.054 0.055 0.056 0.057 0,058 0.059
change 1.6% 1.6% 1.6% 1.6% 1.6% 1.6%
Estimated SDG&E Non-Gas Revenue ($000)
Residential $13,451 $13,761 $14,078 $14.401 $14.730 $15.067
Core Commercial $3.920 $4,075 $4,348 $4.476 $4,607 $4.743
Noncore Commercial $666 $693 $739 $761 $783 $806
Noncore Industrial $3,592 $3,650 $3.709 $3,768 $3,829 $3,890
Subtotal RlCII $21,629 $22,179 $22.874 $23,406 $23.949 $24.506
Average RICII ($/Therm) 0.284 0.290 0.295 0,300 0.306 0.311
Electric Generation $14,020 $14,246 $14.475 $14,707 $14.942 $15,183
Total $35,649 $36.425 $37.349 $38,113 $38.891 $39,689
Averge ($/Therm) $0,107 $0.109 $0.111 $0.114 $0.116 $0.118
Estimated Chula Vista Operating Expenses
C V. Delivery Cost to RlCII 0.205 0.211 0.217 0.224 0.230 0.237
C.V. Cost to Serve RICII ($000) $15,563 $16,140 $16.827 $17.418 $18.031 $18,666
Est Cost to Serve Power Plant ($/Th) 0.0013 0.0014 0.0014 0.0015 0.0015 0.0016
C.V. Cost to Serve PP ($000) $346 $357 $367 $378 $390 $401
Bypass Transmission Rate ($/Th) 0.016 0.017 0.017 0017 0.017 0.018
Bypass Cost to C.V. $5,449 $5,545 $5,650 $5,747 $5,846 $5.947
Capital Expense ($000) $418 $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958 $958
Total Expenses $22.734 $23.418 $24.220 $24.919 $25,643 $26,390
Total $fTherm 0.068 0.070 0.072 0.074 0.076 0.078
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $12.916 $13,007 $13.129 $13,194 $13,248 $13,299
Lost Franchise Fee $938 $956 $978 $989 $1,002 $1,031
Net BenefiU(Cost) $11.978 $12.051 $12,151 $12.205 $12.246 $12,268
Discount Rate
Page30f4 Crossborder Energy
--------- - .. -------------
Attachment 8
City of Chula Vista
Financial Pro Forma Analysis
Natural Gas Utility Option
(SDG&E System Bypass)
2019 2020 2021 2022 2023
Customer Accounts
Residential 85,770 86.335 86,496 86,656 86,816
Core Commercial 4,521 4,556 4,599 4,642 4,685
Noncore Commercial 27 27 27 28 28
Noncore Industrial 10 10 10 10 10
Electric Generation 1 1 1 1 1
Total 90.329 90,929 91,133 91,337 91,540
Gas Requirements (Mth)
Residential 27,737 27,920 27,972 28,023 28.075
Core Commercial 9.295 9,414 9,550 9,687 9.827
Noncore Commercial 7.301 7.395 7,501 7,609 7.719
Noncore Industrial 34.778 34,778 34.778 34,778 34.778
Subtotal RIC/I 79,111 79.507 79.801 80.097 80.399
Electric Generation 257.544 257,544 257.544 257.544 257.544
Total 336.655 337.051 337.345 337.641 337,943
% Increase 0.1% 0.1% 0.1% 0.1% 0.1%
Estimated SDG&E Delivery Rates ($/Therm)
Residential 0.556 0,564 0.574 0.583 0.592
Core Commercial 0.525 0,534 0.542 0.551 0.560
Noncore Commercial 0,114 0.115 0.117 0.119 0.121
Noncore Industrial 0.114 0.115 0.117 0.119 0.121
Electric Generation 0.060 0.061 0.062 0,063 0.064
change 1.6% 1.6% 1,6% 1.6% 1,6%
Estimated SDG&E Non-Gas Revenue ($000)
Residential $15,410 $15,760 $16,042 $16,329 $16,621
Core Commercial $4,882 $5,024 $5,178 $5,336 $5,500
Noncore Commercial $830 $854 $880 $907 $935
Noncore Industrial $3.953 $4,016 $4,080 $4,146 $4.212
Subtotal RICII $25,075 $25,654 $26,180 $26,718 $27,268
Average R/CII ($/Therm) 0.317 0.323 0.328 0.334 0.339
Electric Generation $15,425 $15,673 $15,923 $16,179 $16,438
Total $40,500 $41,327 $42,103 $42,897 $43,706
Averge ($/Therm) $0.120 $0.123 $0.125 $0.127 $0.129
Estimated Chuta Vista Operating Expenses
C.v. Delivery Cost to RICII 0.244 0.252 0.259 0.267 0.275
c.v. Cost to Serve R/C/I ($000) $19.323 $20,002 $20.679 $21,378 $22,102
Est. Cost to Serve Power Plant ($/Th) 0.0016 0.0017 0.0017 0.0018 0.0018
C.V. Cost to Serve PP ($000) $413 $426 $438 $452 $465
Bypass Transmission Rate ($/Th) 0.018 0.018 0.019 0.019 0.019
Bypass Cost to C.V. $6.049 $6,153 $6,257 $6,363 $6,471
Capital Expense ($000) $418 $418 $418 $418 $418
Capital Improvement Cost ($000) $958 $958 $958 $958 $958
Total Expenses $27.161 $27.957 $28,750 $29,569 $30,414
Total $/Therm 0.081 0,083 0.085 0.088 0.090
Estimated Benefit of Gas Utility
SDG&E Revenue minus CV Cost $13,339 $13.369 $13.353 $13,328 $13.292
Lost Franchise Fee $1,055 $1,078 $1,104 $1,133 $1.146
Net BenefiU(Cost) $12,284 $12,291 $12,249 $12,195 $12.146
Discount Rate
Page 4 of 4 Crossborder Energy
-----.----- .
Attachment 3
TABORS CARAMANIS & ASSOCIATES
Memo To: Elizabeth Hull. Deputy City Attorney,
City of Chula Vista
From: Frederick H. Pickel
ce: Willie Gaters
Date: May 6. 2004
Re: Electricity Aggregation & Power Acquisition
The purpose of this memo is to summarize my high level review of the
Community Choice Aggregation ("CCA") and wholesale power acquisition
components ("Generation Supply Strategy" and other power supply
acquisition alternatives) of the "Municipal Energy Utility Feasibility
Analysis Phase I Report" (October 10, 2003 and December 12, 2003
Drafts, or "MEU Draft").
In the context of this limited review related to CCA and the Generation
Supply Strategy, I believe that the City of Chula Vista should follow no
more than the least aggressive path, a "Low and Slow" approach.
1. This would be a low cost aggregation approach to an initially
limited customer group, with out-sourcing of administration to
qualified energy marketing organizations, similar to the approach
that has been successfully used in Texas and New England. This
is a lower initial cost approach than suggested in the CCA strategy
in the MEU study. The City can use this approach to learn about
the markets at a lower cost and risk than the suggested MEU Draft
approach. The City need not take title to the power or the power
generation assets.
2. The City should continue to participate in the development of
California's CCA rules, stressing an approach to build on low-
overhead successes in other states rather than inventing an
elaborate and likely infeasible California program from scratch.
The City should not move ahead with CCA until favorable CCA
rules are established.
3. The MEV draft did not fully address the risks in developing an
energy utility - Chula Vista should learn by doing in a limited risk
way rather than making large initial commitments. The
aggregation setup costs can be much lower than in the MEU draft.
4. Once the City is more familiar with the markets, if opportunities
arise, the City can expand the scope of its activities.
(O",'OR"" '0 Chmd, S",., C""b,';dg" M.\ ""1' (,'c"",';]04 w "'C'3I4"'"' T"',"COM
","""" R780A"b"", ¡"born "",d. ","', C"";,, "..,CA 9174(' 9"'79"4133 <AX 9,i"79"4H3
",'Sm,",M""¡¡ddA,,",,,. Im"..g"",.CA """" 1""F'79'" "" 3'3'9F"'"
~- ...----.----.---.,----.-..---' .-.
Page 2
Community Choice Aggregation for Electricity
First, the rules for CCA are not fully established in California. The main
uncertainty in developing such a program is the likely nature of any
California legislation or CPUC regulation, current and future. Other
states have successfully developed electricity purchasing aggregation
programs, but the most successful programs are focused on specific
market segments rather than full community programs.
Second, far lower initial implementation costs are possible than the $4.2
million estimated by the MEU Draft. TCA and its affiliates have worked
on the implementation of aggregation programs in Texas, Massachusetts,
and Maine. These aggregation programs have been targeted as state-
wide programs for non-profit or governmental entities only, rather than
whole community programs.
In our experience with aggregation programs elsewhere, the startup costs
are the external costs associated with professional services assisting in
the strategy and negotiation of enabling agreements and standard form
customer/ energy supplier contracts between the aggregation sponsor
and one or more companies in the energy marketing business. In this
"Co-op Purchasing" approach, the aggregation sponsor, like Chula Vista,
coordinates the relationship with the marketers, provides form master
agreements between the energy marketers and individual customers, and
helps manage disputes. The cost for the aggregation sponsor involves 2
to 4 permanent staff plus initial outside professional help of $300,000 to
$500,000.
With Co-op Purchasing, the aggregation sponsor does not take title to the
power, and the marketer retains responsibility for the power acquisition
to serve the customers. The City avoids the commodity risks associated
with electricity in this approach, but also may miss out on larger
potential savings associated with direct supply acquisition or generation
ownership. In managing a Co-op Purchasing type aggregation, the City
would gain familiarity with energy markets and with energy regulation.
At the other extreme, a CCA that has the sponsor take possession of the
power commodity, its management, and the wholesale and retail billing
processes can be very costly and is unlikely to be costs effective - the
costs could be far in excess of $4.2 million stated in the MEU draft. This
"do-it-all-yourself" approach requires the development of internal risk
management processes and billing systems with initial investment and
------ ----. --.--- - --
Page 3
on-going operating costs that at least as high as those summarized in the
MEU Draft, likely far higher.
The MEU Draft report does not explore aggregation alternatives in
sufficient breadth. The California rules are not fully defined, so Chula
Vista has the opportunity to shape the final format. There have been
successful aggregation programs developed in other states - and it is
possible to have a successful program without jumping into a full "do-it-
all-yourself' CCA with high initial investment costs and high on-going
annual operation costs along with a Generation Supply Strategy
involving direct electricity procurement contracts and/ or generation
asset purchases.
Co-op Purchasing MEU draft "Do-it-all-
("Texas / yourself' aggregation
Massachusetts Model" with direct supply
or out-sourcing contracts or generation
approach) acquisition
Setup cost $300,000 - $500,000 At least $4.2 million
once California rules
are in place
On-going cost 2 to 4 staff plus ad hoc Much higher, not
professional assistance directly available in
on key issues study
Net Benefits Modest benefits at low Larger projected
City risk benefit, but
substantial energy
market risk to City
Electricity Acquisition and "Generation Supply Strategy"
The Generation Supply Strategy approach in the MEU Draft is driven by
the "do-it-yourself' CCA approach and potential Greenfield
Developments. So, first, if Chula Vista decides to out-source aggregation
development, it may be possible to avoid direct involvement in electricity
acquisition - this avoids the risks but also reduces the potential benefits
Page 4
related to municipal ownership. This out-sourcing approach may also be
possible under a Greenfield strategy.
Second, the current electricity market is creating a difficult time for
generation asset owners. Natural gas prices are up beyond prior
expectations - and natural gas is the primary fuel for nearly all new
generation. Electricity prices have not gone up enough, so that
generation asset owners are in a pinch between slightly higher wholesale
electricity prices and much higher gas prices. A number of key
generation owners have financial troubles because of these factors. TCA
analyses done over the past 2 years indicate that this situation will not
be alleviated for 3 to 5 years or more, depending upon overall economic
growth and western hydropower conditions. However, the price of new
generation equipment for new generation projects and of troubled
generation assets for new projects or those under development have not
come down to a level where many purchases of assets are taking place.
This may create an opportunity for the City to obtain rights to electricity
supplies through creative agreements with existing generation or projects
that are in advanced development. For example, this might require
customized agreements on development controls, property taxes, and
their timing in return for a portion of the power supply. But this
approach also requires the simultaneous development of a CCA,
Greenfield, or Municipal Distribution operation that can use the power
and efficiently dispose of any excess power.
The MEU Draft report does not explore power acquisition alternatives in
sufficient breadth. First, it may be possible to out-source power
acquisition under the CCA or Greenfield. Second, specialize agreements
may be possible that might allow the City to obtain power at attractive
prices - but this analysis would have to be specific to the opportunity,
not a generic analysis like that presented in the report. Third, a MEU
strategy based on the direct purchase of power via contract or by the
acquisition of generation is very costly and risky.
Related Comments
The report does not stress the volatility of energy markets. The City
decision makers must be prepared for routine and sudden shifts in
electricity and gas prices and related regulatory schemes - but this
volatility does not mean that Chula Vista should not participate in these
markets. In addition, energy prices not only move suddenly, they usually
Page 5
move together. It is the gap between the prices of alternatives that
provides the benefit to the City and its constituents (such as between
Chula Vista supplied power and the prices offered by others). The City
can directly or indirectly manage these risks, but must be prepared for
the volatility and its active management.
The discussion would be improved by presentation of several scenarios
that encompass both the energy market and political uncertainties
related to the development of a municipal energy utility.
The MEU Draft appropriately proposes a phased Roll-Out Strategy. This
MEU Draft should stress this phased approach, for example, starting
small with a more limited implementation of a CCA or along with
Greenfield Developments on a case-by-case basis, with supply
acquisition out-sourced in a way where the City assumes little cost or
risk.
-
Public Copy
City Clerk's Office
-
Attachment 4
-
CITY OF CHULA VISTA
- MUNICIP AL ENERGY UTILITY
FEASIBILITY ANALYSIS
-
- .
- EXECUTIVE SUMMARY
- .
-
- Submitted Jointly by:
- DUNCAN, WEINBERG, GENZER & PEMBROKE, P.C.
McCARTHY & BERLIN, L.L.P
- AND
NA VIGANT CONSULTING
-
- *
-
-
March 19,2004
-
*
Printed on recycled paper
--
TABLE OF CONTENTS
TABLE OF CONTENTS
I. PURPOSE OF THE FEASIBILITY ANALYSIS.............................. I
II. EXISTING UTILITY FRANCHISE WITH SAN DIEGO GAS &
ELECTRIC COMPANY......................................................... 3
III. REGULATORY AND LEGISLATIVE ISSUES................................4
IV. OVERVIEW OF RECOMMENDATIONS..................................... 5
A. Options...................................................................... 5
B. Savings...................................................................... 6
V. CITY ENERGY CUSTOMERS, PROJECTED LOAD AND POWER
SUPPLY..............................................................................9
A. Swnmary.....................................................................9
B. Customer Base............................................................. 10
C. PowerSupply............................................................. 11
1. In-City Generation ......,............,""'" ............,..... 12
2. Distributed Generation............... ........... ......,... ...... 13
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION.. 15
A. Community Choice Aggregation (CCA)......... ..................... 15
1. Swnmary......................................................,.. 15
2, Customer Base...,........ ....................................... 15
3. Functional Elements...............,........."............... ... 16
4. Benefits and Risks................................................ 16
a, Benefits................................................,.. 16
b. Risks....................................................... 17
5. LegallRegulatory...... .........,.. .................................18
i
.,.,-""--" ,..
TABLE OF CONTENTS
a. Electric Aggregation..................... ............... 18
b. Gas Aggregation... ..................... ............... 19
6. FinancingOptions............................................... 20
7. Implementation Schedule and Timelines........... ......... 20
a. Implementation Schedule.............................. 20
-
(I) Track I Tasks.................................... 20
(2) Track 2 Tasks.................................... 22
b. ..Timelines................................................ 22
8. Recommendation......... ...........................,..... ...... 23
B. Greenfield Development......... ....................................... 24
1. Summary.......................................................... 24
2. .Customer Base................................................... 24
3. Functional Elements.............................................. 24
4. Benefits and Risks............................... ...""" .........25
a. Benefits................................................... 25
b. Risks...................................................... 26
5, Lega1/Reguiatory.................................................. 26
6. Financing Options............ ............ ................. .........26
7. Implementation Schedule and Timelines.....,......,.......... 27
a. Implementation Schedule... ........................... 27
b. Timelines................................................ 29
8. Recommendation................................................. 29
ii
TABLE OF CONTENTS
C. Combined Community Choice Aggregation /Greenfield
Development............................................................. 30
1. Summary.....................................................,.... 30
2. Customer Base............................................. ....... 30
3. Functional Elements.............................................. 30
4. Benefits and Risks................................................. 30
a. Benefits................................................... 30
b. .Risks..................................................... 30
5. LegallRegulatory... ..............,............. ...,.. ...... ...... 31
6. FinancingOptions.................................................31
7. Implementation Schedule and Timelines................ ...... 31
a. Implementation Schedule.................. ............ 31
b. .Timelines............................................,.. 31
8. Recommendation... ...... ...,.. ....., .......,..... ......... ...... 32
D. Municipal Distribution Utility........................................... 33
1. Summary.......................................................... 33
2. Customer Base........... .........,........... ......................33
3. Functional Elements.............................................. 33
4. Benefits........................."....,............,.................35
5. Risks,...........................................,...."...............37
6. LegallRegulatory......... ......................................... 38
a. Fonnation and Implementation Process............... 38
b. Exercise of the Power of Eminent Domain........... 39
7. FinancingOptions.................................................39
iii
TABLE OF CONTENTS
8. Implementation Schedule and Timelines...................... 39
a. Implementation Schedule.............................. 40
(I) Focused MDU Feasibility and
Implementation Plan Tasks... ............... 40
-
(2) Implementation Plan Tasks.................. 42
b. Timelines................................................ 43 -
9. Recommendation................................................. 44
E. Joint Powers Agency/Municipal Utility District..................... 46
VII. NATURAL GAS............................................. ..................... 47
VIII. CONCLUSIONS AND RECOMMENDATIONS........................... 49
A. Discussion and Comparison of Recommended Options............ 49
1. Community Choice Aggregation............,.....,..... ...... 49
a. Analysis....................................................49
b. Recommendation........................................ 49
2. Greenfield Development...... ...... ...... ...... ................ 50
a. .Analysis................................................ 50
b. Recommendation............... ...... ..... ........... ... 50
3. Combined CCAIGreenfield Development................... 51
a. Analysis................................................. 51
b. Recommendation.................................",... 51
4. Municipal Distribution Utility........................ ....,.... 52
a. Analysis....................................................52
b. Recommendation........................................ 53
iv
.--. ......---- .----------.
TABLE OF CONTENTS
5. Joint Powers Agency and Municipal Utility District
Options......................................................,... 53
a. Analysis....................................................53
b. Recommendation........................................ 54
B. Roll Out Strategy.......................................................... 54
I. CCA - Implementation Schedule...... ...... ........"" ...." 54
2. Greenfield - Implementation Schedule......... ...... ...... ... 56
3. Combined CCAlGreenfield - Implementation Schedule. .. 58
4. MDU - Implementation Schedule.............................. 58
Charts/Graphs
Chart: Summary of Savings Estimated for Each Option Ranked by NPV
of Savings /Tom 2006 through 2023.................. ....... ......... ......,..... 7
Graph: City ofChula Vista MEU Options Annual Cost Savings Versus
SDG&E Rates ($)................................................................. 8
Chart: 2002 Chula Vista Energy Use.................................................... 9
City Versus Regional Energy Usage..................................................... 10
Projected Chula Vista Customer Load...... .............................................. 11
CCA Implementation Schedule.............................................. ............. 55
Greenfield Implementation Schedule... ..................................... ............. 57
MDU - Implementation Schedule...................................................,...... 59
v
1. PURPOSE OF THE FEASIBILITY ANALYSIS
EXECUTIVE SUMMARY
I. PURPOSE OF THE FEASIBILITY ANALYSIS
On May 29, 2001, the City passed Resolution No. 2001-162 adopting the
City's Energy Strategy and Action Plan (City Energy Strategy). The City Energy
Strategy was based on the assessment of the City's energy management options that were
set forth in a Report prepared by MRW Associates. On June 5, 2001, the City adopted
Ordinance No. 2835 establishing the City as a municipal utility. An overview of the
City's Energy Strategy and other actions taken by the City to implement its Energy
Strategy are discussed in detail in the Introduction (Section I) of this feasibility analysis
(Report).
Based upon the impact of the California energy crisis, and in furtherance
of the City's Energy Strategy, the City of Chula Vista (City) retained the services of
Duncan, Weinberg, Genzer & Pembroke, P.c., McCarthy & Berlin, LLP., and Navigant
Consulting Inc., collectively the "Municipal Energy Utility (MEU) Study Team," to
perform a Municipal Energy Utility Feasibility Analysis for the City. The City requested
that the MEU Study Team perform a financial, legal, and technical feasibility analysis of
developing a municipal energy business.
Specifically, the MEU Study Team was directed to determine: (I)
whether it is desirable and economically feasible for the City to pursue the
implementation of an MEU; and (2) if so, to advise what form of MEU structure would
best meet the needs of the City.
The City further asked the MEU Study Team to analyze and discuss the
feasibility of developing a municipal energy business that would meet as many of the
following ?bjectives as possible:
(a) establish reliable electricity and natural gas supply at competitive
rates and maintain the highest level of customer service;
(b) identify a viable business model that benefits the City's time and
investment;
(c) pursue an environmental advantage for City residents, businesses
and the region;
(d) obtain a citywide distribution of MEU benefits;
(e) utilize the MEU as an economic development tool to retain and
attract businesses; and
(t) enhance Chula Vista's vision to continue as a vibrant community
in the region.
I
...... .--....
1. PURPOSE OF THE FEASIBILITY ANALYSIS
In this feasibility analysis, the MEV Study Team has provided
comprehensive answers to the questions posed by the City based upon the objectives set
forth by the City, important assumptions, and the analysis of a wealth of available data.
2
II. EXISTING UTILITY FRANCHISE WITH SAN
DIEGO GAS & ELECTRIC COMPANY
II. EXISTING UTILITY FRANCHISE WITH SAN DIEGO GAS &
ELECTRIC COMPANY
San Diego Gas & Electric Company (SDG&E) owns and operates both the
electric and gas distribution systems in the City of Chula Vista under fTanchises granted
by the Chula Vista City Council. The original twenty-five year /Tanchise, granted in
1972 to operate the electric distribution systems in Chula Vista, expired in 1997 and was
extended for a five-year period under Ordinance No. 2746, adopted in 1998. The original
/Tanchise to operate a gas distribution system in Chula Vista, also with a twenty-five year
tenu, expired in 1997 and was extended for a five year period pursuant to Ordinance No.
2747, adopted in 1998. Both the electric and gas /Tanchises expired, by their tenus, on
June 30, 2003.
Representatives of Chula Vista and SDG&E conducted negotiations with
respect to the renewal or extension of the electric and gas /Tanchises earlier this year. The
tenus of the proposals submitted by SDG&E for a fifty-five (55) year extension of the
/Tanchises were evaluated by the Chula Vista staff and rejected as unacceptable. Once
negotiations reached an impasse in late July 2003, the City and SDG&E attempted to
agree on a temporary extension of the /Tanchises to give the City more time to evaluate its
options. The City offered a 90-day extension of the /Tanchise agreements while SDG&E
offered to extend service under current tenus and conditions for a 45-day period. At this
writing, the tenu of the /Tanchises has not been agreed upon and the parties have
continued to perfonu under the tenus and conditions of current fTanchise agreements on a
month-to-month basis.
The current /Tanchise agreements have been an important element in the
conduct of this feasibility analysis inasmuch as the tenus, conditions and rates for gas and
electric service as provided in the current fTanchises, or rate schedules promulgated
thereunder, have provided the benchmark against which all of the MEU options have
been measured to detenuine the feasibility of each of the MEU options analyzed by the
MEU Study Team. In evaluating each of the MEV alternatives, the impact on /Tanchise
fee revenue received by the City under the current /Tanchise agreements has been
calculated and explicitly set forth as a cost of pursuing each MEU option. The MEU
Study Team's test for economic feasibility of any and all MEU options requires that
financial benefits of a particular option must exceed any foregone /Tanchise fee revenue
that would result /Tom the pursuit of the MEU option.
3
--_.----------------- __m___.__-----..
III. REGULATORY AND LEGISLATIVE ISSUES
III. REGULATORY AND LEGISLATIVE ISSUES
As part of this feasibility analysis, the City has directed that the MEU
Study Team provide an explanation of the legal and regulatory environment in which the
MEU would operate. The MEU Study Team has prepared a comprehensive analysis of
the state and federal laws, which are, or may be, applicable to any of the MEU options
identified and analyzed. The Regulatory and Legislative issues which the City will face
if it implements any of the MEU options are set forth in Appendix B.1 of the Report at
11-27.
4
- ------------.
IV. OVERVIEW OF RECOMMENDATIONS
IV. OVERVIEW OF RECOMMENDATIONS
A. Options
In preparing this Report, the MEU Study Team perfonned a thorough
analysis of the energy markets in California and, in particular, in the SDG&E service
territory and prepared a comparative analysis of the City's opportunities and options to
develop and implement the City's Energy Strategy and Action Plan. Following the
directives of the City's Council and Staff, the MEU Study Team developed a series of
conclusions and recommendations, which are summarized below. The MEU Study Team
has examined both the markets for electricity and gas and detennined the feasibility of
developing a Municipal Energy Utility which would provide both electric and gas
service.
For the reasons set forth in this Report and summarized below, the MEU
Study Team concluded that it is feasible for the City to develop and implement a
municipal electric utility on a phased basis. At the same time, however, the MEU Study
Team has concluded that, barring any substantial changes in SDG&E's gas rates, it is not
economically feasible for the City to undertake providing gas service to consumers within
the City within the study period. The options examined by the MEU Study Team are
discussed in Section III and evaluated in Section IV of the Report. The conclusions and
recommendations relative to these options are set forth below.
Based on its analysis, the MEU Study Team recommends that the City
embark on a course of action that includes the following elements:
(a) development of a Community Choice Aggregation (CCA) Program
with plans to become operational in 2006, including active
participation in ongoing CPUC proceeding's to develop
implementation costs, credits, rules and protocols.! A final
decision whether to implement the CCA program should be made
following [mal CPUC rulings on these issues;
(b) immediate development and implementation of City ownership of
a distribution system in the currently undeveloped portions of the
City (Greenfield Development);
(c) combine the CCA and Greenfield projects for administration by
the City's MEU;
(d) on a longer tenn basis, begin development of an electricity
Generation Supply Strategy which will include the ownership or
I The MEV Study Team recommends that the City continue its current participation in CPVC and
related regulatory proceedings in an attempt to affect the outcome of any CPVC decision that will
directly affect CCA cost-effectiveness and feasibility.
5
- --_._-~---- - ._---- - -.. .-------------.--------.--- --.-. --- - -------- -
IV. OVERVIEW OF RECOMMENDATIONS
otherwise gain entitlement to at least 130 MW of electric
generation capacity inside the City to optimize the benefits /Tom
the recommended programs;
(e) on an interim basis, develop commitments for power purchase
agreements to meet the immediate requirements of the CCA and
Greenfield projects;
(f) After several (three to four at a minimum) years of successful
CCAlGreenfield experience, consider acquiring ownership and
operation of the existing electric distribution system within the
City which is now owned and operated by SDG&E, and becoming
a full service municipal electric distribution utility (MDU);2 and
(g) barring any substantial change in SDG&E/SoCal Gas rates or in
the natural gas markets in California, the MEU Study Team
recommends that the City of Chula Vista not pursue providing
natural gas service to customers within the City. If an MDU is
established in the future, the City should reevaluate the potential
for providing natural gas at that time.
B. Savings
With a focus on the options enumerated above, and using conservative
assumptions, the MEU Study Team modeled potential savings for the City, measured
against current and projected SDG&E rates, yielding a net present value (NPV) of
between $21 and $122 million for the study period. These projected savings or benefits
will be available, at the City's discretion, to reduce utility rates to electric customers of
the City, ~o fund utility operations and expansion projects, or to fund other worthy public
purpose projects.
In preparing the financial pro fonna for each study option, the MEU Study
Team perfonned a thorough analysis including: (I) SDG&E's forecast rates; (2)
potential California Energy Crisis Cost Responsibility Surcharges (exit fees) lost
/Tanchise revenues, and lost property tax revenue; (3) energy or commodity costs
(including generation ownership, power purchase contracts, renewable energy contracts
and spot-market purchases); (4) California Independent System Operator (CAISO)
charges; and (5) operation and maintenance costs. Each of these items was factored into
the pro forma analysis, In this evaluation, the MEU Study Team assessed the cost and
benefits of each option based on two energy supply strategies. Under the first strategy,
the City would procure all of its energy requirements in the wholesale energy market by
executing power contracts with various power suppliers at fixed prices for medium and
2 In the event that the CPVC's fmal rules and regulations fail to provide the foundation for an
economically sound CCA project, the MEV Study Team recommends that the City accelerate
consideration of the MOV option.
6
------- ---..-
IV. OVERVIEW OF RECOMMENDATIONS
short terms (Contracts Supply Strategy). In the second strategy, it was assumed that the
City would install its own generating facilities or take an ownership position in a power
generation facility developed by another entity (Generation Supply Strategy). The
Generation Supply Strategy is based upon City ownership of 130 MW of new combined
cycle gas turbine power plant capacity. The financial pro forma analysis compares the
total costs of each option with the total costs of continuing to take retail utility service
from SDG&E. The start-up costs and capital costs identified for each MEU option are
amortized over thirty years and factored into the pro forma analyses to arrive at the figure
for cost savings in relation to SDG&E rates. Thus, the projected savings or benefits
shown are net of the amortized start-up costs.
Financial pro forma for all the study options or combinations are
summarized in the table below. The table shows the total savings over the 18-year study
period from 2006 through 2023 and the Net Present Value (NPV) of these savings over
the same time period.
Summary of Savings Estimated For Each Option Ranked By NPV of Savings From
2006 Through 2023
Rank Option Supply Nominal Savings NPV of Savings ($ Average
Strategy ($ Millions) Millions) Annual
Savings (%)
I CCA/Greenfield Generation 351 122 10%
2 MDU Generation 329 109 9%
3 CCA Generation 244 90 8%
4 CCA/Greenfield Contracts 170 52 4%
5 CCA Contracts 86 28 2%
6 Greenfield Contracts 89 21 10%
7 MDU Contracts 16 (t2) -1%
The above table considers the dollar cost and benefit of each of the MEU
options. Later in this Report, the MEU Study Team discusses the non-quantifiable risks
and benefits of each of the MEU options.
As shown on the chart below, the implementation of a Combined
CCA/Greenfield option, with a Generation Supply Strategy,3 will produce the maximum
savings for the City of approximately $14.9 million in 2006, increasing to $31.7 million
in 2023. The total NPV of the stream of annual savings is $122 million for the study
period. The chart shows further that the implementation of the second ranking option (in
terms of maximum savings), an MDU option, with Generation Supply Strategy, will
produce savings of $12.3 million in 2006, increasing to $28.7 million in 2023. The total
NPV of the stream of annual savings is $109 million for the study period.
Elements of the Generation Supply Strategy are discussed in Section V.C below at 11-13.
7
IV. OVERVIEW OF RECOMMENDATIONS
City 01 Chuia Vists MEU Options -
Annual Cost Savings Versus SOG&E Rstes ($)
",000,000
35,000,000
30,000,000 m
2S,OOO,DOO
2O,OOO,DOO
15,000,000 -
10,000,000
-
5,000,000
-
2008 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
""""CCAIG¡eenlieid . G",,""' -e-MOU . Gener.tion
-
Each of the MEV options, which were evaluated by the MEV Stndy Team,
is summarized in Section VI below, at 15-46, and detailed analysis of each option is --
provided in Sections ill and IV of the Report.
-
--.
-
8
'---'--
V. CITY ENERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
V, CITY ENERGY CUSTOMERS, PROJECTED LOAD AND POWER
SUPPLY
A, Summary
The chart below shows the City electric energy loads by customer sector
for 2002, that are consistent with the SDG&E system-wide average energy mix.
2002 Chula Vista Energy Use
Streetlights
1%
Residential
44%
Medium Commercial
27%
Small Commercial
8%
However, the City is experiencing significant development in ways that will change this
energy mix. Based on the City's general plan, growth is projected to occur in all
customer segments, but especially in the medium commercial customer sector. Such
growth, when it occurs, will improve the City's load profile, reduce the average costs to
serve the City's electric loads, and improve the City's attractiveness to energl suppliers.
The following table compares 2002 segment usage for the City and SDG&E contrasted
with forecast sector usage for Chula Vista in 2023.
4 SDG&E 2002 FERC Form-I, page 301, line 2, column d, system wide results.
9
V. CITY ENERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
City Versus Regional Energy Usage
(MWh)
Chula Vista SDG&E Chula Vista
2002 2002 2023
-
Residential 305,735 44% 6,266,000 44% 568,772 42%
Small Commercial 56,216 8% 1,710,025 12% 78,154 6%
Medium Commercial 193,534 27% 3,391,622 24% 439,170 33% -
Large Commercial 142,922 20% 2,725,159 19% 250,191 19%
Streetlights 6,627 0.9% 44,442 0.3% 8,745 0.7%
Total 705,034 100% 14,137,248 1,345,032 --.
100% 100%
The City has been, and will continue to be, subject to strong growth in all -
sectors. However redevelopment and new development are forecast to have the greatest
impact in the medium sized commercial end-use consumer sector. In the next twenty
years the City will experience growth in its overall energy requirements by more than 90 -
percent. As described in Section IV.F.3.d(l) of the Report at 120-21, a municipal
distribution utility, comprised of the number of the City of Chula Vista electricity
consumers projected for 2006 (recommended MEU implementation date), would be the
II th largest out of California's 48 electric utilities based on customer count, and the 20th
largest based on energy sales.
B. Customer Base
The MEU Study Team estimates that, in 2004, the City will have
approximately 73,000 electric service customers (excluding the City's street lighting
service accounts). The City's annual load factor (the ratio of peak annual demand to the
average annual demand) is approximately 65 percent, which is high compared to other -
California cities. The City's higher load factor would allow the MEU to function more
efficiently and economically compared to the majority of other California cities.
Residential electric load can be significantly affected by ambient
temperatures and consumer use of air conditioning. However, Chula Vista's relatively
mild climate and reduced cooling load has a significant impact on residential load shapes
and a direct bearing on the cost to serve the City's electric load. Generally, Chula Vista's
residential loads are more economic to serve than other typical California communities,
more attractive to generation suppliers, and render more types of generation projects cost-
effective.
Long-term electric load forecasts for the City have been modeled for two
primary areas: (i) existing and planned development in areas currently served by
SDG&E's distribution infrastructure; and (ii) areas being developed in which SDG&E
10
V. CITY ENERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
has not built distribution inftastructure and where the City may decide to build and
operate distribution infrastructure (Greenfield development).
The MEU Study Team forecasts that, over the study period, there will be
an increase of approximately 22,000 customers, including growth in the current SDG&E
service territory and in the Greenfield areas, with an annual conswnption growth of
approximately 600,000 MWh, and a peak load growth of approximately 100 MW. This
represents a customer increase of 29 percent and an energy increase of over 80 percent.
More than half of the increased regional energy conswnption results from planned
commercial development. Due to this trend, the average, per customer energy
conswnption increases by more than 36 percent (excludes street lighting accounts) during
the study period.
Projected Chula Vista Customer Load
Customers Energy (MWh)
2004 2023 (%) 2004 2023 (%)
Residential 69.440 89,510 29% 329.719 568.772 73%
Commercial <20 kW 3.203 4,272 33% 57.594 78.154 36%
Commercial 20-500 kW 340 708 106% 198.276 439.170 121%
Commercial 500 kW + 13 22 71% 146,424 250.191 71%
Total 72.996 94.513 29% 732.013 1.336.287 83%
C. Power Supply
In providing electric power to serve the City's customer base under any of
the study options, the City has two basic choices: purchasing its electric power supply
requirements /Tom other utilities or generators participating in the California energy
market (Contract Supply Strategy); or developing generation resources by constructing
generation or participating with a generation developer and taking an equity interest in
local generation (Generation Supply Strategy).
A key finding of this feasibility analysis, under any of the MEU structures
analyzed, is that there is significant benefit to the City in electric generation ownership or
ownership-like rights. Furtbennore, the City finds itself in unique circwnstances
compared to other cities in the region due to the confluence of natural gas and electric
transmission facilities, and the location of the South Bay Power Plant (South Bay), and
the location of the proposed Otay Mesa Power Plant (Otay Mesa). The City is
geographically at the center of a significant portion of the energy facilities required to
support the San Diego region. The MEU Study Team recommends the City develop in-
City generation as the centerpiece of its MEU electric supply strategy. Our
recommendation is not that the City should seek to develop a generation resource on its
own; rather the MEU Study Team recommends that the City look to jointly develop
and/or pursue a partial ownership with a developer in a larger base load generating unit.
II
------- - ------------------,---,--.__. - . ------- - ----------
V. CITY ENERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
1. In-City Generation
The Generation Supply Strategy, with in-City generation, provides the
maximum opportunity for electricity cost savings achieved through the implementation of
an MEU. Associated savings are positive in every year for both the CCA and MDU
options. The combined CCAlGreenfield option with a Generation Supply Strategy offers
the greatest benefits of all the options.
Ownership of generation would offer the City several advantages relative
to procuring electricity through power purchase contracts (Contracts Supply Strategy).
Among the benefits associated with participation in generation projects are:
. Lower electricity costs due to the City's retention of generation operating
margms;
. The ability to leverage partial ownership to locate projects within the City and
receive /Tanchise fee revenues and local taxes; and
. Reduction in CAISO transmission charges, CAISO administrative charges, and
protection against charges related to transmission system congestion.
The MEU Study Team modeled generation options for the City using
operating and cost parameters of a new combined cycle gas turbine operating as a base
load plant. These parameters include the unit's heat rate, capacity cost, variable O&M
costs, availability factor, hours of planned operation, and the year the resource becomes
operational. Sales of any excess production beyond what is needed to serve the City's
load would be sold into the market. The price for excess sales reflects a 25% discount
relative to the prevailing peak or off-peak price to reflect the probability that excess sales
will occur in the lowest priced hours of the on- or off-peak periods.
The following assumptions were used in the calculation of generation
costs:
Capacity: 130MW
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh
Capacity Factor: 90%
Variable O&M: $2 Per MWh
Excess Sales: 75% of Market Price
There are presently at least two local generation options, which may be
available to the City with respect to obtaining generation located within or near the City's
boundaries:
(I) Otay Mesa: The Otay Mesa Generating Project (Otay Mesa) will
be a 510 MW, natural gas-fired combined cycle power plant located in the Otay Mesa
area in western San Diego County. Calpine Energy Services, LP (Calpine) is the project
12
oooo .. --..-oo----- - .. . ---oo-oo--.oo.oo---oo----.--.-
V. CITY ENERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
owner. The 15-acre site is about 15 miles southeast of San Diego, California, and about
1.5 miles north of the United States/Mexico border. SDG&E has recently announced
plans to purchase most or all of the capacity /Tom Calpine's Otay Mesa plant. If these
plans are implemented, this option would not be available to the City. If SDG&E's
proposal is not finally approved and implemented, the City should examine this option, as
the MEU Study Team believes that there is still an opportunity to discuss potential
teaming arrangements with Calpine,
Under current plans, a new 230-kV switchyard at the site is proposed.
There are plans to build a O.l-mile connection to SDG&E's existing 230-kV Miguel-
Tijuana transmission line that passes near the eastern boundary of the Otay Mesa site. A
new two-mile natural gas pipeline will be built by SDG&E to provide fuel for the project.
Originally scheduled for completion in the summer of 2002, the construction schedule
now calls for its completion by summer 2005. Currently the project is reported to be five
percent complete.
(2) South Bay Power Plant Repower (SBPP): The California State
Lands Commission approved the San Diego Unified Port District's (Port District or Port)
expenditure of $110 million in public trust funds to acquire the SBPP /Tom SDG&E on
January 29, 1999. The existing SBPP consists of four natural gas-fired conventional
boiler units and one 14 MW combustion turbine.
Duke Energy North America's (Duke) 10-year lease with the Port District
to operate the SBPP went into effect in April 1999. As part of its lease agreement with
the Port District, Duke must, subject to certain conditions, dismantle and relocate the
existing plant by 2009. According to the lease agreement, Duke must identify a specific
relocation site no later than June 2006 and publicize its site selection as part of an
application to the California Energy Commission (CEC) for permits to site the new plant.
Currently, the future of Calpine's Otay Mesa project and the siting of a
new South Bay Power Plant remain unknown, The MEU Study Team's analysis indicates
that the City is uniquely located to allow the City to potentially host either or both of
these generation projects.
2. Distributed Generation
In addition to the evaluation of the Generation Supply Strategy, the MEU
Study Team also evaluated the feasibility of acquiring or building small distributed
generation units within the City to serve the customers of the City's MEU as a start-up
strategy. With respect to this option, the MEU Study Team has concluded that there are
no generation projects of sufficient size now operating within the City to support the
development of an MEU. The MEU Study Team has also concluded that the
development of small distributed generation projects is not economically feasible as a
start-up measure in implementing an MEU.
13
".'_"'_00..-__0
V. CITY F"\fERGY CUSTOMERS, PROJECTED
LOAD AND POWER SUPPLY
Moreover, until the City successfully develops its Greenfield projects or
fonns an MDU and acquires the electric distribution system of SDG&E, it would have no
means of delivering power from small City generation facilities to consumer elec"'ic
loads (load), Without a distribution system, it would not be possible for the City 0
obtain delivery of power under the state's direct access laws and regulations and the
Federal open access laws and regulations which apply to direct transmission access,
except for the CCA-only option. Furthennore, the concept of developing distributed
generation at selected sites around the City (e.g., main campus) would not provide a City-
wide benefit and would offer limited savings. As noted above (see Section L(d)), the
MEU Study Team was asked by the City to analyze feasible municipal energy businesses
with the objective of "city wide distribution ofMEU benefits."
At such time as the City develops a Generation Supply Strategy and has,
through ownership or construction, a means of delivering power /Tom local distributed
generation projects to load, the MEU Study Team recommends that the City explore the
development oflocal distributed generation projects to augment the City's power supply.
14
- -- .---------_u -~------
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
The MEU Study Team has examined all MEU structures, which are
presently authorized under California law (or the California Constitution) and has
identified five structures that would be suitable and provide a legal basis for Chula
Vista's entry into the utility business, These include:
a) Community choice aggregation for both electricity and natural gas (CCA);
b) "Greenfield municipalization" development (Greenfield);
c) Municipalization under a city electric utility department fonnat, eventually
leading to a Municipal Distribution Utility (MDU) system;
d) Participation in a joint powers agency (JPA); and
e) Municipalization under a Municipal Utility District fonnat (MUD).
Each of these options is discussed in Section III of the Report and
evaluated in Section IV of the Report.
A. Community Choice Aggregation (CCA)
1. Summary
As discussed in the Report, Section III B.I at 25 and Section IV.C at 39,
the City of Chula Vista can elect to serve as a community load aggregator for electric
service within the City. A load aggregator is an entity that procures electric energy
and/or natural gas for residents and businesses within a community, Under this option,
the City would not own the electric or gas distribution system within the City. Rather, it
would own or procure electric power and/or natural gas, either through ownership of
resources, market purchases, or through a partner on behalf of the customers that choose
to aggregate their load. SDG&E would then be required to deliver the electric energy
and/or natural gas to the end-use customer across its transmission and distribution
facilities.
2. Customer Base
The customer base for the electric CCA option is potentially all electric
customers in the City. However, customers have the option to "opt-out" of the CCA
program and continue to receive their electric service /Tom SDG&E. For the purposes of
this feasibility analysis, the MEU Study Team has assumed that all potential customers
within the City would participate and that none would elect to "opt out." To the extent
that some potential customers do "opt out" of the CCA program, the benefits to
remaining customers would be proportionately diminished. The customer base for the
gas aggregation option includes all residential and small commercial customers in the
City. Certain industrial customers that use less than 250,000 thenns per year can also
become a part of the customer base.
15
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
3. Functional Elements
The MEU Study Team evaluated two primary supply strategies for the
City to serve the electric loads of the MEV customers: I) a Generation Supply Strategy
that uses city owned generation resources for base load requirements; and 2) a Contracts
Supply Strategy that uses long term power purchase contracts for base load requirements.
The Generation Supply Strategy is based on City ownership of 130 MW of new
combined cycle gas turbine power plant capacity located within the City or by acquiring
an equity interest or entitlement to 130 MW of a plant owned by a third party. The
Contracts Supply Strategy is based on the City entering into long and short-term fixed
price power supply contracts to meet the majority of the MEV's load requirements.
The MEU Study Team evaluated a number of supply portfolios to
optimally serve the load requirements of the City. A typical supply portfolio would
utilize generation owned by the City or long-term contracts for the majority of projected
base load requirements. These long-term resources would be supplemented with short-
term contracts covering the additional seasonal load requirements of the portfolio,
typically in the third quarter of each year. Spot market purchases and sales are used to
fill the residual net short load requirements.
The City would not need to invest in any transmission or distribution
infrastructure, i.e., substations, lines or meters, in order to serve City residents under this
option. Although final CCA Rules and Regulations have not been promulgated, it is
assumed that the City's CCA customers would pay SDG&E the retail rate for non-
generation charges (e.g., transmission and distribution). SDG&E would provide a credit
on the bill to remove its costs related to generation and procurement of electricity that
would be procured by the City. The bill credit that SDG&E will provide for generation-
related charges is assumed to be the entire generation rate net of the applicable exit fees.
SDG&E would continue to perform metering and billing services for end use customers,
the costs of which are embedded in existing retail distribution rates.
4. Benefits and Risks
a. Benefits
The 18-year NPV of savings or benefits to the City and its residents,
measured against current and projected SDG&E rates, is projected to be $28 million if
power supply is obtained from the competitive wholesale market in the form of contracts
or an average annual savings of 2%. If the power is supplied /Tom City-owned
generation, the 18-year savings are projected to be $90 million with average annual
savings or benefits of 8%. Capital costs for the Generation Supply Strategy are estimated
to be $78 million.
16
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
The major benefit available through the electric aggregation option is that
the City could begin procuring electric energy and supplying it to retail customers
without the need to purchase the SDG&E electric distribution system.
By electing to implement a CCA program, Chula Vista could begin to
provide utility services to customers within the City as an interim step without
developing a utility in/Tastructure that would require the enormous investment necessary
to acquire and operate a utility distribution system.
b. Risks
On the electric utility side, CCA is governed by the Community Choice
Aggregation legislation (AB 117, Chapter 838, September 24, 2002\ and the CPUC's
corresponding proceeding, Rulemaking 03-10-003 (R.03-10-003). If the City elects to
pursue the CCA option, the CPUC must confirm or approve the implementation plan
before final steps to implementation can occur. Pursuant to R03-10-003, the CPUC is to
determine the implementation requirements for a CCA, including the level of any
applicable cost responsibility surcharges, IOU administrative charges, and other costs and
restrictions that may be developed. As discussed further in Section 5 below at 18-19 and
in Section IV.D.4 of the Report at 57, the parameters of the CPUC's proceeding will
dictate the rules governing CCA programs. On November 26, 2003, the assigned
Administrative Law Judge in R.03-10-003 issued a ruling bifurcating the proceeding into
two phases. The first phase, in which hearings were held in February 2004, addressed
many of the cost related issues. Administrative and ministerial matters will be the subject
of the second phase of the proceeding
The MEU Study Team is advised that the City is a party to R03-10-003
and is taking an active role to ensure that the CPUC's CCA rules and regulations are just
and reasonable and consistent with the City's energy development objectives. The MEU
Study Team recommends that the City continue to take an active interest in ongoing
CPUC proceedings to establish the costs, credit rules and protocols that will eventually
determine the cost effectiveness and feasibility of the CCA program.
The primary risks inherent in the CCA option are:
The cost responsibility surcharges and transaction fees imposed by the
CPUC could make the program uneconomical. Especially problematic
would be unanticipated increases in these costs after the CCA program
has begun. Such cost increases could impose fmancial hardship on the
City or force CCA rates higher than the comparable SDG&E rates.
, AB 117 became effective January I, 2003 amends Sections 218.3, 366, 394, and 394.25 of the
Public Utilities Code and adds Sections 331.1, 366.2, and 381.1 to the same Code.
17
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
The City could improperly hedge its exposure to electricity and/or -
natural gas price volatility and adverse price movements could impose
severe financial hardship on the City or its customers.
-
The City could fail to properly secure its customer base, making debt
financing via the capital markets impossible to obtain and exposing the
City to stranded costs if customers opt out of the CCA program.
The City's energy suppliers could default on supply contracts (credit
risk) at times when energy spot markets are high, forcing the City to -,
purchase energy at excessively high prices.
On the natural gas side, the biggest impediment to a successful -
implementation would appear to be the slim margins on the actual procurement of the
natural gas commodity. Typically, existing natural gas Local Distribution Companies
(LDCs) earn most of their return /Tom their transmission and distribution assets, not the
actual commodity itself, which is usually priced at cost with a minor markup for
brokerage services. As discussed in Section VII below at 47-48 and in Section IV.H of
the Report at 140-54, the MEU Study Team has made an analysis of the feasibility of
providing gas service to customers within the City and has concluded that it is not
economically feasible to attempt to provide gas as an aggregator or provide gas
transmission and distribution service by acquiring the gas distribution system of SDG&E.
This option should be revisited if there are dramatic changes in SDG&E's gas rates.
5. LegallRegulatory
a. Electric Aggregation
While AB 117 does provide a statutory basis for Community Aggregation
Projects, the CPUC has not yet developed and implemented final rules for the
development of such programs. On September 4, 2003, the CPUC issued an order
instituting a rulemaking or "OIR" (Rulemaking 03-09-007) in order to develop the
guidelines for community aggregation programs, as it was directed to do under AB 117.
On October 2, 2003, the CPUC reissued the rulemaking under Docket No. R.03-10-003,
and an initial pre-hearing conference and a workshop have been held. The City, as noted
above, is a party to and active in, these proceedings.
The City could become a Community Choice Aggregator for electric
utility generation by developing an implementation plan, and then having this plan
approved by the CPUC pursuant to the rules and protocols to be adopted in R.03-10-003.
AB 117 (2002 Migden - Chapter 838, Statutes of 2002) offers flexibility in that it
provides for an "opt out" program rather than an "opt in" program. This would allow the
City to sign up customers willing to switch /Tom SDG&E generation service to City
service without the necessity of developing an active marketing effort to lure customers.
Instead, the City would merely need to notify customers of the impending community
18
----- ----------------------------- ------ ---------
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
choice aggregation program. Any customers that do not want to participate in the
program would be required to notify the City of their election within a specified amount
of time.
AB 117 also requires full cooperation by the host investor owned utility
(SDG&E) in any CCA program implemented by the City. In this regard, SDG&E is
required to provide necessary load information and other important data to Chula Vista,
and continue to provide transmission, distribution, metering, meter reading, billing and
other essential customer services.
An additional benefit of becoming a Community Choice Aggregator may
be for Chula Vista to administer the public goods charges collected /Tom electric
customers in the program. In addition to authorizing CCA programs, AB 117 also
requires the CPUC to determine the policies and procedures by which any party,
including a CCA, may apply to the CPUC to administer cost-effective energy efficiency
and conservation programs. The Commission issued a decision in July 2003 to set up this
program. Like all other electric users in the state, those that are served by a CCA will
still be required to pay the state mandated public goods charge. However, in lieu of
having these funds administered by SDG&E for use on any qualified programs within the
IOU's entire service area, Chula Vista could apply to the CPUC for the authority to
administer these funds and utilize 100% of the proceeds locally. Decision 03-07-034
(D.03-07-034) authorizes CCAs seeking energy efficiency program funding authorization
to do so, applying the existing procedures, schedules, selection criteria, and evaluation,
measurement and verification requirements already developed by the CPUC.
Furthermore, in order to facilitate the CCA's ability to administer the energy efficiency
program funds, 0.03-07-034 directs the IOUs to provide certain information and data to
the CCAs that would allow them to develop and implement local energy resource plans
and programs.
b. Gas Aggregation
For natural gas load aggregation, the State of California currently has laws
and procedures in place for "core" aggregation opportunities. Core aggregation has been
allowed since the early 1990's and permits a municipal agency to petition the current
natural gas energy provider and take over responsibility for the provision of natural gas
commodity services. This is known as the Core Aggregation Transportation (CAT)
program, and requires a minimum usage by customers that together purchase and
consume 120,000 therms of natural gas per year. Core customers are those that use less
than 250,000 therms a year and include all residential customers as well as those small
commercial and industrial customers using under the core limit threshold. Non-core
customers (large commercial and industrial customers using over 250,000 therms per
year) are already required to solicit their own natural gas procurement. As discussed in
Section VII below at 47-48 and in Section IV.H of the Report at 140-54, the MEU Study
Team has determined that it is not economically feasible for the City to enter into the gas
distribution business, including engaging in gas load aggregation, at this time. This
19
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EV ALUA nON
CCA
option should be reevaluated in the event that SDG&E succeeds in raising its rates for gas
service.
6. Financing Options
The City would have a variety of financing mechanisms available to
finance its CCA project depending upon the specific asset and/or activity. Financing --
techniques might include the following:
- General Obligation Bonds -
- Limited Obligation Bonds
- Special Assessment
-
- Certificates of Participation
- Revenue Bonds
- Commercial Paper
The MEU Study Team believes that tax-exempt debt financing should
generally be applicable to finance CCA capital projects.
In Appendix C, Section IV.A, at 126-27, the MEU Study Team has
provided an overview and comparative analysis of each type of financing vehicle that is
available to the City.
7. Implementation Schedule and TimeJines
It is estimated that it would take between one and two years for full
implementation of this option, depending largely upon when the rules and regulations for -
the program are approved and implemented by the CPUC. The major and critical steps
necessary to implement a CCA program are set forth below:
a. Implementation Schedule
The MEU Study Team recommends a two-track approach to implement a
CCA project. The following outlines the critical path elements for each track of work:
(1) Track 1 Tasks
1.1 - Project Initiation - Orientation Sessions for Elected Officials and Staff
1.2 - Base Case Feasibility Studies
- Load Forecasts
- Cost-of-Service Analyses
1.3 - Regulatory Engagement-A
20
VI. MEV STRUCTURAL OPTIONS -
OVERVIEW AND EV ALVATION
CCA
Participation in CPUC CCA proceedings and workshops for the
development of costs, credit rules and protocols; use base case feasibility
studies perfonned under 1.2 above as the basis to demonstrate the impacts
of proposed decisions.
1.4 - Track I Report
Update base case feasibility study with final CPVC adopted costs, credit
rules and protocols; evaluate results and make threshold decision whether
or not to proceed with implementation.
1.5 - Prepare CPUC Implementation Plan Filing
- Develop program structure, organization, operations plans and
funding
- Perfonn Rate Design (cost allocation methodology and disclosure)
- Document participant rights and responsibilities
- Finalize energy supply resource portfolio
- Adopt Implementation Plan in a public hearing6
- Pass City Ordinance to implement CCA as defined in the
Implementation Plan7
- File the Implementation Plan with the CPUC
Where third-party suppliers are indicated, evaluate and document their
financial, technical and operational capabilities. If the City intends to
pursue an equity position in generation resources document the same
capabilities of the City and/or its equity partners.
1.6 - Regulatory Engagement-B
Monitor, participate and respond as required to CPUC proceedings and
processes to approve or reject the City's filed Implementation Plan.
Pending CPUC approvals, begin Track 2 Tasks.
6 Ca!. Pub. Util. Code §366.2 (c)(3) "The implementation plan, and any subsequent changes to it,
shall be considered and adopted at a duly noticed public hearing."
7 Cal. Pnb. Util. Code §366.2 (c)(IO)(A).
21
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
(2) Track 2 Tasks -
2.1 - CCA Implementation
2.1.1. - Register the CCA with the CPUC (may become part of 1.5 above)
2.1.2. - Execute Investor-Owned Utility (IOU) Service Agreement 8 -
2.1.3. - Detennine Required Aggregated Load Metering Facilities 9
-
2.1.4. - Complete Arrangements for 60-Day Customer Notification
And Opt-Out Provisions
2.1.5. - Notify SDG&E When CCA Service Will Begin
2.2 - CCA Operation (iterative and on-going activities) -
2.2.1. - Activate Energy Supply Resource Plan
- Execute Supply Contracts --
- Schedule Generation Resources
2.2.2. - Update Load Forecast and Optimize Scheduling
2.2.3. - Manage Supply Portfolio and Risk Management
2.2.4. - Process Financial Settlements
2.2.5. - Produce Operating Statements and Reports
b. Timelines
Upon acceptance of this Report, the City will have completed Track I
Tasks l.l and 1.2. The CPUC proceedings began on August 21, 2003 and appear to be
moving ahead in a manner to meet the CPUC's expectation of lasting between six and
nine months or approximately mid-2004. The MEU Study Team strongly recommends
that the City remain active in the ongoing CPUC proceedings in order to help shape the
8 The City, as a CCA operator, will need to establish a legal relationship with SDG&E. It is
anticipated that a service agreement will include processes for infonnation exchange including
electronic data interchange, procedures for settling financial transactions, treatment of customer
bill payment funds transfer, credit tenDs, access to confidential customer infonnation, audit
provisions, and regulatory oversight and complaint processes.
9 Identity whether additional metering devices described in Section IV.C.2.a of the Report at 40 can
be employed. If feasible and warranted, place service orders with SDG&E to have them installed.
22
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VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
CCA
CCA implementation costs, credit rules and protocols. The MEU Study Team estimates
that a CCA could be operational by 2006. Please refer to Section VIII.ß at 55 and
Appendix C, Section V at 130, for Gantt Chart time requirement projections for ach Task
described above.
8. Recommendation
The MEU Study Team recommends that, subject to the final adoption of
CPUC rules, the City take immediate steps to provide electric utility services through the
development and implementation of a CCA program. To enhance the benefits accruing
/Tom the CCA program, the MEU Study Team recommends that the City also adopt a
Generation Strategy leading to the development of generation capability within the City
as part of its resource portfolio. The MEU Study Team does not recommend any
financial commitment by the City for the development or ownership of a generation
resource until such time as the CPUC has finalized CCA rules and protocols and
approved a CCA Implementation Plan for the City. However, planning should begin
immediately for the implementation of a CCA program, although actual implementation
must await the promulgation of final rules by the CPUC.
23
VI. MEU STRUCTURAL OPTION~ -
OVERVIEW AND EV ALUATICN
GREENFIELD DEVELOPMENT
B. Greenfield Development
1. Summary
As discussed in the Report, Section III.B.2 at 26 and Section IV.D, at 61,
Greenfield development calls for the investment in distribution facilities to provide
electric service to certain previously undeveloped areas within the City of Chula Vista.
This structure would include undeveloped acreage of land designated for an industrial
park, for example, or for new residential subdivisions that are anticipated and planned for
within the City's general plan build-out schedule. The City may need to purchase a
substation and would have to interconnect to SDG&E's system in order to supply energy.
The City would also need to develop the distribution system configuration
(overhead/underground), lines, poles, and service extensions, as well as make
arrangements for appropriate meters and related customer service functions. The MEU
Study Team has identified the Otay Ranch Area, Mid-Bayfront, and Sunbow planning
areas as the sites primarily adaptable to a Greenfield project.
Once the Greenfield utility structure is established, the City would take
wholesale transmission service /Tom SDG&E and the CAISO, and its customers in the
Greenfield areas would no longer pay SDG&E retail rates, As the Greenfield
development would interconnect to SDG&E's distribution system, transmission service
would be under SDG&E's Wholesale Distribution Access Tariff (WDAT). The rates,
terms and conditions of service to be provided by SDG&E under its WDA T are regulated
and determined by the Federal Energy Regulatory Commission (FERC).10 The cost for
taking wholesale service under the WDA T would be determined based on an assessment
of the actual distribution facilities utilized by the City. The distribution capital costs
associated with City-owned distribution system serving the Greenfield development will
be determined based on the cost to construct new facilities.
2. Customer Base
The most likely areas for Greenfield development are the Mid-Bay/Tont,
Otay Ranch, and Sunbow planning areas. The number of customers in these potential
Greenfield development areas are projected at 4,017 in 2006 increasing to 10,193 in
2023.
3. Fnnctional Elements
A new, City-owned electric distribution system would be constructed in
the Greenfield service areas and interconnected with the existing SDG&E system. The
distribution system includes substations, lines. poles, extensions and meters.
-_.
10 A copy of SDG&E's Pro Fonna WDA T is attached as Appendix D.
24
VI. MEV STRUCTURAL OPTIONS -
OVERVIEW AND EV ALVATION
GREENFIELD DEVELOPMENT
The required capital investment for the new distribution system is
approximately $3,000 per customer. The approach used to estimate distribution capital
costs is based on industry standard investment costs per utility customer. The derivation
of this figure is explained in Appendix C, Section II.E.2 at 84-86. The MEU Study Team
believes this is a reasonable approximation for distribution capital costs in the context of
the MEU options analysis. Actual distribution capital costs will depend on factors
specific to the topography of the city, such as population density; requirements for under-
grounding of distribution facilities; the mix of residential, commercial, and industrial
customers in the existing and Greenfield development areas; and the method of service
provided for these customers. The option Chula Vista may elect is to require all
developers of new Greenfield areas to construct the requisite distribution facilities
according to the City and SDG&E standards, and dedicate such facilities to the City. If
such an approach were successfully implemented, the benefits accruing /Tom the
Greenfield option would increase substantially /Tom what the MEV Study Team has
estimated, because the initial infTastructure costs would be borne by the developer, not by
the City as was modeled by the MEU Study Team. The implementation of this option
would, of course, be subject to the adoption of appropriate policies by the City Council to
impose or recover these charges. The MEU Study Team has taken the most conservative
approach to projecting financial benefits for the Greenfield development by incorporating
the aforementioned $3,000 per customer distribution cost.
Resource requirements for a Greenfield only approach would be fulfilled
by entering into long and short-term contracts for power supply. The MEU Study Team
has concluded that it would not be feasible to obtain an ownership interest in a generation
project solely to match the relatively small and rapidly changing load requirements in the
Greenfield .development areas.
The power supply sources and portfolio would include long-term (one to
five years) and short-term (up to one year) contracts. Spot purchases could also be used to
fill the residual net short load requirements.
The rate structure assumptions used in the Greenfield model are based on
the City taking wholesale transmission service /Tom SDG&E through SDG&E's WDAT.
4. Benefits and Risks
a. Benefits
The 18-year NPV of savings to City residents, with power supply obtained
through contracts, is projected to be $21 million with average annual savings of 10%
compared to comparable SDG&E rates. Capital costs for this option are estimated at
$13.8 million.
25
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
GREENFIELD DEVELOPMENT
The benefits under this option include the likelihood of lower cost of
procurement and delivery of electricity, local control, improved reliability, and economic
development enhancements. An additional benefit of a Greenfield municipalization
effort would be that the City would not need to purchase the existing distribution
facilities /Tom SDG&E, and go through a lengthy condemnation process.
b. Risks
One of the risks that would play out, at least through the initial
in/Tastructure development period, is the economic viability of the program. Since at
least part of the in/Tastructure would need to be in place before customers began to
consume the energy, there would need to be enough working capital and cash flow to get
through the first few years as development came "on-line." Construction of some
distribution facilities such as lines, poles, and extensions would be phased in as
development progresses. However, some facilities may need to be constructed first, such
as a substation with a large enough capacity to meet future load growth. Another risk is
attributable to the fact that the amount of energy required to serve the Greenfield starts
out very small. The City likely will not be able to secure power at as competitive rates as
it could if it was purchasing for a larger load.
5. LegallRegulatory
With the exception of CPUC rules requiring the payment of Cost
Responsibility Surcharges, or "exit fees," discussed in Section IV.F.4.b.(4) of the Report
at 124-26 and Appendix B, Section II.C.I at 78-81, there are no specific state laws or
CPUC rules regulating the implementation of the Greenfield development option. Chula
Vista has adequate authority under the California Constitution and state statutes to
provide electric service to its inhabitants. Federal law governs the interconnection of the
City-owned distribution facilities with the facilities of SDG&E, including those operated
by the CAISO and SDG&E's rates for transmission service provided under its WDAT are
regulated by the FERC. The laws regarding interconnection requirements are also
addressed in Appendix B, Section II.C.3 at 33-35.
6. Financing Options
The City would have a variety of financing mechanisms available to
finance its Greenfield projects depending upon the specific asset to be required or built
and/or activity. Financing techniques might include the following:
þ> General Obligation Bonds
þ> Limited Oblig:ltion Bonds
þ> Special Asses>ment
þ> Certificates of Participation
26
.-...- --..-.- ...---------------------- - ----------
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
GREENFIELD DEVELOPMENT
J;> Revenue Bonds
J;> Commercial Paper
The MEU Study Team believes that tax-exempt financing should
generally be applicable to finance all the Greenfield capital projects.
In Appendix C, Section IV.A, at 126-27, the MEU Study Team has
provided an overview and comparative analysis of each type of financing vehicle that is
available to the City.
7, Implementation Schedule and TimeJines
It is estimated that it would take one to three years for full implementation
of this option. A detailed listing of the steps necessary to implement this option is set
forth below,
a. Implementation Schedule
(I) Ordinance:
City passes an ordinance to form a municipal utility (City has
already passed Ordinance No. 2835).
(2) System Design:
Electric distribution design firms will work with developers to
design and specify system requirements in compliance with
applicable design standards to serve the planned development. (2-
3 mo.)
(3) Determine Interconnection ReQuirements:
Assess technical requirements and cost to achieve interconnection
of the development distribution system with adjacent transmission
or distribution facilities. If the given Greenfield development is
going to be interconnected with facilities operating below
transmission system voltage levels (which for SDG&E is 138kV),
and served at distribution voltage levels (most likely 12-69 kV), it
will need to be served under SDG&E's WDAT. If this is the case,
the City must complete an application for service according to the
SDG&E WDAT. SDG&E will perform a facilities requirement
and system impact study to determine the logistics and the cost to
effect an interconnection with the SDG&E system, A successful
application will result in the execution of a service agreement
27
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EVALUATION
GREENFIELD DEVELOPMENT
which sets forth the costs, tenus and conditions of service. (6-9
mo.)
(4) Final Evaluation:
Evaluate and assess projected loads, costs and benefits (at this -
point, primarily interconnection costs) and detennine whether to
proceed with the project. (1 mo.)
(5) Procure and Schedule Power:
Based on load studies and forecasts derived from infonnation
provided under item (2), tailor and initiate a resource and schedule
power delivery to coincide with project completion and estimated
development occupancy. Update power delivery schedules, as
required before operational status as provided in power contract
tenus and conditions, to balance loads and resources. (2 mo.)
(6) Staffing/Outsourcing:
Initiate human resources plan. Update plans to reflect development
schedules and requirements; perfonn staffing or solicit outsource
staffing services. (2 mo.)
(7) In/Tastructure Construction:
Land developer subcontractors will install electric system
infTastructure, including trenching, conduit, backfill, vaults,
manholes and transfonner pads (as they would if SDG&E were to
serve the area). (2-5 weeks)
(8) High Voltage Eauipment Installation:
The City will engage subcontractors specializing in high-voltage
interconnection to pull conductors through the conduit, install
substations, connectors, switches, transfonners and connections
with metered panels (residents, businesses, etc). (2-3 weeks)
(9) Peripheral Eauipment:
City will install peripheral electrical equipment (traffic
controllers/irrigation pedestals/street lights). (2-3 weeks)
28
VI. MEU STRUCTURAL OPTIONS -
OVERVIEW AND EV ALUA nON
GREENFIELD DEVELOPMENT
(10) Initiate Operations:
Schedule and initiate Greenfield utility operations to coincide with
the occupancy date for newly developed area. (1 mo. - occupancy
date)
b. Timelines
The MEU Study Team estimates that the steps identified above would take
between 15 and 20 months to complete /Tom the time electric distribution system design
firms begin working with developers. Operation of a new Greenfield project will depend
upon actual project completion and building occupancy in the newly developed area. The
project implementation schedule Gantt chart, Section VIII.B below at 57 and Appendix
C, Section II.V.B at 131, is structured in months /Tom the onset of any given Greenfield
development project.
8. Recommendation
The MEU Study Team recommends that the City provide utility services
to the residents and businesses in the developing areas of Mid-Bay/Tont, Otay Ranch, and
Sunbow through the implementation of Greenfield projects and the construction of new,
City-owned distribution facilities.
29
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUATTON
COMBINED CCAIGREENFIELD DEVELOPMENT
C. Combined Community Choice Aggregation/Greenfield Development
1. Summary
The City of Chula Vista can simultaneously implement the CCA program
and Greenfield development on approximately the same schedule. Based upon the
economic analysis set forth in this Report, the MEU Study Team has concluded that the
most beneficial option open to the City is a Combined CCAlGreenfield development
based on a Generation Supply Strategy.
2. Customer Base
In combining the CCAlGreenfield options, the City could serve a
projected combined customer load of 90,652 customers beginning in 2006 and 104,469
customers in 2023 at the end of the study period. As discussed above, the MEU Study
Team has assumed 100% participation in the CCA program. To the extent that potential
customers "opt out", as they have the legal right to do, the benefits to the City and its
remaining customers would be reduced accordingly.
3. Functional Elements
The functional elements of other CCA and Greenfield options discussed
above do not change when the two options are combined. The two programs would be
administered and managed by the same administrative staff.
4. Benefits and Risks
a. Benefits
The benefits of a combined CCAlGreenfield development are materially
enhanced by the combination of these programs. Based on the financial pro fonna
perfonned by the MEU Study Team, the combined CCAlGreenfield utility option, using
City-owned generation (Generation Supply Strategy) would produce savings amounting
to $14.9 million in 2006 and increase to $31.7 million in 2023, for a total NVP savings of
$122 million over the study period. Capital costs for this option are estimated to be $78
million for generation and $13.8 million for distribution facilities.
b. Risks
There are certain risks inherent in both the CCA and the Greenfield
options, particularly one based on a Generation Supply Strategy. In the case of
Greenfield development, the full implementation of a Greenfield program in the
undeveloped areas of the City will depend on the pace at which commercial and
residential development occurs in the Greenfield areas. There is also the risk that
30
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
COMBINED CCAIGREENFIELD DEVELOPMENT
generation costs projected in the study to serve Greenfield's loads will be higher than
projected due to unforeseen changes in the California energy markets.
In the case of CCA development, there is currently uncertainty and
attendant risks related to the final development and implementation of rules and protocols
governing CCA programs. The City also runs the risk that, if benefits or savings to be
made available to electric customers are not attractive enough, prospective customers will
"opt out" of the CCA program, thus diminishing the benefits or savings to the City's
remaining customers.
5. LegaJ/Regulatory
Pursuing a program which combines both Greenfield development and
CCA will not alter the legal requirements for either option. There are no legal
impediments (or advantages) to pursuing both options simultaneously or in tandem.
6. Financing Options
The financing options open to the City for a combined CCAlGreenfields
utility option are those applicable to either the CCA or the Greenfield options as
discussed above.
7. Implementation Schedule and TimeJines
Barring any substantial delay in the promulgation and issuance of final
CPUC rules and regulations for CCA Projects, it is estimated that a combined
CCAlGreenfield utility option can be planned and implemented in a two to three year
time /Tame to allow the City to commence operations in 2006.
a. Implementation Schedule
The major and critical steps to implement a CCA project are discussed
above in Section VI.A.7.a at 20-22 and in Section IV.C.6.a of the Report at 58-60 and
will not be repeated herein. The major and critical steps to implement a Greenfield
project are discussed and outlined above in Section VI.B.7.a at 27-29 and in Section
IV.D.6.a of the Report at 77-79 and will not be repeated herein. Suffice it to say that, in
combining the Greenfield and CCA options, the critical steps and timing will remain
relatively unchanged.
b. Timelines
The implementation schedules for the CCA and Greenfield MEU options
can move forward simultaneously and the two options can be implemented on
approximately the same schedule depending on separate variables.
31
-- ..._.._-.-.--_...
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
COMBINED CCNGREENFIELD DEVELOPMENT
In the case of the CCA option, the largest unknown is the development
and implementation of final CCA rules and regulations by the CPUC. As discussed
earlier, the CPUC initiated its CCA rulemaking procedure on August 21, 2003 and issued
Rulemaking No. R-03-09-007 on September 4, 2003. On October 2, 2003, the CPUC
reissued the rulemaking under Docket No. R.03-10-003. On November 26, 2003, the
assigned Administrative Law Judge in R.03-10-003 issued a ruling bifurcating the
proceeding into two phases. The first phase, in which hearings were held in February
2004, addressed many of these cost related issues. Administrative and ministerial matters
will be the subject of the second phase of the proceeding. It is anticipated that final CCA
rules and regulations will be implemented by mid-2004, and, under this schedule, the
MEU Study Team estimates that a CCA could be operational by mid-2005 (please refer
to Section VIII.B below at 55 and Appendix C, Section V.A at 130 for Gantt chart time
requirement projection for each critical path necessary to fonn a CCA).
In the case of a Greenfield Project, the operation of any Greenfield Project
will depend upon actual project completion and building occupancy in the newly
developed areas designated for Greenfield development. The MEU Study Team
estimates that the steps necessary to implement a Greenfield Project would take /Tom 15
to 20 months to complete /Tom the time the City Staff and electric distribution design
finn begin working with the developers of the Greenfield areas. The project
implementation schedule (Gantt Chart) in Section VIII.B below at 57 and in Appendix C,
Section IIV.B, at 131 is structured in months /Tom the onset of any given Greenfield
development project.
8. Recommendation
The MEU Study Team recommends that the City elect to develop both a
CCA project and Greenfield projects in the near tenn and combine the administration of
these projects under the City's MEU. The MEU Study Team also recommends that the
City immediately begin initial planning for development of an internal generation
program to allow the City to serve its customers with City-owned generation. While it is
not necessary for City-owned generation to be online to serve the MEU load at the outset,
the long lead-time and due diligence required for investment in generation dictates
beginning the process now. In developing an MEU with the CCA and Greenfield
projects in the near tenn, the City will establish utility infrastructure and gain operating
experience without the necessity of acquiring the electric distribution facilities of
SDG&E.
32
-- ----------- -- -------------------- ----- --- -------
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
D. Municipal Distribution Utility
1. Summary
As discussed in the Report, Section III.B.4 at 26 and Section IV.F at 99,
the Municipal Distribution Utility (MDU) model is a full service utility that develops and
acquires generation resources and owns and operates the distribution facilities within the
City in order to provide full utility service to retail electric customers in the City. If the
City implements this option, the City would acquire SDG&E's electric distribution
system by negotiation or condemnation and perform operation and maintenance
activities. The City would also develop or acquire generation resources, and/or purchase
power to meet City load requirements.
2. Customer Base
The development of an MDU will give the City the capability of providing
full electric distribution service to all electric consumers in the City. It is projected that
the MDU would serve 86,652 customers in 2006 and 104,499 customers at the end of the
study period in 2023.
3. Functional Elements
The MEU Study Team evaluated two primary supply strategies for the
City to serve the loads of the MDU customers: I) a Generation Supply Strategy that uses
city owned generation resources for base load requirements; and 2) a Contracts Supply
Strategy that uses long term power purchase contracts for base load requirements. The
Generation Supply Strategy is based on City ownership of 130 MW of new combined
cycle gas turbine power plant capacity. The Contracts Supply Strategy is based on the
City entering into long and short-term fixed price power supply contracts to meet the
majority of the MDU's load requirements.
To achieve the highest benefit under this option, the City would have to
acquire the distribution system of SDG&E and have ownership of at least 130 MW of
internal generation. Under this scenario, the City would take wholesale transmission
service /Tom SDG&E and the CAISO, and its customers would no longer pay SDG&E
retail rates. It is assumed that the City or its customers would be subject to payment for
the exit fees and other non-bypassable charges mandated by AB 1890. The City would
acquire the existing distribution system from SDG&E at a negotiated price or by the
exercise of the power of eminent domain.
In assessing the feasibility of the MDU option, it is important to
distinguish whether the option includes a Generation Supply Strategy based on the
ownership or enûtlement to at least 130 MW ofload generation.
The MDU option is financially viable if the City owns generation within
the City boundaries. Internal generation minimizes wholesale transmission charges and
33
- --- ------------- - ------------ - -______n
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
other charges assessed by the CAISO. So long as the internal generator operates at a
capacity factor greater than 50%, FERC rules require transmission access charges to be
assessed on a net load basis, i.e., the internal generation is subtracted /Tom the gross load
requirements of the MDU before applying the transmission rates. In addition, internal
generation reduces exposure to transmission congestion charges, charges for reliability
services, and certain elements of the CAISO's grid management charge. The benefits of
internal generation to the MDU's cost of service /Tom reduced transmission access
charges and other CAISO charges are estimated at $6 million per year.
These wholesale transmission related benefits would not be obtained if the
City were to supply its load through power purchase contracts or ownership of remote
generation that must utilize the CAISO transmission network for delivery to the City
MDU. An MDU supplied through purchases /Tom the market (as opposed to City-owned
generation) is not financially viable for the City in the near term.
The MEU Study Team evaluated a number of supply portfolios to
optimally serve the load requirements of the City. A typical supply portfolio would
utilize generation owned by the City or long-term contracts for the majority of projected
base load requirements. These long-term resources would be supplemented with short-
term contracts covering the additional seasonal load requirements of the portfolio,
typically in the third quarter of each year. Spot market purchases and sales are used to
fill the residual net short load requirements.
To import power, the City would take wholesale transmission service at
the 115 KV voltage level and would be assessed CAISO charges for high and low voltage
transmission service. Transmission costs are based on the currently effective CAISO
transmission access charges applicable to the SDG&E area for high voltage and low
voltage transmission service. The transmission charges were assumed to escalate at 1.3%
per year.
The MEU Study Team used the results of a nationwide benchmarking
study of municipal electric utilities to estimate distribution operation and maintenance
(O&M) costs for the city. The study grouped municipal electric utilities by size into five
strata and reports average per customer O&M costs within each strata for distribution
O&M, customer service expenses, and administrative and general expenses. The average
total annual distribution O&M costs reported by participants in the study range /Tom
$246 to $594 per customer, reflecting a wide range of urban and rural municipal utilities
of various sizes and population densities.
The MEU Study Team has also used a targeted set of case studies of
California municipal electric utilities to obtain O&M estimates that would be more
reflective of the costs expected for the City municipal electric utility. Data are available
for years 1998-2001, and the average total annual distribution O&M costs range /Tom
$231 to $380 per customer. For this analysis, the four-year average per customer O&M
costs of California municipal utilities of similar size as Chula Vista was used to predict
the cost for MDU distribution operations. The four municipal utilities with between
34
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
50,000 and 90,000 customers were selected. These were Burbank, Glendale, Pasadena,
and the Turlock Irrigation District. The average annual O&M cost is $270 per customer.
By comparison, the MEU Study Team has calculated the system-wide
average distribution O&M costs for SDG&E, using FERC Fonn I data, of $198 per
customer. The lower figure for SDG&E reflects economies of scale in distribution
operations that are not available to smaller distribution systems. The capital financing
and tax advantages of municipal electric utilities are offset to a degree by higher per
capita O&M costs typical of smaller utilities.
4. Benefits
The projected NPV of savings to City residents does not support use of
this option with power procured solely through contracts. However, with power supplied
/Tom City-owned generation, the NPV of this option is projected to be $109 million over
the study period. Capital costs are estimated to be $185 million to acquire SDG&E's
distribution system and $78 million for generation. I I
If Chula Vista decides to pursue this option, its residents could realize a
number of benefits, including the likelihood of lower-priced power, more stable
electricity rates, local control, improved reliability, and opportunities for economic
development. Moreover, in acquiring the SDG&E distribution system, the City will have
valuable assets and broaden its opportunities for further savings.
There are important inherent benefits and advantages to public ownership
of utility systems. Since the California electric industry was restructured and
"deregulated" by the California Legislature in 1996, the electric customers of the State's
IOUs have experienced dramatic increases in their electric rates, particularly in the San
Diego area. At the same time, the customers of most of the State's publicly-owned
utilities were protected from the dramatic increase in rates. While some municipal utility
customers also experienced rate increases, the increases were not on the order of
magnitude that the customers of the California IOUs have experienced. The major reason
municipal utility rates did not increase as dramatically as IOU rates is that municipal
utilities were not fully and forcefully committed to the California deregulation
experiment, and therefore not substantially reliant on the energy spot markets in 2000 and
2001. Most municipal utilities had either developed their own generation resources, or
entered into long-tenn power contracts that "locked-in" and stabilized future energy
costs, and were therefore not dependent upon spot-market purchases. The history of the
restructuring of the California electric industry and related regulatory and legislative
issues is set forth in Appendix B, Section I at 11-27. This analysis demonstrates and
discusses the legal and regulatory environment in which the City of Chula Vista's MDU
would operate once established.
II The total capital costs for the acquisition ofSDG&E's distribution system would be approximately
$12 million lower if the City elects to pursue the Greenfield option and build distribution facilities
for these customers.
35
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TlON
MUNICIPAL DISTRIBUTION UTILITY
Municipal utilities have an inherent price advantage over IOUs because
the municipal utility is not motivated to produce profits for shareholders. Municipal
utilities are pennitted to set rates which cover both capital and operating expenses and
also fund utility reserve accounts, fund in-lieu-of-tax payments to local governments,
fund other worthy public projects and, within reasonable limits, make a rate of return on
its investment. In addition, the municipal utility has access to tax-exempt financing for
many capital expenditures. These key components provide the City with significant
advantages regarding retail electricity rates as compared to remaining a full requirements
customer of SDG&E.
Another major advantage with this option would be local authority and
control. For instance, the future potential City of Chula Vista Electric Utility Department
could make resource decisions, develop maintenance practices, develop capital
improvement programs, and make other decisions relating to the operation of the utility
for the sole benefit of City residents and businesses. For instance, the City could elect to
purchase electricity /Tom more environmentally benign resources in comparison to
SDG&E's resource mix. The City Council would be the only entity to set electric rates.
Such rates would be designed to meet any unique circumstances existing within the
City's service territory. Currently, these decisions are being made by SDG&E (for the
benefit of its shareholders) under the regulation of the CPUC and the FERC. Municipal
utilities are not, for the most part, subject to CPUC or FERC regulation.12 Rather, they
are, for the most part, subject to self-regulation and control by the City Councilor a
municipal utility board or commission.
An important facet of local control which should not be overlooked is the
ability of the Chula Vista City Council to fashion programs to utilize public goods
charges (discussed in Section IV.F.3.d(I)) of the Report at 119-20 and in Appendix B,
Section III.C.I.a at 16-17). Such programs must meet the requirements of state law, but
can be designed to meet the unique requirements of Chula Vista customers and provide
direct benefits to Chula Vista residents and businesses.
Public Utilities Code 385 authorizes and requires local publicly owned
electric utilities to collect, through rates for local distribution service, revenue allocated to
public benefits programs. The public benefits charges are to be not less than the lowest
expenditure level of the three largest IOUs on a percent ofrevenue basis for year ending
December 21, 1994. Public benefits related charges are currently a minimum of
2.85 percent of the publicly owned electric utility's revenue requirement.
Public benefit programs referred to include the following:
i. Cost-effective demand-side management services to promote energy
efficiency and energy conservation;
12 See discussion in Appendix B, Section I.C at 15-27.
36
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
ii. New investment in renewable energy resources and technologies (subject
to applicable statutes);
iii. Research, development and demonstration programs for public interest to
advance science and technology that is not adequately provided by
competitive and regulated markets; and
iv. Service for low-income electricity customers, including, but not limited to,
energy efficiency services, education, weatherization, and rate discounts.
Revenue associated with this charge would be available to the City to
allocate to various activities identified above.
Finally, the City could provide economic incentives for specific economic
development areas within the City, and design rates to match those incentives.
5. Risks
One obvious and large risk inherent in this option is the amount of
resistance that SDG&E would exert against the City moving forward with a public power
entity. Ideally, if the City decided that it wanted to proceed with the implementation of a
City Electric Utility Department, the City would be able to reach a negotiated settlement
with SDG&E for the acquisition of its distribution assets. However, it is more likely that
SDG&E would resist the acquisition of its distribution facilities.
In considering the MDU option, the City should not underestimate the
potential strong opposition SDG&E will wage against the taking of its distribution assets
or infringement on its customer base. The City should anticipate that SDG&E will use
every legal and political tool available to ITustrate, defeat or delay the implementation of
the City's MDU option. The Eminent Domain Law 13 gives the property owner several
opportunities to defeat the acquisition, beginning with the contest of the Resolution of
Necessity. SDG&E can also delay the implementation ¡rocess by contesting the terms
and conditions of the interconnection before the FERC.' At the bottom line, SDG&E's
political and legal resistance to selling its distribution assets may substantially increase
the start-up costs associated with the creation of a new utility.
It is worth noting that SDG&E recently funded a citizen's initiative in San
Marcos in opposition to the City Council's efforts to implement a Greenfield project to
serve newly developed areas within the City. IS
13 See discussion in Appendix B, Section II.A at 28-30.
14 See discussion in Appendix B, Section 1l.C.3 at 33-35.
IS The San Diego Union Tribune, August I, 2003. According to San Marcos Councilman Lee
Thibadeau: "SDG&E is doing everything it can to interfere with the city's right to establish our
own utility and save our residents millions of dollars."
37
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
Another risk may involve issues surrounding the separation or "islanding"
fÌom other parts of the SDG&E system. If the City and SDG&E cannot agree on the
terms and conditions of the interconnection, the City will be required to file an
application for interconnection with the FERC. The FERC will establish the terms and
conditions of the interconnection, including any necessary reconfiguration of the SDG&E
distribution system to allow SDG&E to continue to serve those customers located outside
of the City's service territory. The FERC will assign the costs of the interconnection to
the City. There would also likely be certain physical distribution asset separation
problems where portions of SDG&E's distribution lines cross other jurisdictional
boundaries. This may require the construction of additional distribution substations,
installation of net metering technologies, or other local distribution design
reconfigurations resulting in the award of severance costs to SDG&E as part of the
condemnation process. The net effect could result in increased costs of acquiring
SDG&E's distribution assets and establishing the City's distribution system.
Operational risks must also be considered, as the City would be
undertaking electric distribution operations that require skill sets and personnel not
currently in place at the City. Operations and maintenance of high voltage electrical
systems require skilled and experienced personnel with the ability to safely and reliably
operate the system.
To provide a cost benefit over the current SDG&E service, the City would
need to be able to acquire the distribution system, provide or obtain energy and related
services, perform operation and maintenance services, billing, settlements, and
collections, and perform long-term planning, all at a cost ofless than the current provider.
Based upon the financial pro forma performed by the MEU Study Team, the City can
meet this challenge through the formation and operation of a full service MDU.
6. Legal/Regulatory
a. Formation and Implementation Process
Cal. Const. Art. XI, §9 provides specific authority for municipal
corporations to provide utility services both within and without of their boundaries ". . .
except within another municipal corporation which furnishes the same service and does
not consent." Cal' Pub. Util. Code § 10002 provides that a municipal corporation may
acquire, construct, own, operate, or lease any public utility, A Public Utility, in this
context, is defined as the supply of a municipal corporation alone or together with its
inhabitants, or any portion thereof, with water, light, heat, power, sewage collection,
treatment, or disposal for sanitary or drainage purposes, transportation of persons or
property, means of communication, or means of promoting the public convenience. See
Cal. Pub. Uti!. Code § 10001.
Publicly owned municipal utilities (the various forms of which are set
forth and described at Cal. Pub. Uti!. Code § 9604(d)) are not regulated by the Public
Utilities Commission or any other supervising agency, in the absence of a legislative
38
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VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
grant of authority (Cal. Const., art XII, § 3; see also, County of Inyo v. Public Utilities
Commission (1980) 26 Cal. 3d 154.
No fonnation or implementation process is specified by state law for the
creation of such a utility.
As discussed in Section I above at I, the City of Chula Vista has already
taken the initial steps in the fonnation of an MEU with the adoption, on June 5, 200 I, of
Ordinance No. 2835, establishing the City as a municipal utility.
b. Exercise of the Power of Eminent Domain
In California, a public entity, such as Chula Vista, may acquire property
for public use, including public utility facilities and fÌanchises, using the process of
eminent domain.16 The procedure which a municipality or other entity (e.g. Municipal
Utility District) must follow in acquiring public utility facilities or fÌanchises is discussed
in detail in Section IV.F.4.a of the Report at 123-24 and in Appendix B, Section I1.A at
28-32. The MEU Study Team has also provided an analysis of the standards for
detennining "just compensation" in eminent domain proceedings. See Appendix B,
Section I1.B at 30-32.
7. Financing Options
The City would have certain financing advantages in comparison to
SDG&E due to its lower cost of capital arising from access to low cost debt and
exemption fÌom federal and state income taxes. Tax-exempt financing is not applicable
to the acquisition of existing distribution assets and was not used in the analysis. Tax-
exempt financing was only asswned to be used for all new distribution and generation
facility development.
In Appendix C, Section IV.A, at 126-27, the MEU Study Team has
provided an overview and comparative analysis of each type of financing vehicle that is
available to the City.
8. Implementation Schedule and Timelines
The implementation of an MDU option will be complicated by the
eminent domain process asswning that the City is unable to reach agreement with
SDG&E after making an offer for the purchase of the electric distribution system. To
develop a reliable offer, the City must complete the study and planning process and adopt
a Resolution of Necessity. On a most optimistic basis, the MEU Study Team estimates
that an MDU could be established in a three and one-half year time fÌame. More
realistically, the MEU Study Team would suggest allowing a five to six year (or more)
16 See Cal. Civ. Proc. Code §§ 1240.010 and 1240.110.
39
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
lead time for the fonnation of the MDU. During this period, the City could implement
the CCNGreenfield options, develop an MEU infÌ'astructure, and gain utility operating
experience before undertaking the task of acquiring or condemning SDG&E's electric
distribution system.
a. Implementation Schedule
In the event that Chula Vista elects to fonn an MDU, the MEU Study
Team has identified the following major and critical steps, beginning with a focused
MDU Feasibility and Implementation Plan, which will be necessary for the City to
complete before commencing the operation of the City's electric distribution system:
(1) Focused MDU Feasibility and Implementation
Plan Tasks
(1.1) Distribution System Survey and Valuation: (I mo.)
1.1.1 Detail the distribution system configuration, inventory
equipment and facilities; document the percent condition
1.1.2 Perfonn a system valuation to detennine just compensation for
the negotiated purchase or condenmation of the existing
distribution system
(1.2) Severance Plan and Cost Study: (3 mo.)
1.2.1 Perfonn an engineering evaluation of the distribution system
within and adjacent to the City's boundaries
1.2.2 Document the location and configuration of substations and
interconnections required to isolate and interconnect the City
electric system and ensure SDG&E can provide service to its
remaining customers
1.2.3 Prepare plans, specifications, drawings, material lists, cost and
construction time estimates
1.2.4 Identify other private properties that must be purchased or
condenmed and estimate just compensation and time estimates
(1.3) Energy Resource Plan: (3 mo.)
1.3.1 Finalize generation and contract supply strategy, engage
developers in negotiations
1.3.1.1 Negotiate placement of generation facilities within
City boundaries
1.3,1.2 Negotiate a percentage of plant ownership and/or
entitlement to generation plant output
1.3 .1.3 Identify a short list of wholesale energy providers;
refine supply pricing, tenns and conditions of
supply
(1.4) Human Resources Plan: (3 mo.)
40
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
1.4.1 Identify any areas of overlap with existing City organizational
structures and ways to leverage existing staff capabilities
1.4.2 Re-evaluate hwnan resource requirements (Section IV.F at
106-07) to eliminate overlaps in staffing
1.4.3 Develop detailed job descriptions for each remaining hwnan
resource reqUIrement
1.4.4 Perform an analysis of the regional labor base to determine
availability of qualified candidates for key discipline areas,
survey the relevant job market to fulfill plans to staff these
positions and provide time estimates
(1.5) Facilities Plan: (3 mo.)
1.5.1 Identify facility requirements
1.5.1.1 Customer and Energy Services: (call center, staff
offices, billing system, vehicles and equipment)
1.5.1.2 Distribution Engineering and Operations: (offices,
communication and control equipment, garage
facilities, service vehicles, yard, security)
1.5.1.3 Power Operations: (staff offices, systems and
equipment)
1.5.1.4 Detail availability, location and cost to build, buy,
lease or otherwise acquire the needed facilities
(1.6) Pro Forma Update: (1 mo.)
1.6.1 Update cost estimates with results of the distribution system
survey, severance, energy resource, hwnan resources and
facilities plans described in 1.1 to 1.5
1.6.1 Prepare request to SDG&E to obtain detailed customer load
data
1.6.2 Update and refine load forecast based on planned development
1.6.3 Incorporate the impacts of any new regulations, cost
asswnptions or City objectives
(1.7) Finance Plan: (1 mo.)
1.7.1 Work with financial planners and bond counsel to develop
revenue bonding and other alternatives for financing depending
upon categories and values of assets to be financed
(1.8) Governance Plan: (2 mo.)
1.8.1 Propose governance structures for the new municipal utility
1.8.2 Obtain consensus among City leadership and establish plans
for reporting, oversight and financial management of the
municipal utility
(1.9) Implementation Plan: ( I mo.)
1.9.1 Incorporate all of the above into an implementation plan
41
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
MUNICIPAL DISTRIBUTION UTILITY
1.9.1.1 Structures, costs, timelines, updated financial
prospectus
1.9.1.2 Achieve City leadership's approval and move to
Implementation Phase
(2) Implementation Plan Tasks
(2.1) Establish public interest and necessity and demonstrate greatest
public good, least private injury (1 mo.)
(2.2) Ordinance No. 2835 has provided local authority establishing a
public utility - further action by City Council to authorize
negotiations with SDG&E as described in Section 2.3 below (1 mo.)
(2.3) Make an offer and attempt to negotiate the purchase of SDG&E's
distribution system (1 mo.)
(2.4) Provide an opportunity for SDG&E to appear and be heard and argue
public interest and necessity (30 days required - I mo.)
(2.5) Adopt Resolution of Necessity to condemn the property (I mo.)
(Resolution of Necessity creates a rebuttable presumption that the
public interest and necessity have been established17)
(2.6) Final Offer: 30 days prior to condemnation trial the City must make
another attempt to negotiate the purchase of the property (1 mo.)
(2.7) Judicial Review:18
2.7.1 SDG&E is likely to seek judicial review of the validity of the
City's Resolution of Necessity (see 2.5) before or during the
power of eminent domain proceedingl9 (3 mo.)
(2.8) File Complaint in Superior Court invoking the power of eminent
domain and initiating condemnation proceedings (6 mo. to 2 years)
2.8.1 Obtain any final information needed to confirm and support
any critical elements of the Implementation Plan
2.8.1.1 The City can secure either the written consent of the
SDG&E or an order fÌom the Superior court to enter
the property to make photographs, studies, surveys,
17 Cal Civ. Proc. Code § 1245.250.
18 Cat Civ. Proc. Code § 1245.255.
19 Cal Civ. Proc. Code §§ 1250.350 and 1250.370.
42
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VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
examinations, and appraisals or engage in similar
activities related to acquisition or use of the
propertlO
2.8.1.2 If the City's Resolution of Necessity is accepted and
the City's right to affect a taking of SDG&E's
property and setting of compensation is approved, the
City may apply ex parte to the court for an order for
possession (deposit with the court the probable
amount of compensation) and proceed to initiate the
Implementation Plan.
(2,9) Execute Implementation Plan: (I year)
2.9.1 Negotiate the Date of Possession based upon the
scheduled completion of the Following:
Governance Plan
Human Resources Plan
Facilities Plan
Severance Plan
Energy Resource Plan
2.9.2 Execute Energy Supply Agreements
2.9.2.1 Finalize arrangements with developers for generation
projects
2.9.2.2 Prepare RFP for Power Supply Contracts, Evaluate
Responses and Execute Contracts
2.9.2.3 Begin Scheduling power
b. Timelines
Given the many variables inherent in the eminent domain proceedings and
in the other regulatory proceedings related to the establishment of state imposed exit fees
and non-bypassable charges, it is impossible to provide a defmitive implementation
schedule. The MEU Study Team estimates the following timelines for the completion of
the planning elements and implementation phases in establishing an MDU:
Planning Elements: The time to complete additional planning, consisting
of the individual elements itemized above, performed in sequence are estimated to take
twenty months. However, overlaps and concurrent work projects might reduce this
estimate to one year. The lead time to implement generation projects, on which the MDU
Generation Strategy option and its benefits are based, is estimated between one and one-
half to three years, although this might be initiated prior to completing all of the planning
elements.
20 Civ. Proc. §§ 1245.010, 1245.020, 1245.030.
43
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VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
Implementation Phase: It is estimated that the process leading up to a
condemnation trial will take approximately six months for Implementation Tasks 2.1
through 2.7. The court hearings are estimated to take between six months and two years.
An order for possession might be obtained prior to resolution and setting of just
compensation, It is estimated that the City can establish its right to take the SDG&E
assets by obtaining the judicial approval of the Resolution of Necessity within ten
months. It is further estimated that the implementation Plan can be fully executed in
fÌom one year to 18 months. Hence, the most optimistic time projection to implement the
MDU is three and one-half years.
The MEU Study Team believes the estimated two year time required to
implement a generation project will run concurrently with the additional planning
activities and the condemnation process. Accordingly, the 3.5 year time estimate would
not change for implementation of the MDU structure option with a Contract Supply
Strategy. However, as discussed above, the MEU Study Team does not recommend
implementing the MDU option with a Contracts Supply Strategy.
Based on the analysis contained herein, the City could elect to implement
an MDU employing a Generation Supply Strategy as soon as it could obtain entitlement
to generation output fÌom a local, modern power plant. A phased approach, as described
above, would allow the City to develop experience in the power procurement and
delivery business.
If the City elects to implement the MDU option in the 2010 timefÌame,
after the establishment of the Combined CCAIGreenfield option, as recommended by the
MEU Study Team, the City would commence the MDU Planning and Implementation
Elements discussed above in mid-2008.21
In considering the timelines necessary to implement an MDU system, the
City should be cognizant of and prepared for strong legal and political opposition fÌom
SDG&E. Such opposition could substantially delay the completion of the acquisition
process and increase the start-up costs for the MDU option.
9. Recommendation
Based upon the positive results of the pro fonna fmancial studies and the
other major benefits, which will accrue fÌom the implementation of the MDU (with the
Generation Supply Strategy) option, the MEU Study Team believes that it is feasible,
fÌom both an economic and operational standpoint, for the City to fonn and operate an
MDU by acquiring the distribution assets of SDG&E. In coming to this conclusion, the
MEU Study Team recognizes that, because of the substantial capital investment required
to acquire the distribution system, generation facilities and to defÌay the start-up expenses
21 It should be noted that, in the Gantt Chart located in Section VlIl.B below at 59 and in Appendix
C, Section V.C at 132, the implementation schedule used for comparing the MEV options
reviewed herein begins in 2004 for all options.
44
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EV ALUA TION
MUNICIPAL DISTRIBUTION UTILITY
for an MDU, the potential NPV of benefits to the City is less favorable than the
CCAIGreenfield option with a Generation Strategy. At the same time, the MEU Study
Team is of the opinion that, in the long run, the ownership of the electric distribution
system would allow the City to serve all electric customers within the City at rates
substantially below the current and projected rates of SDG&E and pennit the city to build
asset value in the distribution system. The MEU Study Team has also given substantial
weight to the non-financial benefits to be realized by public ownership of the distribution
system, including local control of rates and service, discretion in the application of
savings or benefits, and independence /Tom SDG&E and the owner/operators of the
transmission grid.
Given the additional planning and study requirements needed to
implement the MDU option, together with the procedural steps which must be followed
under the Eminent Domain Law, the MEU Study Team recommends that the City defer
implementation of the MDU option until the 2008-10 time /Tame and re-evaluate the
option based on circumstances existing at that time, Assuming that the City proceeds to
develop the CCA and Greenfield options in the meantime, the City will have an MEU
in/Tastructure, customer base, generation facilities and several years of operating
experience before needing to make the critical decision of potentially acquiring the
distribution system of SDG&E. In the event that CCA appears to be uneconomical once
the CPUC has issued its final rulemaking decisions, the MEU Study Team would
recommend that the City accelerate its consideration of the MDU option.
45
VI. MEU STRUCTURAL OPTIONS - OVERVIEW AND EVALUATION
JOINT POWERS AGENCYIMUNICIPAL UTILITY DISTRICT
E. Joint Powers Agency/Municipal Utility District
As discussed in the Report, Section IJI.B.5 at 26 and Section IV.G at 135,
the MEU Study Team identified two long range options which are open to the City once
it establishes an MDU. These options are participating in a Joint Action Agency (JPA) or
forming a Municipal Utility District (MUD). As explained in the body of this Report,
both the JPA and MUD options would involve making complex arrangements and
entering into contractual agreements with other publicly-owned electric systems and/or
local governments.
While both the JP A and MUD options provide a vehicle for spreading risk
and expenses and allowing the City's MEU to take advantage of the economies of scale,
it is the opinion of the MEU Study Team that neither the JP A nor MUD option is suitable
as a vehicle for the initial formation of an MEU by the City.
Once the City forms its MEU and begins operations under anyone of the
options analyzed and recommended herein, the City should consider participation in an
existing JP A or the formation of an MUD.
The legal authority and the procedures required to participate in or form a
JPA or MDU are set forth in Section IV.G of the body of the Report at 135-39.
46
_... -.'w . -...--.--.--..--..--... 0.. ..-.. n_'_.'.
VII. NATURAL GAS
VII. NATURAL GAS
As explained in Section IV.H of the Report at 140-54, the MEU Study
Team performed an analysis of the feasibility of owning and operating the gas
distribution facilities located within the City. The gas distribution system in Chula Vista
is currently owned and operated by SDG&E, a wholesale customer and affiliate of SoCal
Gas.
The study first focused on the economics of the gas distribution business
since SDG&E's gas procurement charge for core customers is competitive with the
market price of gas available to SDG&E at the California border. The MEU Study Team
found that (I) SOG&E does not own substantial amounts of interstate pipeline capacity,
and (2) that SDG&E's gas procurement contracts are based on rates that are "at or below"
market prices and that, even with projected escalation in gas prices, it is unlikely that
SDG&E's gas procurement contracts will be "above market" during the 18-year period of
the study. Under these circumstances, it was concluded that Chula Vista could not
compete with SDG&E by entering into the gas distribution business using SDG&E's gas
distribution system for delivery of gas to customers within the City.
The MEU Study Team then performed an analysis to determine whether
Chula Vista could provide any benefits or achieve economic feasibility by acquiring,
owning and operating the gas distribution system within the City's boundaries. Since the
MEU Study Team had concluded that the City could not procure gas at wholesale for
prices that were competitive with SDG&E, it was necessary to determine whether the
City could provide gas transportation and distribution (T &0) services to customers at a
lower cost than the customers currently pay to SDG&E for these services. To perform
this analysis, the MEU Study Team provided an estimate, using conservative
assumptions, ofChuia Vista's estimated costs for facility acquisition, operating costs, and
transmission costs which would have to be paid to both SoCai Gas and SDG&E to get
wholesale gas to the City.
Once the MEU Study Team projected all operating and gas procurement
costs, these costs were compared to comparable costs of continuing to buy retail gas /Tom
SDG&E to determine whether Chula Vista could provide gas service to its customers at
rates lower than SDG&E. The comparative cost analysis for both gas distribution service
and for a full service gas utility (including acquisition, ownership and operation of the
gas distribution system) were negative. Under the conservative assumptions used by the
MEU Study Team, the study shows that, over the 18-year study period (2006 through
2023), the NPV of the revenues which would be lost by establishing a municipal gas
utility in Chula Vista would be approximately $24 million.
As this feasibility analysis reflects, on September 17, 2003, SDG&E filed
an application for significant increases in its natural gas rates as part of its Biennial Cost
Allocation Proceedings (BCAP). If approved, SDG&E's new gas rates would become
effective on January 1, 2005. In the event that SDG&E succeeds in its proposal to
47
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VII. NATURAL GAS
increase its gas rates, the MEU Study Team recommends that the City should reexamine
the feasibility of providing gas distribution services.
-
-
-
-
48
..... ......... "--.'---.---..'--. ............
VIII. CONCLUSIONS AND RECOMMENDATIONS
VIII. CONCLUSIONS AND RECOMMENDATIONS
A. Discussion and Comparison of Recommended Options
Based upon the results of this feasibility analysis, the MEU Study Team
has recommended that the City implement its Energy Strategy through the
implementation of the following MEU options or a combination thereof:
1. Community Choice Aggregation Program
a. Analysis
Under a CCA program based on a Contracts Supply Strategy, cost savings
or benefits are projected to occur in the years 2006-10. Projected SDG&E rate reductions
in 2011 resulting from the expiration of DWR power purchase contracts eliminate the
savings or benefits in the years 2011 through 2014. At that time, annual increases in
SDG&E's rates are projected to provide persistent savings or benefits to the City through
the study period. Savings begin at $6.3 million/year in 2006 and increase to $11
million/year in 2023. The City could implement the CCA program based on a Contracts
Supply Strategy without substantial capital costs, The first year implementation costs to
get this program in operation are estimated at $225,000.
A CCA program based on a Generation Supply Strategy promises to
optimize the City's revenues and savings to its customers. If Chula Vista elects to secure
130 MW of generation, the MEU Study Team projects savings to begin at $13.3
million/year in 2006 and grow to $21.3 million/year in 2023. Here again, savings or
benefits will be reduced significantly in the years 2011-2014 due to the expiration of
SDG&E's DWR contracts, and savings or benefits would increase as SDG&E's
wholesale rates are increased. Under this option, the City would be required to make a
substantial capital investment in generation facilities to provide 130 MW of intemally-
generated electric power. The initial investment in generation is estimated at $78 million.
The major benefit available under the CCA program is that, under this
option, the City could begin purchasing electric energy and supplying it to its retail
customers without the need to purchase the SDG&E electric distribution system. It
would also provide a generation portfolio and the inftastructure and experience necessary
if the City also elects to establish a Greenfield Project or form an MDU and acquire and
operate the electric distribution system within the City.
b. Recommendation
It is the recommendation of the MEU Study Team that the City
immediately implement the Tasks identified in the body of the Report to implement a
CCA program. While the actual implementation of a CCA program cannot be completed
until the CPUC issues its final rules and regulations, the MEU Study Team believes that
the City could implement a CCA program by mid-2005 or 2006.
49
VIII. CONCLUSIONS AND RECOMMENDATIONS
Of the two CCA options analyzed, implementation of a CCA program
with a Generation Supply Strategy, as opposed to the Contract Supply Strategy, optimizes
the benefits and savings to the City
2. Greenfield Development
a. Analysis
Based upon the economic analyses, the MEV Study Team concluded that
a Greenfield utility, which commences service in 2006, would lose money until 2012.
Beginning in 2012, the MEU Study Team projected persistent savings or benefits through
the end of the study period (2023) due to the addition of a larger number of electricity
users and the addition of large commercial and industrial loads. Over the study period
(2006-23), savings or benefits are projected to amount to $21 million. The
implementation of a Greenfield option would require a capital investment of
approximately $13.8 million to provide the distribution system necessary to serve
developing areas.
The MEU Study Team projected the cost of taking wholesale distribution
service under SDG&E's WDAT and developed projections for the initial cost of
construction, the distribution infÌastructure necessary to serve the Greenfield areas. The
MEU Study Team then developed a projected electric supply portfolio, including long
and short-tenn power purchase contracts and renewable energy contracts. The study
showed that a stand-alone Greenfield utility was not of sufficient size to support the
development of an internal generation project by the City. Therefore, the projected
power supply for the Greenfield utility is 100% contract based.
In addition to the economic benefits to be derived over the study period,
the development and operation of Greenfield projects also produces other non-financial
benefits to the City. Importantly, the operation of the City's Greenfield projects will put
the City into the utility business, provide City personnel with experience in operating an
electric utility, and provide the City with the beginnings of an electric distribution
infrastructure. Moreover, as discussed below, the Greenfield option can be readily
combined with a CCA program to optimize savings to customers within the City and is
easily absorbed as part of a municipal distribution system if the City later decides to fonn
an MDU and acquire and operate the electric distribution facilities within the City
boundaries.
b. Recommendation
The MEU Study Team has concluded that the development of Greenfield
Projects within the City is both economically feasible and desirable and recommends that
the City immediately implement plans to develop Greenfield projects in the Mid-
Bayfront, Eastlake/Otay Ranch Area and Sunbow planning areas for operations in 2006.
50
VIII. CONCLUSIONS AND RECOMMENDATIONS
3. Combined CCA and Greenfield Development
a. Analysis
The detailed economic and financial analysis performed by the MEU
Study Team demonstrates that the City can obtain the greatest potential benefit in the
short term by forming a CCA and simultaneously pursuing Greenfield project
opportunities. Under the most beneficial option, the City would build or acquire equity in
a generation project (130 MW), preferably within the City, to supply the combined
CCAlGreenfield loads, The CCA program would give the City the operational scale
required to effectively source electricity for the CCA and Greenfield customers and
successfully compete with the electric supply portfolio ofSDG&E.
In implementing the combination of CCA and Greenfield projects, the
City can capture the benefits of CCA in areas where there is presently an SDG&E
distribution infÌastructure and realize commensurate savings on the electric energy
component for Greenfield areas, thus significantly increasing the cost effectiveness of the
Greenfield projects.
Based on the financial pro forma performed by the MEU Study Team, the
combined CCAIGreenfield utility option, using City-owned generation, would produce
annual savings or benefits amounting to $14.9 million in 2006 and increasing to $31.7
million in 2023 (again with significant reductions in savings or benefits in the 2011-2014
time /Tame). Over the study period savings or benefits are projected to amount to $122
million.
To implement a combined CCAlGreenfield utility option, the City would
be required to invest some $78 million in a new generation facility and $13.8 million for
the new distribution facilities in the Greenfield development areas.
b. Recommendation
To optimize savings and benefits to the City and its customers, the MEU
Study Team strongly recommends that the City implement the combined CCAlGreenfield
utility option in the immediate future. The MEU Study Team estimates that a CCA
program could be operational by mid-2005 (assuming that the CPUC issues final rules
and regulations by mid-2004). With respect to Greenfield development, the MEV Study
Team estimates that the initial Greenfield project could be implemented in a 15 to 20
month time /Tame depending upon the construction schedule and building occupancy
within the designated Greenfield areas. Thus, a combined CCAlGreenfieid operation
could be implemented at least by 2006.
51
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VIII. CONCLUSIONS AND RECOMMENDATIONS
4. Municipal Distribution Utility
a. Analysis
Based upon the pro forma financial analysis performed by the MEU Study
Team, a City-owned MDU would, under the MDU Generation Supply Strategy (i.e., with
at least 130 MW of in-City generation), realize $12.3 million/year in savings in 2006 and
increasing to $28.7 million in 2023. Total savings through 2023 would amount to $109
million. Savings would be substantially reduced in the 2011-2014 time/Tame due to the
expiration of SDG&E's obligations under its contracts with DWR.
Under an MDU Contracts Supply Strategy (i.e., under which the Chula
Vista MDU purchases all electric power requirements in the market and pays related
transmission costs), the MDU would suffer losses in the first eleven years and realize
only modest savings in the period /Tom 2017 through 2023. Based upon the pro forma
results, the MEU Study Team has concluded that an MDU that relies exclusively on
market purchases of wholesale electricity to serve the entire load requirements of its
customers would not be a cost-effective option for the City.
The MDU option would require a substantial investment in distribution
infTastructure to distribute electric power to the customers of the City's MDU, including:
distribution substations, primary distribution transformers, primary distribution wires and
poles, final line transformers, secondary distribution feeders, and meters. It was assumed
that the City would acquire these facilities /Tom SDG&E by negotiated purchase or
through the exercise of the power of eminent domain.
For purposes of this feasibility analysis, the MEU Study Team relied on
information provided by SDG&E, the City's tax records, the CPUC, the Federal Energy
Regulatory Commission (FERC) and upon industry standard practices to estimate the
value of the SDG&E distribution system at $170 million. Using this acquisition cost
figure, the MEU Study Team estimated the combined system acquisition and start-up
costs (including distribution facilities, customer service call center, billing equipment and
service vehicles) at $185 million.
In addition to the capital costs necessary to acquire the SDG&E
distribution system and establish necessary interconnections and bulk power supply costs,
the MEU Study Team estimated the distribution operations and maintenance costs and
has taken into consideration the required payment for "exit fees" and other non-
bypassable charges mandated by legislation and related CPUC orders and any applicable
Federal stranded costs which may be required under FERC rules or regulations. The
MEU Study Team has also factored in the loss of fTanchise and/or tax revenues.
In forming and implementing an MDU, the City can expect enormous and
continued opposition by SDG&E, both legally and politically. Depending upon the
strength of the opposition by SDG&E, the litigation costs could substantially increase the
implementation costs and substantial delays could result.
52
-- ----------.---------------
VIII. CONCLUSIONS AND RECOMMENDATIONS
b. Recommendation
The MEU Study Team has concluded that, in the long tenn, the fonnation
of an MDU, which obtains generation /Tom City-owned facilities and owns and operates
a utility distribution system is a feasible option notwithstanding the substantial capital
investment required and higher risks and potential litigation costs involved. In making
this recommendation, the MEU Study Team notes that the NVP of savings or benefits
over the study period is less for the MDU option than for the Combined CCAlGreenfield
option (with a Generation Supply Strategy). This is primarily due, of course, to the
capital costs necessary to acquire the SDG&E distribution system. At the same time, the
MEU Study Team believes that the long-tenn benefits resulting from the City's
ownership of the electric distribution system (i.e., local control, asset appreciation, and
independence /Tom SDG&E and the owner/operators of the transmission system) may
justify the City's decision to establish and operate an MEU.
For the reasons explained in the body of this Report, the MEU Study
Team recommends that the City first implement the CCAlGreenfield options and defer a
decision on the potential implementation of the MDU structure until the 2008-10 time
/Tame.
If the MDU continues to be the more beneficial option in 2008-2010, as
this analysis predicts, the City would, at that time, have four years of power supply
operations (CCA), distribution system operation and maintenance experience (for the
Greenfield portion of the City) to assist it in making a decision on whether to fonn and
operate a full service MDU.
5. Joint Powers Agency and Municipal Utility District Options
a. Analysis
If the City elects to establish a full service MDU and acquire the electric
distribution facilities of SDG&E, two other long-range options will be available to the
City's MDU. The City, through its MDU, may be able to participate in an existing Joint
Powers Agency (JPA), or fonn, in partnership with another community, unincorporated
territory, or public utility entity, a Municipal Utility District (MUD).
Both of these options provide the City with alternatives which would
spread risk, expand the City's options for generation and transmission resources and
allow the City to more effectively achieve the economies of larger scale projects and
operations. For the reasons explained in this feasibility report, the MEU Study Team has
concluded that neither the JP A nor the MUD structure is suitable for use as a vehicle for
establishing an MEU. Both options involve the development of arrangements,
agreements and infTastructure with other publicly-owned utilities or local governments.
The development of these arrangements would further complicate and delay the
53
... .n.... ..-----.-..-.....-......-.. ...-..........-.
VIII. CONCLUSIONS AND RECOMMENDATIONS
implementation process and would require the City to relinquish local control in the
development of its MEU structure.
b. Recommendation
At such time as the City establishes an operating MEU, it is recommended
that it reevaluate the feasibility of participating in a JP A or fonning an MUD.
B. Roll Out Strategy
As part of this feasibility analysis, the MEU Study Team has provided a
detailed listing of the major and critical steps necessary to implement each of the
recommended MEU options. The MEU Study Team has also provided a Gantt Chart
showing the time-line requirements for each major step or task necessary /Tom the
initiation of the process to operations. See Gantt Charts below and in Appendix C,
Section V at 130-32.
1. CCA - Implementation Schedule
The MEU Study Team recommends a two-track approach to evaluate and
implement a CCA project. Within Track One the following tasks are required
immediately: (I) conduct an orientation session for Elected Officials and Staff on this
option including a review of this feasibility analysis; (2) continue active participation in
the CPUC's proceedings and workshops for the development of costs, credit rules and
regulations; (3) update the feasibility analysis with infonnation /Tom the CPUC
proceedings; and (4) develop the CCA Implementation Plan, adopt the Implementation
Plan at a duly noticed public hearing, pass an Ordinance to implement CCA per the
Implementation Plan and file the Implementation Plan with the CPUC by July 200422.
Under Tra,ck One, the MEU Study Team anticipates that the CPUC approval of the City's
Implementation Plan would take between four to seven months.
Assuming CPUC approval of the City's CCA Implementation Plan by
January 2005, the following tasks would be initiated simultaneously within Track-Two:
(a) the City would execute a Service Agreement with SDG&E; (b) complete
development of CCA metering facilities; and (c) complete customer notification
regarding opt-out provisions. Between July 2005 and January 2006 the following
iterative and on-going activities should be conducted by the City: (1) activate Energy
Supply Resource Plan; (2) address Load Forecast and Optimize Scheduling; (3) manage
supply portfolio and risk management (4) process financial settlements; and (5) produce
operating statements and reports. Under this schedule and based on these assumptions,
the MEU Study Team anticipates that a CCA project could be operational by early 2006.
Please see Section IV.C.6 at 58-60 for more detail on this Implementation Schedule.
22 Although the CPUC has not approved rules for the implementation of the CCA program, the draft
rules and CPUC precedent indicate that parties have submitted applications for the CCA program.
54
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VIII. CONCLUSIONS AND RECOMMENDA nONS
2. Greenfield - Implementation Schedule
Recognizing that the City has previously passed an ordinance to fonn a -
municipal utility and, working back /Tom the date that occupancy of the Greenfield areas
would be initiated (as early as July 2005), the MEU Study Team recommends that the
following steps be taken by the City to implement the Greenfield option: (I) consult with
electric distribution design fInnS and developers to design and specify system
requirements for the Greenfield Project -- initiate in January 2004 and complete by April
2004; (2) following the development of the design and system requirements, the City --
would need to detennine the interconnection requirements, which includes an assessment
of technical requirements and costs to achieve interconnection of the distribution system
-- initiate in April 2004 and complete no later than mid-November 2004; (3) evaluate and
assess projected loads, costs and benefits -- initiate in November 2004 and complete by
mid-December 2004; (4) based upon the final evaluation of the load studies and forecasts,
the City would need to tailor and implement a resource plan and schedule power and
update power delivery schedules; (5) the City would initiate a human resource plan, in
December 2004 and complete staffmg by February 2005; (6) developers would complete
infTastructure construction (trenches, conduits, vaults and transfonner pads) in the March
to April 2005 time /Tame; (7) high voltage contractors would install conductors,
transfonners, service drops and metering in April 2005; (8) contractors would install
streetlights, traffic signals and landscape irrigation facilities (peripheral equipment) by
mid-May 2005; and (9) utility service could be provided between mid-May and mid-June
2005 or be scheduled to coincide with an occupancy. Please see Section IV.D.6 at 77-79
for more detail on this Implementation Schedule.
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VIII. CONCLUSIONS AND RECOMMENDATIONS
3. Combined CCAlGreenfield - Implementation Schedule
The implementation schedule for the CCAlGreenfield entails utilizing the
major and critical steps identified in the implementation schedules for CCA and
Greenfield options and combining them. The major and critical steps and timelines
would remain unchanged.
4. MDU - Implementation Schedule -
If the City elects to form an MDU, the MEU Study Team has identified -
the following major and critical steps: (I) During the first year after electing to pursue the
MDU option, the City should complete the feasibility and implementation plan, which
includes: (a) Distribution System Survey and Valuation, (b) Severance Plan and Cost --
Study, (c) Energy Resource Plan, (d) Human Resource Plan, (e) Facilities Plan, (t) Pro
Forma Update, (g) Finance Plan, (h) Governance Plan, and (i) Implementation Plan. (2)
by the end of the first year, establish public interest; (3) begin the condemnation process:
(a) offer to purchase the distribution facilities of SDG&E, (b) public hearing on finding
of public interest and necessity, (c) adopt Resolution of Necessity to condemn property,
(d) second and final offer of purchase to be extended to SDG&E, (e) judicial review of
Resolution of Necessity, (t) conduct the condemnation proceeding; and (4) execute
Implementation Plan once condemnation proceedings have been completed and an Order
for Possession has been entered by a court of competent jurisdiction. If the City elects to
implement the MDU option in the 2010 time /Tame, after the establishment of the
Combined CCAlGreenfieid option, as recommended by the MEU Study Team, the City
would commence the MDU Planning and Implementation elements in mid-2008. Please
see Section IV.F.6 at 127-131 for more detail on this Implementation Schedule.
--
58
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Public Copy
City Clerk's Office ...
Attachment 5 ~
CITY OF CHULA VISTA ~
MUNICIPAL ENERGY UTILITY ~
FEASIBILITY ANALYSIS ë
..
.
REPORT ~
..
. ~
Submitted Jointly by:
DUNCAN, WEINBERG, GENZER & PEMBROKE, P.c.
McCARTHY & BERLIN, L.L.P
AND
NA VIGANT CONSULTING
. S
c
"
.
S
Ô
March 19,2004
*
Printed on recycled paper
TABLE OF CONTENTS
I. INTRODUCTION..,.............,................,.....,.,.....,.........,........ 1
A. Background..."....."......"......,..............."......."....".,..... 1
B. City Energy Strategy,.....",...",.....,.,.......,......,................ 2
1. Overview of City's Energy Strategy...................,....... 2
2, Energy Strategy Discussion....,......,.........,.,.....,........ 3
3. Incorporation of City's Energy Strategy Into the
Feasibility Analysis..................,...,.....................,... 4
C. Existing Utility Franchise with San Diego Gas & Electric............ 5
D. Organization of Report.. ....... ..,... ...... .......................... .... ...6
II. CITY ENERGY CUSTOMERS, PROJECTED ELECTRIC LOAD
ANDPOWERSUPPLY........,.......................,...,..............,........8
A. Summary.",....,......"""....".....,.,.....".........".......,......,.8
B. Current and Future Electrical Loads".,....,...,......"......",....... 9
1. Electricity Sector Load Shape... .."., ... ...... ".... ..,... ... 10
2. Long-Term Electric Load Forecast"......".,.....,......... 13
a. Greenfield Area Load Forecast.., ............... ......, 16
C. Power Supply...........................,................,........,........, 21
1. In-City Generation".....".........."......",...........,...... 21
2, Distributed Generation.".,........"........,...".......,..". 23
III MEU STRUCTURAL OPTIONS......,..,..................................,... 25
A. Summary...,.....",.....,.,...,...",...."...,....,..""......",.,..... 25
B. Description ofMEU Options.........,....................................25
1. Community Choice Aggregation.....",......,...,........,.. 25
2, Greenfield Development...",..,.""..........",......".... 26
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TABLE OF CONTENTS
3. Combined Community Choice Aggregation/Greenfield... 26
4, Munièipal Distribution Utility..,.....,......,.......,....,.... 26
5, Joint Powers Agency/Municipal Utility District." . . . ... ... 26
IV EVALUATION OF CHULA VISTA'S MEU OPTIONS........,.......... 29
A. Introduction,... ..,.. ".... ..,.. "" ...... .".. ...... "". ,.... ..... .", ... 29
B. Summary and Evaluation,....,..""...."",.........",............,,. 31
C. Community Choice Aggregation,......"........."...,........."",. 39
1. Customer Base...",."... ........."..........,..........,...,.. 39
2. Functional Elements,.........,...............,.................. 40
a, Inftastructure Requirements,.....,..",.........,..". 40
b, Resource Management..,..".......,...,.,.....,..".. 41
c. Operations and Maintenance....".."..........."... 44
d, Human Resource Requirements..............."...... 44
3, Cost-Benefit Analyses..... .." .",., ...... ." ." "".. ...... ." 45
a. Financial Analysis....,...,..,.,....................,.... 45
b. Financial Analysis Structure........,...........,....., 46
c, Pro Fonna Results....,...............,................., 47
(I) CCA - Generation Supply Strategy.......... 48
(2) CCA-Contracts Supply Strategy,..,.......... 52
d. Intangibles..............,........"...............,....... 56
(I) Benefits,...",..",.........."."""........... 56
(2) Risks......"""".,......."""""..,......... 56
4. Legal/Reguiatory...... '" ",... ... ...", "".. ".... ...... ...... 57
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TABLE OF CONTENTS
5. FinancingOptions."".........,.,.......",.........",......... 57
6, Implementation Schedule",.........,......,....,...........,.. 58
a. Major and Critical Steps............,..,................. 58
(I) Track 1- Tasks....,...,.....,.....,.....,...... 58
(2) Track 2 -Tasks..................,.......,...... 59
b. .Timelines...",.........",.,..".."".........,......, 60
7. Recommendation...,..".......".".......",.....,...,........ 60
D, Greenfield Development...".,.",...."""......",.........."...... 61
1. Customer Base..,...",......",........".",......,..."....... 61
2. Functional Elements."",.........",......",.",.......,..,... 62
a. InfTastructure Requirements,........ ",... ...,.. ."... 62
(I) Distribution System InfTastructure...,...,.. 62
(2) Interconnection/WDAT Costs,............... 64
b. Resource Management....".,.",....,..."""....... 65
c, Operations and Maintenance.....""",.......".,.... 67
d. Human Resource Requirements."...".......".",... 67
3. Costs and Benefits...................,......,.,......,..........., 70
a, Financial Analyses.....,................................. 70
b. Financial Analysis Structure... ....,. ........ .......... 71
c. Pro Forma Modeling Results..,.,."",..........",.., 72
d, Intangibles........,...........,.............,............. 75
(I) Benefits""........"".....",..""..""...... 75
(2) Risks..........,.......,.......,...,.,............. 76
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TABLE OF CONTENl
4, Legal/ReguJatory,. ,... ..,.. ,... ..,. ,. ... ..",. ...... "....... ,.. 76
5, FinancingOptions",...,.."...."."....",.,....."........,.., 76
6. Implementation Schedule...."........,..................".... 77
a, Major and Critical Steps..,...,.....",....,."....... 77
b, .Timelines,.....,........".......,.......,.............. 79
7, Recommendation""..".",..."""....".....,...,.......,... 79
E. Combined Community Choice Aggregation/Greenfield
Development.. .".....,... .....,.................."........,............. 80
1. Customer Base......",......",.......,......,.........,........ 81
2. Functional Elements,....,.........,..,.......,.................. 83
a. In/Tastructure Requirements,..... ..,....... ..,.. ...... 83
(1) CCA Infrastructure,............................. 83
(2) Greenfield Infrastructure...................., 83
(a) Distribution System Infrastructure. .. 83
(b) Interconnection/WD AT Costs. . . . ,. 84
b, Resource Management.....,.........."........"..... 84
c. Operations and Maintenance,.......,.........",."... 86
(I) Operations and Maintenance - CCA...., .... 86
(2) Operations and Maintenance - Greenfield... 86
d, Human Resource Requirements..,...",.........".... 87
(1) Human Resource Requirements - CCA...". 87
(2) Human Resource Requirements -
Greenfield..................,............,.,...... 87
3, Costs and .Benefits.",........",.......",........."........... 87
iv
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TABLE OF CONTENTS
a. Financial Analysis.............................."....... 87
b. Financial Analysis Structure,.......................... 87
c. Pro Fonna Results..........,............................ 90
(I) CCAlGreenfieid - Generation.....,......... 91
(2) CCAlGreenfield - Contracts.................. 93
4, Legal/Regulatory.....,... .......,......,.....,........,......... 96
5, Financing Options...... ...........,......................"...... 96
a. CCA Financing".........."............................ 96
b. Greenfield Financing......".............,........,..... 96
c. Methods of Financing,...........",........,...,..... 96
6. Implementation Schedule..,..... ........ .".,...... ."......... 97
a. Major and Critical Steps,........",....,.......... .... 97
b. .Timelines.",...........".............................. 97
7. Recommendation.... ..."... ...... ...."... ,.."....... ......... 98
F. Municipal Distribution Utility.,.........,...,............"...."",... 99
1. Customer Base...",...,...........",......,.................... 100
2. Functional Elements... ........,...",........................", 100
a. Inftastructure Requirements".... ...,.,...... ."... ,.. 100
(1) Distribution Infrastructure..... .......... .,... 100
(2) Supply Portfolio Operations InfTastructure.., 101
b. Resource Management,..",...........""..."..........102
(I) Energy Supply - Generation",...""..........102
(2) Energy Supply - Contracts",................., 103
v
TABLE OF CONTENTS
a. Financial Analysis....................................... 87
b, Financial Analysis Structure......... .,.... ............ 87
c. ProFonnaResults,...................................... 90
(I) CCAlGreenfieid - Generation... "....,.. .,. 91
(2) CCAlGreenfield - Contracts................,. 93
4, Legal/Regulatory........,...........,.....,......... ............ 96
5, Financing .Options,.......................................,...... 96
a, CCA Financing.......................................... 96
b, Greenfield Financing.................................... 96
c. Methods of Financing"."""".""..",............ 96
6, Implementation Schedule....................................... 97
a, Major and Critical Steps............................... 97
b. .Tirnelines...,...,......,....,....,...................... 97
7, Recommendation. ..... ...... ...... .,.... .,.... ".... ",.., ",... 98
F. Municipal Distribution Utility.... "". "",. """ .,... ....... ...... ... 99
1. Customer Base...................,....",......",............... 100
2, Functional Elements...............",...",...,................. 100
a. Infrastructure Requirements,.. ",... ",... ...... ...... 100
(I) Distribution Infrastructure...........,. ....... 100
(2) Supply Portfolio Operations Infrastructure... 101
b. Resource Management...........,."",.""..""..,....102
(I) Energy Supply- Generation",...",...",.,...102
(2) Energy Supply- Contracts.....,............... 103
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TABLE OF CONTENTS
c. Operations and Maintenance........................... 104
(1) Distribution Operations and Maintenance
Costs.............,................,................ 104
(2) Electric Portfolio Operations..............,... 105
d. Human Resource Requirements.............,.......... 106
3, Costs and Benefits......,..,...................................... 107
a. FinanciaiAnalyses."..............."...........,...,... 107
b. Financial Analysis Structure.................,......... 108
c. Pro Forma Results....................................... III
(I) MDU - Generation Strategy.................. 111
(2) MDU - Contracts Supply Strategy...... .... 114
d. Intangibles.....,................,..,...............,...,.. 118
(I) Benefits... ....... ..."... ...... ...... ... ...... .,. 118
(2) Risks.................,..,..............,.....,.... 122
4. Lega1/ReguIatory.. ""...... ...... ..,... ."... ""..... ......". 123
a. Exercise of the Power of Eminent Domain", . . ..... 123
b. Cost Exposure............",...",..................." 124
(I) Acquisition Costs...",.,.."..,............... 125
(2) Severance Costs............,....,............... 125
(3) Interconnection Costs.....,................... 125
(4) California Cost Responsibility Surcharge
for Departing Load..,......,..,................. 125
--- 5, Financing Options........,...",...",...",.......................126
.. 6, Implementation Schedule....................,...."...",...." 127
-- vi
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TABLE OF CONTENTS
a, Major and Critical Steps................................. 127
(1) Focused MDU Feasibility and
Implementation. ..... ",... ..... ..........". ,.. 127
(2) Implementation Plan Tasks.....................129
b. .Timelines,..",.............,..",....................., 131
7, Recommendation... .,. ...... ..,. "". .,.... ............... ",... 132
G, Joint Powers Agency/Municipal Utility District...... ...... '" ...... 135
1. Joint Powers Agency.....,...................,................ 135
a. Fonnation Requirements... ...... ............... ...... 135
b. Benefits..........."""",.............",.............., 136
c. Risks...............,.................,...................., 136
2, Municipal Utility District... '" ,.,.,. ...... ."... ...... ......,.. 137
a. Fonnation Requirements........,..................... 137
b. Benefits.....".,.........",.............................. 138
c. Risks.....,.,.",......",.........",..................." 138
3. Implementation Schedule......"",.......",.........",...... 139
4. Recommendation....""........"........"".......",........ 139
H, Natural Gas",......"",.,...",..".....""......".................... 140
1. Feasibility of Acquiring Gas Distribution Facilities in
Chula ..Vista......................................,..............., 140
2, Gas Demand Forecast,...................,.......,..........,..... 141
3, SDG&E Gas Transportation Revenue......",.............., 143
4, Estimate ofChuia Vista Operating Costs......,.....",...." 146
5, SoCai Gas and SDG&E Transmission Costs.",....,.,."..., 149
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TABLE OF CONTENTS
6. Capital Cost Estimate...................,.....,................... 150
7. Estimated Benefit of Utility Ownership............,..... ...... 150
8. SDG&E BCAP Proposal.......................,................. 151
I 9, Conclusions............,.,.....................".......... .........152
II
V CONCLUSIONS AND RECOMMENDATIONS..........,................... 156
II A. Discussion and Comparison of Recommended Options..............,156
II B. Electric Service.........................................,....,............. 156
1. Community Choice Aggregation............",............... 157
II 2 Greenfield Development."... .............. .."... ",......... 158
II 3, Combined CCAlGreenfield Development..................... 160
4. Municipal Distribution Utility......"....",....,.,..,........ 161
-- 5. Joint Powers Agency and Municipal Utility District
, Options"....",...",....,..................................:..... 163
-- a. Joint Powers Agency................................. 164
i
- b. Municipal Utility District.",.. .....,... ...,..... ...... 164
I C. Roll Out .Strategy...,...................,.,......,....................... 165
-
1. CCA - Implementation Schedule..,........................... 165
I] 2. Greenfield - Implementation Schedule....................,... 168
- 3. CCAlGreenfield - Implementation Schedule.................. 170
4, MDU - Implementation Schedule.....,........................ 170
-
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,
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~ viii
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TABLE OF CONTENTS
Charts/Graphs
Section II
2002 Chula Vista Energy Use By Customer Class"........"............". 8
City Versus Regional Energy Use..............,.............................. 9
Chula Vista 2002 Hourly Electric Demand (MW) ",........,............,., 10
SDG&E Static Load Profile Load Factors.................................... 10
Cooling Degree Days."",........,."...........""........................... 11
Comparison of Chula Vista and Sacramento Electric Demand (MW). . ., 12
Chart I-Peak Day Demand.........................,................. 12
Chart 2-Monthly Peak Demand.....""..................."........ 12
Chart 3 -Annual Hourly Demand""........".........,.........." 12
Chula Vista's 2002 Peak Load (MW).......................................,.. 13
20-Year Load Forecast 2004-2023..",.......",....".........",...."...... 15
Map - Greenfield Development Areas.."..,.....",......,......""........ 18
Greenfield Land Use Inventory Projected Through 2020
(Residential and Non-Residential)... ,.......,.....,... ................ 19
Greenfield Land Use Inventory Projected Through 2020
(By Percent of Land Use)........,..................,.................. 19
Section IV.B
Summary of Savings Estimated for Each Option Ranked by NPV of
Savings from 2006 through 2023"...",...,...,....""...",.....,. 31
City of Chula Vista's MEU Options - Annual Cost Savings
Versus SDG&E Rates ($)..........,.........,....................,... 31
Table 11-1 - CCA - Comparison of Projected Average
Rates ($/kWh)..........,.......,........ .......,.................,.... 34
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TABLE OF CONTENTS
Table 11-2 - Greenfield - Comparison of Projected Average
Rates ($/kWh)..... .................................................... 35
Table 11-3 - Combined CCAIGreenfield - Comparison of Projected
Average Rates ($/kWh)..... ........................................... 36
Table 11-4 - MDU - Comparison of Projected Average Rates ($/kWh)... 37
Section IV.C
CCA Projected Customers, MWh, and Peak MW By Year.................. 39
System .Requirements..,..........,.....,.....,.................................. 41
Power Purchase Contracts - CCA Option...........................,.,...,... 43
Renewable Energy Contracts- CCA Option................................. 43
CCA Human Resource Requirements.......................................... 45
Power Supply Portfolio Energy Costs ($)........,.............................. 47
Pro Fonna Swnmary and Projected Savings - CCA Generation
Supply Strategy (Millions of Dollars Per Year)... ................... 49
Chart 1: Comparison of CCA Costs Based on CCA Generation
Supply Strategy.........................",.,...",.....................". 50
Chart 2: CCACost Components ona PerMWh Basis............",......... 51
Pro Fonna Swnmary and Projected Savings - CCA Contracts
Supply Strategy (Millions of Dollars per Year) ...... ............ ... 53
Chula Vista Municipal Electric Utility Annual Cost Savings $(000).".,. 54
Chart 3: Comparison ofCCA Costs Based on Contracts Supply
Strategy..,................................,........................,........ 55
Chart 4: CCA Cost Components on a Per MWhBasis....""....,.,......... 56
Section IV.D
Greenfield Projected Customers, MWh, And Peak MW By Year. . . '" . ,.. 62
Potential Greenfield Development Areas",..............".,...,............" 63
x
A
TABLE OF CONTENTS
Power Purchase Contracts - Greenfield Option",............".""........." 65
Renewable Energy Contracts - Greenfield Option..,..""..........."...., 66
Greenfield Human Resource Requirements.."...........",..,."......""" 68
Greenfield Areas Projected Customer Populations",............",...,..... 69
Minimum Portfolio Operations - Greenfield....................,.....,......... 69
Pro Forma Summary and Projected Savings - Greenfield
Contracts Supply Strategy (Millions of Dollars Per Year)......,.... 74
Chart 5: Comparison of Greenfield Costs Based on Contracts
Supply Strategy.............................,.................. ,............75
Section IV.E
CCA Projected Customers, MWh And Peak MW By Year
Excluding Greenfield Customers".............",.............",..,., 82
Greenfield Projected Customers, MWh, And Peak MW By Year. .. . . . '" 83
Power Purchase Contracts - CCAlGreenfieid Option...",.........,.,...... 85
Renewable Energy Contracts - CCAlGreenfield Option.,."......,....,.... 86
2006 Energy Resource Costs ($) by Supply Strategy,....,...........,...... 90
Pro Forma Summary and Projected Savings - Combined
CCAlGreenfield Generation Supply Strategy
(Millions of Dollars per Year)...,.............,..............,......... 92
Pro Forma Summary and Projected Savings - CCAlGreenfield
Contracts Supply Strategy (Millions of Dollars per Year) .....,.... 94
Chula Vista Municipal Electric Utility Annual Cost Savings $(000)........,95
Section IV.F
MDU Projected Customers, MWh, And Peak MW By Year.....,............ 100
System Requirements..,.............................................,....,........, 102
Power Purchase Contracts - MDU Option......,..",.........",...".",...... 103
xi
TABLE OF CONTENTS
Renewable Energy Contracts - MDU Option...",."",...",...""..",...",104
MDU Human Resource Requirements.......................................... 107
2006 Energy Resource Costs ($) By Supply Strategy......................... 110
Pro Fonna Summary and Projected Savings - MDU Generation
Supply Strategy (Millions of Dollars Per Year) ... .................. 112
Chart 7: Comparison ofMDU Costs Based On Generation
Supply Strategy".".",................................................... 113
Chart 8: MDU Cost Components On A PerMWh Basis..................... 114
Pro Fonna Summary and Projected Savings - MDU Contracts Supply
Strategy (Millions of Dollars Per Year) ................,......,........,115
Chula Vista Municipal Electric Utility Annual Cost Savings $(000),........ 116
Chart 9: Comparison ofMDU Costs Based On Contracts
Supply Strategy."..................",...."........... ....................117
Chart 10: MDU Cost Components OnA Per MWh Basis..................... I 18
California Electric Utilities,..",...,.,.......................,...."",......"....121
Chula Vista Municipal Electric Utility Annual Cost Savings $(000),........ 133
Section IV.H
Figure I: SDG&E GPC v, Topock Index Price....,..,.................,....... 140
Table 1: Composition of 2002 Chula Vista Gas Demand........,............ 142
Figure2: Composition of Gas Demand 2002..,...................,........... 142
Table 2: Gas Demand Forecast................,................................. 143
Table 3: Forecast SDG&E Gas Transportation & Distribution
Rates ($Thenn) .........................,..,.....................,........ 144
Table 4: Sempra-Wide EG Rate (2002 BCAP) ..,..,........................ 145
Table 5: Forecast SDG&E T&D Revenues from Chula Vista ($000)..,.. 146
Table 6: Long Beach and Palo Alto Gas Delivery Costs......,....,......... 147
xii
I
TABLE OF CONTENTS
Figure3: .Sample Comparison.......,............................................ 148
Figure 4: Muni Gas LDC Operating Costs per Therm.....,..,.....,.....,.., 148
Table 7: Estimated Benefits of Gas Utility Ownership in Chula Vista...,.. 151
Table 8: Economics of Serving South Bay Power Plant.....,........,...... 154
Section V
CCA Implementation Schedule..,.,...,.....,.....,...,.......................... 167
Greenfield Implementation Schedule............... ....",.,..,.,.""..",...", 169
MDU Implementation Schedule.,.....,........,.........,.....,...,......,....... 171
xiii
1. INTRODUCTION
-
-
SECTION I
- INTRODUCTION
-
1. INTRODUCTION
I. INTRODUCTION
The purpose of this section of the Report is to provide infonnation on the
background for this Report, a review of previous City activities, and a discussion of the fonnat of
the remainder of this Report.
A. Background
On April 15, 2003, the City Council for the City of Chula Vista (Chula Vista or
City) authorized the retention of the team of Duncan, Weinberg, Genzer & Pembroke, P.C.
(Duncan), McCarthy & Berlin, LLC., and Navigant Consulting Inc. (NCI) (collectively the
Municipal Electric Utility (MEU) Study Team) to undertake the financial, legal and technical
feasibility of various possible municipal energy business structures and alternatives.
Specifically, the MEU Study Team was retained to perfonn what the City had described as its
Municipal Electric Utility Feasibility Analysis, to answer the questions: Is it desirable for the
City to pursue the implementation of an MEV? If so, what form of MEV?
In an effort to assist the City, the MEU Study Team submitted a proposal that
included a multi-disciplinary methodology to address these two critical questions, as well as
addressing the following requests /Tom the City:
1. Consider and incorporate, if appropriate, previous City actions and analysis
contained in the City's adopted Energy Strategy and Action Plan.
2. Identify the characteristics of Chula Vista that present opportunities or challenges
to MEU irnplementation.
3. Describe the various fonns of MEUs; give California examples where possible.
Identify the risks/benefits, pros/cons of each.
4. Describe step-by-step, the MEU fonnation and implementation process. Include a
timeline. Include descriptions of any required approvals /Tom the CPUC, FERC,
or other governmental agencies.
5. Estimate and describe the financial and human capital resources required for each
stage of municipalization.
6. Estimate and describe the costs, risks, potential environmental impacts and
vulnerabilities of MEU fonnation and implementation. How can costs be
managed and risks mitigated?
7. Describe the current legal, regulatory, political, and economic framework in
which an MEU would operate, the challenges and opportunities presented
thereby, and approaches to overcoming and taking advantage of such challenges
and opportunities.
8. Describe the potential benefits of MEU operation in Chula Vista: In what specific
ways could a Chula Vista MEU deliver benefits not currently provided by
SDG&E?
I
1. INTRODUCTION
9. Provide case studies, which illustrate both the potential benefits and pitfalls of an
MEU.
10. Identify altemativesllower risk approaches to MEU implementation including but
not limited to aggregation (e.g. types of partnerships with SDG&E or regional
partnerships). Identify the risks/benefits, pros/cons of each. In completing this
section consider alternatives contained in the City's existing Energy Strategy and
Action Plan.
11. If justified by the analysis, recommend an initial MEU business model that would
implement City's energy objectives. Provide a proposed outline of a Focused
Feasibility Study and Implementation Plan for the recommended MEU.
The starting point for this feasibility analysis was to review previous activity
undertaken by the City, including the previously adopted "City of Chula Vista Energy Strategy
and Action Plan."
B. City Energy Strategy
On May 29,2001, the City Council passed Resolution No. 2001-162 adopting the
City's Energy Strategy and Action Plan (City Energy Strategy), The City Energy Strategy
marked the culmination of an assessment of the City's energy management options, which was
prepared by MRW and Associates. As Task No. I of the MEU Analysis, the MEU Study Team
reviewed the MRW report, the City's Energy Strategy and the Energy Strategy Status Update
provided by the City.
1. Overview of City's Energy Strategy
The MR W Report (and City Staff) developed a portfolio of twelve options for the
City to consider. The options were grouped into "highly recommended," "promising," and
"higher risk" strategies. The highly recommended strategies were deemed to have low or
manageable risk and have the potential for short-tenn payoffs. These included:
1. Continue and expand energy conservation projects in existing and future City
facilities;
2. Continue, expand, and promote energy efficiency and renewable energy programs
for businesses and residents;
3. Monitor the development of the California electric energy market and prepare for
the opportunity to enter into competitive supply contracts with energy service
providers to serve City electric loads;
4. Develop and implement a legislative strategy to support the City's Energy
Strategy; and
5. Continue and expand efforts to implement CO2 Reduction Plan and a GreenStar
Building Incentive Program.
2
-.....-...-.-....-- .. '---"'---"---"---",----",,,,- --- --..----.---
1. INTRODUCTION
The "promising options" were deemed to offer significant benefits; however,
additional risk with a payoff over several years was included as well. These options consisted
of:
6. Pursuit of distributed generation opportunities within the City;
7. Look for opportunities to enter into a bilateral agreement with a power generator; I
8. Partner with a third-party to build and operate generation facilities; and
9. Develop an emission offsets program based on mobile sources.
Finally, three "higher-risk options" were identified. These were deemed to
require large capital outlays, carry significant risk, and require a longer time/Tame for payoff.
- These options include:
10. Finance, own, and operate a large-scale power plant;
11. Form a municipal distribution utility (for all or a portion of the City); and
12. Become a municipal aggregator.
Resolution No. 2001-162 adopted the City's energy strategy and eight (8) options
for the City to begin or continue. The City has been pursuing options 1, 2, 5 6 and 7 above,
The MEU Study Team is also informed that the City has held discussions with the
San Diego Port Authority (Port Authority) and Duke Energy North America (Duke) regarding
the potential relocation and repowering of the South Bay Power Plant (South Bay).
Finally, on June 5, 2001, the City also passed Ordinance No. 2835 establishing
the City as a municipal utility.
2. Energy Strategy Discussion
The City has been involved in investigating its options following the failed
California energy "experiment" for well over two years. The City Staff is sophisticated
regarding the causes of the crises and several factors that continue to leave the state and the San
Diego region in a precarious position regarding long-term reliable supply of energy.
The City has adopted an Energy Strategy that provides for the City to do
essentially everything that a "typical" city can do to address citywide energy conservation,
I "Bilateral contract" is a tenD referring to a transaction in the deregulated electric energy market meaning a
contract between a generation supplier and end-use consumer that circumvents or bypasses a functioning
commodity pool, such as the now defunct California Power Exchange. All retail competition, bilateral or
other, characterized by direct transactions between end-use consumers and suppliers other than
jurisdictional public utilities was suspended by the CPUC on September 20, 2001. Hence, strategy 3
referenced above and strategy 7, are identical and not available to the City until retail completion is
reintroduced into California electric energy markets.
3
----._____m___.__- .------..-------...--..---
1. INTRODUCTION
energy education, and environmental stewardship, In addition, the City has undertaken
additional steps of pursuing distributed generation opportunities at City facilities (e.g. new police
station). All of these efforts should continue as the City moves further into the energy field.
The City is now embarking on a more aggressive energy track, which may
become the City's new energy program, one that goes beyond what the "typical" city is currently
undertaking, This strategy includes: (I) the focused re-negotiation of the electric and natural gas
/Tanchise agreements with SDG&E; (2) exploring options for City acquisition of the electric
output /Tom the existing and proposed expansion of the methanol plant to serve the new City
corporation yard and possibly other entities; (3) "Greenfield" municipal electric and natural gas
services provided to new development areas within the City (exercising the City's right to
provide utility services but avoiding condemnation of existing SDG&E distribution facilities);
(4) discussions with the Port Authority and Duke regarding the South Bay Power Plant; and (5)
conducting this MEU feasibility analysis.
The MEU Study Team commends the City on the efforts undertaken to date and
the successes that the City has enjoyed. Regardless of the outcome of the ongoing negotiations
with SDG&E and all of the other activities discussed as the new "track," the MEU Study Team
believes that the City should continue with the work begun in the Spring of 2001 with the
adoption of the City's Energy Strategy through the implementation of the MEU options
recommended herein.
3. Incorporation of the City's Energy Strategy Into the Feasibility
Analysis
The following strategies identified in the City's Energy Strategy are incorporated
into this feasibility analysis.
Power Supply
» Identify renewable resource funding options;
» Partner with third parties to build and operate generation facilities; and
» Finance, own, and operate a large-scale power plant to meet a portion of the City's
demand for electricity.
Power Supply and Regulatory Issues
» Monitor market and legal restrictions and be prepared to enter into an electric service
contract with competitive suppliers (ESPs/generators).
Municipalization Alternatives
» Become a municipal aggregator and acquire energy, at negotiated rates, for City loads
as well as all residents and businesses located with the City's jurisdiction.
4
1. INTRODUCTION
Evaluate Distribution Utility Options
J¡. From a baseline of the existing utility service provided by SDG&E, assess the overall
strengths and weaknesses of options to own and operate all or portions of the local
distribution system.
The main focus of this Report is to move beyond the current Energy Strategy and
explore the other options and opportunities as well as the challenges that the City retained the
MEU Study Team to identifY and explore. One option will be the status quo, which would be to
continue with the implementation of the current Energy Strategy and remain with SDG&E as the
full service utility provided electricity and natural gas to all loads within the City. The other
options are discussed in greater detail throughout the body of this report.
C. Existing Utility Franchise with San Diego Gas & Electric Company
San Diego Gas & Electric Company ("SDG&E") owns and operates both the
electric and gas distribution systems in the City of Chula Vista under /Tanchises granted by the
Chula Vista City Council. The original twenty-five year /Tanchise, granted in 1972 to operate
the electric distribution systems in Chula Vista, expired in 1997 and was extended for a five year
period under Ordinance No. 2746, adopted in 1998. The original /Tanchise to operate a gas
distribution system in Chula Vista, also with a 25 year term, expired in 1997 and was extended
for a five year period pursuant to Ordinance No. 2747, adopted in 1998. Both the Electric and
Gas Franchises expired, by their terms, on June 30, 2003.
Representatives of Chula Vista and SDG&E conducted negotiations respecting
the renewal or extension of the Electric and Gas Franchises earlier this year. The terms of the
proposals submitted by SDG&E for a fifty-five (55) year extension of the /Tanchises were
evaluated by tqe Chula Vista Staff and rejected as unacceptable. Once negotiations reached an
impasse in late July 2003, the City and SDG&E attempted to agree on a temporary extension of
the /Tanchises to give the City more time to evaluate its options. The City offered a 90 day
extension of the /Tanchise agreements while SDG&E offered to extend service under current
terms and conditions for a 45 day period. At this writing, the term of the fTanchises has not been
agreed upon and the parties have continued to perform under the terms and conditions of current
fTanchise agreements on a month-to-month basis.
The current /Tanchise agreements have been an important element in the conduct
of this feasibility analysis inasmuch as the terms, conditions and rates for gas and electric service
as provided in the current /Tanchises, or rate schedules promulgated thereunder, have provided
the benchmark against which all of the MEU options have been measured to determine the
feasibility of each of the MEU options analyzed by the MEU Study Team. In evaluating each of
the MEU alternatives, the impact on fTanchise fee revenue received by the City under the current
fTanchise agreements has been calculated and explicitly set forth as a cost of pursuing each MEU
option. The MEU Study Team's test for economic feasibility of any and all MEU options
5
__._0._____- ------..-
1. INTRODUCTION
requires that financial benefits of a particular option must exceed any foregone /Tanchise fee
revenue that would result /Tom the pursuit of the MEU option.
D. Organization of the Report
The remainder of this Report is structured to provide the City with significant data
and analysis to provide the City with the needed infonnation to make an infonned decision
regarding potential next steps. The Report structure is also designed to cover all of the eleven
Tasks requested by the City and they are incorporated into various sections and appendices to
provide the reader with an opportunity to follow the flow of infonnation and logic that concludes
with the recommendations of the MEU Study Team.
Section II of this Report provides both an overview of the City's energy
customers, projected load growth, an overview of the natural gas situation, and a discussion of
the viability of City-owned generation.
Section III of the Report sets forth a description and discussion of the MEU
options available for the City to consider. Specifically, Section III focuses on MEU
opportunities including: municipalization under a Municipal Distribution Utility (MDU) fonnat;
"Greenfield" municipalization; community load aggregation (CCA) for both electricity services
and natural gas services; and the creation of a Joint Powers Agency (JPA) or Municipal Utility
District.
Section IV of the Report sets forth a detailed evaluation of each of the options
considered by the MEU Study Team together with the basis for the recommendation made by the
MEU Study Team and a roll out strategy for each option.
Section V of the Report contains the MEU Study Teams conclusions and
recommendations.
Finally, the Report has four appendices: Appendix A is a list of abbreviations and
acronyms and a glossary of tenns; Appendix B discusses regulatory and legislative issues;
Appendix C is a Technical Appendix which sets forth: (I) load forecasts, (2) financial pro fonna
and asswnptions, (3) Natural Gas Regional Issues and Supply for power generation, (4)
financing options, (5) implementation schedules, and (6) Operating and Maintenance Expense;
Appendix D is a copy ofSDG&E's Pro Fonna Wholesale Distribution Tariff (WDAT).
The MEU Study Team is prepared to attend a public workshop before the City
Council and the City Staff to discuss and explain the content of the Report and to respond to
questions respecting the Report or the MEU Study Team' conclusions and recommendations,
6
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
-- SECTION II
CITY ENERGY CUSTOMERS,
PROJECTED ELECTRIC LOAD
AND
POWER SUPPLY
7
TI. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
II. CITY ENERGY CUSTOMERS, PROJECTED ELECTRIC LOAD
AND POWER SUPPLY
-
A. Summary
- The chart below shows that City electric energy loads by customer sector
for 2002 are consistent with the SDG&E system-wide average.
- 2002 Chula Vista Energy Use By Customer Class
Streetlights
1%
R.,idential
- 44%
- Medium Commmial
27%
Small Commmial
8%
However, the City is experiencing significant development in ways that will change this
energy mix. Based on the City's general plan, growth is projected to occur in all customer
segments, but especially in the medium commercial customer sector. The following table
compares 2002 segment usage for the City and SDG&E2 contrasted with forecast sector
usage for Chula Vista in 2023.
2 SDG&E 2002 FERC Form-I, page JOI,line 2, column d, system wide results.
8
._--. -- .--.---
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
City Versus Regional Energy Usage -
(MWh)
-
Chula Vista SDG&E Chula Vista
2002 2002 2023
-
Residential 305,735 44% 6,266,000 44% 568,772 42%
Small Commercial 56,216 8% 1,710,025 12% 78,154 6%
Medium Commercial 193,534 27% 3,391,622 24% 439,170 33% -
Large Commercial 142,922 20% 2,725,159 19% 250,191 19%
Streetlights 6,627 0.9% 44.442 0.3% 8,745 0.7%
Total 705,034 100% 14,137.248 100% 1,345,032 100% -
The City has been, and will continue to be, subject to strong growth in all -
energy using sectors. However redevelopment and new development are forecast to have
the greatest impact in the medium sized commercial end-use consumer sector. In the next
twenty years (see long-tenn load forecast below at 13-16) the City will experience -
growth in its overall energy requirements by more than 80% (2004-2023). As described
in Section IV.F.3.d(l) at 120-21, a municipal distribution utility comprised of the City of
Chula Vista electricity consumers projected for 2006 (recommended MEU -
implementation date) would be the 11th largest out of the state's 48 electric utilities based
on customer count and the 20th largest based on energy sales.
B. Current and Future Electrical Loads
The MEU Study Team evaluated the existing customer base for the City's -
prospective MEU, and forecasted electric loads of residential customers; small, medium
and large commercial and industrial customers; and street lighting electric demand. A
20-year load forecast includes sector growth rates and City general plan developments -
and is incorporated into financial projections for MEV structure options discussed in
Sections III and IV. 2002 energy use statistics are applied to rate class static load --
profiles3 to render sector-specific and Chula Vista-wide composite electric demand
profiles. Analysis of rate class profiles reveals significant infonnation about the City's
electric loads. The following chart shows the annual hourly electric demand for Citywide --
loads during 2002.
-
3 Static Load Profiles were developed using three years of load research interval metering
ofSDG&E's different customer classes.
9
---------
--
ll. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
Chula Vista 2002
Hourly Electric Demand (MW)
130.0
- 120.0
110.0
100.0
- 90.0
80.0
70.0
- 60.0
50.0
40.0
- 30.0
Cj:þ:"'!j¡J ~"'Cj:::j~!.:i
-~~~ ~~~~~g:
August
Annual load factor, the ratio of peak annual demand (MW) to the annual
average demand, is approximately 65 percent and is quite high when compared to other
regions in the state. This is attributable largely to the area's mild climate and lower
residential cooling electric load. Note that there are 8760 hours each year. The above
graph represents each hour from 12:00 a.m. January 1 (hour 1) to 11:00 p.m. December
31 (hour 8760).
The following table lists the annual average load factors reflected in
SDG&E's static load profiles, by customer class. The MEU Study Team applied these
load profiles when modeling the City's prospective MEU customer loads.
SDG&E Static Load Profile Load Factors
Load
Customer Sector Factor
Large Commercial/Industrial 68.9%
Medium Commercial 60.8%
Small Comercial 48.1%
Residential 54.0%
1. Electricity Sector Load Shape
The residential class load, more so than the commercial or industrial
classes, is greatly influenced by the climate. In hot, arid regions of the state, the
10
-
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
residential load experiences large load "spikes" due to the load associated with residential
(and to a much lesser degree small commercial) air conditioning. --
The following table shows the climate variations that drive air
conditioning electric loads measured in annual cooling degree-days for various cities in -
California.
Cooling Degree Days -
Chula Vista Sacramento Riverside Bakersfield Palm Springs
862 1,597 1,863 2,286 4,224 -
National Oceanic and Atmospheric Administration ~ Climatography of the u.S. Publication No. 81 30-Year
Normals 1971-2000.CDD: Difference between the average daily temperature and a base temperature value (65
degrees F) -
Compared to other Cities in California, the cooling degree-days are
minimal in Chula Vista. This has a significant impact on residential and overall system -
load shapes and a direct bearing on the cost to serve the City's electric load. To illustrate
the impact of low cooling degree-days, residential load shapes for Chula Vista and
Sacramento are compared and contrasted below. When evaluating MEU energy -
requirements, it is important to recognize, not only how much energy is consumed, but
also when the energy is consumed; i.e., the load shape. Charts I through 3 below apply
the identical amount of energy - Chula Vista's residential energy consumption for 2002 - -
to city load shapes, for Sacramento and Chula Vista, to demonstrate sector climate
sensitivity.
-
-
-
-
-
11
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
Comparison of Chula Vista and Sacramento
Electric Dcmand (MW)
Clwtl Clwt2
- ].,~ ~¡:~,~\ I
~~,~,~,#,,~, ------~--~--
(fi~o"'Y) (Moo'",)
Clwt3
- (MW) Ano""IHoŒlyDemaotd
::~ --
60.0
60.0
40.0
20.0
0.0
- ~ ¡¡¡ ~ ~ ~ ~ ~ ~ ~ i ~ ~ ~ § ~ ~ § ~ - Aooo.]Hoo"
-S"..m,"o-Ch""V(",
12
.--.---.-- --.--
,-
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
To satisfy the annual energy requirements of only Chula Vista's -
residential customers, the MEU would require a power plant with a capacity of 65 MW
and operating annually at 54 percent of its capacity. To provide the identical amount of -
energy to residents of Sacramento, a power plant with 124 MW of capacity operating
annually at 28 percent of its capacity would be required. Determination of the resulting
cost-of-service implications requires analysis of specific plant capital costs, financing,
and capacity and energy proportional cost allocation. However, the application of --
prototypical case values indicates the cost to serve Chula Vista residents is fourteen (\4)
percent less than the cost to serve the Sacramento residents the same amount of energy,
based solely on a comparison of load shapes, and hence significantly less than the costs to -
serve the other cities shown in the above table. This feasibility analysis demonstrates that
Chula Vista's residential loads are more economic to serve, attractive to generation
suppliers, and render more types of generation projects cost-effective -
Remaining sector load (commercial, industrial, and street lighting)
characteristics tend to be less climate-dependent but do not dilute the overall favorable -
load shape. The following charts reflect the 24-hour peak demand profile and annual
energy consumed by the five primary customer sectors.
Chula Vista's 2002
140 Peak Load fMW\
-
12
C"..'~m~'.
10 -
8
2
1:003:005:00 7:00 9:0011:0013:0015:0017:0019:0021:0023:00
--
(Load shapes reflect the City's existing customer loads)
2. Long-Term Electric Load Forecast
A 20-year electric load forecast for the residential sector is based on
Household (HHD) projections contained in the San Diego Regional Planning Agency's
(SANDAG) Preliminary 2030 Forecast of April 2003 and is tailored to incorporate City
\3
-------
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
planning assumptions that generally accelerate growth expectations between 2003 and
2007. Associated growth rates are structured to resolve with the SANDAG projections in
2030. In addition to the overall growth in the number of HHDs, the forecast reflects the
per capita increase in energy consumption /Tom 1990 to 2000 of 15 percent or a
compound annual growth rate of 1.4 percent.
Non-residential commercial loads are based on existing commercial loads
escalated consistent with the projected growth in non-residential building stock through
year 2020, trended through 2023. The MEU Study Team forecasts that over the 20-year
planning horizon the City will experience a growth of approximately 22,000 customers,
annual consumption growth of approximately 600 gigawatt-hours, and a peak load
growth of approximately 100 MW. This growth represents a customer increase of 30
percent, and a demand and usage increase of over 80 percent, The chart below reflects
maximum electric demand for a 20-year period (years 2004 through 2023).
14
. - - - -------------------- - ---------...
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II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
To support the analysis of MEU structure options that include the City
providing both energy commodity and distribution services to all City residents, the long-
term load forecast is divided into two primary areas: (I) existing and planned
development within areas currently served by SDG&E's distribution infTastructure, and
(2) areas being developed in which SDG&E has not built distribution infì:astructure and
where the City may opt to build and operate same (Greenfield Developments or
Greenfield Forecast).
To differentiate between potential Greenfield sites and other City
development/redevelopment areas, the MEU Study Team interviewed City Planning
Division staff' to determine the most likely areas for Greenfield electric distribution
system development. These consist primarily of the Mid-Bay/Tont, Otay Ranch and
Sunbow planning areas.
a. Greenfield Area Load Forecast
The MEU Study Team evaluated the City's General Plan Land-Use
Inventory through year 2020, wherein land-use is projected by square foot (sf) by
activity type. Between 2002 and 2020, the City projects that its electric load service
requirements will grow by 20 thousand households (HHD) and approximately
118 million sf of non-residential development.
Electricity demand and energy requirements were modeled based on
regional residential use and projected HHDs.
Non-residential growth is defined by the City Planning Division in fairly
high-level "land-use defmitions". The MEU Study Team evaluated these land-use
definitions and interviewed City Staff to further understand likely development
outcomes. Electric use "building type" profiles were assigned to each build-out area,
Based on expected development, prototypical floor-area-ratios were applied to develop
building area "footprints" or net building sf. Building type electric load profiles were
modeled using the U.S. Department of Energy, Building Energy Simulation Modeling
Program DOE-2.1.E (DOE-2). Assumptions for model inputs reflect minimum
efficiencies to enable the modeled building to comply with California Energy
Commission (CEC) Title-24 new construction building standards. Where DOE-2 model
templates were not available to model a given building type, regional sampling of
prototypical sites were applied.
In certain areas, as with land-use code 5002 (Regional Shopping Centers),
for example, composite load profiles were assembled /Tom several kinds of retail
businesses for prototypical shopping centers based on surveys of more than 19,000 retail
centers, The surveys reflect shopping center population patterns of small retail stores,
4 Mark Stephens, Principal Planner, Planning Division, City ofChula Vista.
16
... .m. _..0.__0
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
fast food restaurants, full-menu restaurants, medium variety-type department stores, large
retail stores, and grocery stores.
Given projected building type sf', modeled power densities (watts per sf')
were applied to render building peak demand (kW). BT load factors were applied to
peak demand to project annual energy requirements (kWh). Energy was allocated across
8,760 annual hours using rate class static load profiles rendering annual hourly average
demand.
A map depicting the recommended Greenfield development areas is set
forth below. Charts outlining (I) the breakdown of residential and non-residential load
forecasts through 2020 for the recommended Greenfield areas; and (2) Greenfield land
use inventory projections follow the map.
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II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
C. Power Supply
In providing electric power to serve the City's customer base under any of
the study options, the City has two basic choices: purchasing its electric power supply
requirements /Tom other utilities or generators participating in the California energy
market (Contract Supply Strategy); or developing generation resources by constructing
generation or participating with a generation developer and taking an equity interest in
local generation (Generation Supply Strategy).
A key finding of this feasibility analysis, under any of the MEU structures
analyzed, is that there is significant benefit to the City in electric generation ownership or
ownership like rights. Furthermore, the City finds itself in unique circumstances,
compared to other cities in the region, due to the confluence of natural gas and electric
transmission facilities, and the location of the South Bay Power Plant (South Bay), and
the location of the proposed Otay Mesa Power Plant (Otay Mesa), the City is
geographically at the center of a significant portion of the energy facilities required to
support the San Diego region. The MEU Study Team recommends that the City develop
City-owned generation as the centerpiece of its MEU electric supply strategy. Our
recommendation is not that the City should seek to develop a generation resource on its
own; rather the MEU Study Team recommends that the City look to jointly develop
and/or pursue a partial ownership with a developer in a larger base load generating unit.
1. In-City Generation
The Generation Supply Strategy, with in-City generation, provides the
maximum opportunity for electricity cost savings achieved through the implementation of
an MEU. Associated savings are positive in every year for both the CCA and MDU
options. The combined CCAIGreenfield option with a Generation Supply Strategy offers
the greatest benefits of all the options.
Ownership of generation would offer the City several advantages relative
to procuring electricity through power purchase contracts (Contracts Supply Strategy).
Among the benefits associated with participation in generation projects are:
. Lower electricity costs due to the City's retention of generation operating
margllls;
. The ability to leverage partial ownership to locate projects within the City and
receive /Tanchise fee revenues and local taxes; and
. Reduction in CAISO transmission charges, CAISO administrative charges, and
protection against charges related to transmission system congestion,
The MEU Study Team modeled generation options for the City using
operating and cost parameters of a new combined cycle gas turbine operating as a base
load plant. These parameters include the unit's heat rate, capacity cost, variable O&M
costs, availability factor, hours of planned operation, and the year the resource becomes
operational. Sales of any excess production beyond what is needed to serve the City's
21
--- ..........---.-..---
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
load would be sold into the market. The price for excess sales reflects a 25% discount
relative to the prevailing peak or off-peak price to reflect the probability that excess sales
will occur in the lowest priced hours of the on- or off-peak periods.
The following assumptions were used in the calculation of generation costs:
Capacity: 130MW
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh
Capacity Factor: 90%
Variable O&M: $2 Per MWh
Excess Sales: 75% of Market Price
Presently, there are at least two local generation options, which may be
available to the City with respect to obtaining generation located within or near the City's
boundaries:
(I) Dtay Mesa: The Otay Mesa Generating Project (Otay Mesa) will be a
510 MW, natural gas-fired combined cycle power plant located in the Otay Mesa area in
western San Diego County. Calpine Energy Services, LP (Calpine) is the project owner.
The 15-acre site is about 15 miles southeast of San Diego, California, and about 1.5 miles
north of the United States/Mexico border. SDG&E has recently announced plans to
purchase most or all of the capacity /Tom Calpine's Otay Mesa plant. If these plans are
implemented, the option would not be available to the City. IfSDG&E's proposal is not
finally approved and implemented, the City should examine this option, as the MEU
Study Team believes that there is still an opportunity to discuss potential teaming
arrangements with Calpine.
Under current plans, a new 230-kV switchyard at the site is proposed.
There are plans to build a OJ-mile connection to SDG&E's existing 230-kV Miguel-
Tijuana transmission line that passes near the eastern boundary of the Otay Mesa site. A
new two-mile natural gas pipeline will be built by SDG&E to provide fuel for the project.
Originally scheduled for completion in the summer of 2002, the construction schedule
now calls for its completion by summer 2005. Currently the project is reported to be five
percent complete.
(2) South Bay Power Plant Repower (SBPP): The California State
Lands Commission approved the San Diego Unified Port District's (Port District or Port)
expenditure of $110 million in public trust funds to acquire the SBPP /Tom SDG&E on
January 29, 1999. The existing SBPP consists of four natural gas-fired conventional
boiler units and one 14-megawatt combustion turbine.
Duke Energy North America's (Duke) 10-year lease with the Port District
to operate the SBPP went into effect in April 1999. As part of its lease agreement with
the Port District, Duke must, subject to certain conditions, dismantle and relocate the
22
II. CITY ENERGY CUSTOMERS, PROJECTED
ELECTRIC LOAD AND POWER SUPPLY
existing plant by 2009. According to the lease agreement, Duke must identify a specific
relocation site no later than June 2006 and publicize its site selection as part of an
application to the California Energy Commission (CEC) for pennits to site the new plant.
Currently, the future of Calpine's Otay Mesa project and the siting of a
new South Bay Power Plant remain unknown. The MEU Study Team's analysis indicates
that the City is uniquely located to allow the City to potentially host either or both of
these generation projects.
2. Distributed Generation
In addition to the evaluation of the Generation Supply Strategy, the MEU
Study Team also evaluated the feasibility of acquiring or building small distributed
generation units within the City to serve the customers of the City's MEU as a start-up
strategy. With respect to this option, the MEU Study Team has concluded that there are
no generation projects of sufficient size now operating within the City to support the
development of an MEU. The MEU Study Team has also concluded that the
development of small distributed generation projects is not economically feåsible as a
start-up measure in implementing an MEU.
Moreover, until the City successfully develops its Greenfield projects or
fonns an MDU and acquires the electric distribution system of SDG&E, it would have no
means of delivering power /Tom small City generation facilities to consumer electric
loads (load). Without a distribution system, it would not be possible for the City to
obtain delivery of power under the state's direct access laws and regulations and the
Federal open access laws and regulations which apply to direct transmission access,
except for the CCA-only option. Furthennore, the concept of developing distributed
generation at selected sites around the City (e.g., main campus) would not provide a City-
wide benefit and would offer very limited savings. As noted above (see Executive
Summary Section L(d)), the MEU Study Team was asked by the City to analyze feasible
municipal energy businesses with the objective of "citywide distribution of MEU
benefits."
At such time as the City develops a Generation Supply Strategy and has, through
ownership or construction, a means of delivering power from local distributed generation
projects to load, the MEU Study Team recommends that the City explore the
development oflocal distributed generation projects to augment the City's power supply.
23
H -------
III. MEU STRUCTURAL OPTIONS
SECTION III
MEU STRUCTURAL OPTIONS
24
III. MEU STRUCTURAL OPTIONS
III. MEU STRUCTURAL OPTIONS
A. Summary
The MEU Study Team has examined all MEU structures which are presently
authorized under the laws of the California, and has identified five structures which would
accommodate Chula Vista's entry into the utility business. These include:
a) Community aggregation for both electricity and natural gas (CCA);
b) "Greenfield municipalization" development (Greenfield);
c) Municipalization under a city electric utility department fonnat, eventually
leading to a Municipal Distribution Utility (MDU) system;
d) Participation in a joint powers agency (JPA); and
e) Municipalization under a Municipal Utility District fonnat (MUD).
Each of these options is discussed below.
B. Description ofMEU Options
1. Community Choice Aggregation
Subject to the finalization and issuance of final rules by the CPUC, the City of
Chula Vista can elect to serve as a community load aggregator for electric power pursuant to
Assembly Bill 117.
A load aggregator is an entity that procures electric energy and/or natural gas for
residents and businesses within a community. Under this option, the City would not own the
electric or gas distribution system within the City. Rather, it would procure electric power
and/or natural gas, either through its own generation, market purchases, or through a partner on
behalf of the customers that choose to aggregate their load. SDG&E would then deliver the
electric energy and/or natural gas to the end-use customer across its transmission and distribution
facilities. As explained in Section IV.H at 152-54, the preliminary analysis of natural gas supply
markets and costs shows that it is not economically feasible or desirable, at this time, for Chula
Vista to undertake providing natural gas service, either by acquiring the gas distribution facilities
of SDG&E or by implementing a Core Aggregation Transportation option for gas supply,
2. Greenfield Development
Greenfield development calls for the investment in distribution facilities to supply
energy to certain previously undeveloped areas within the City of Chula Vista. Typically, this
structure would include undeveloped acreage of land designated for an industrial park, for
example, or for new residential subdivisions that are anticipated and planned for within the
City's general plan build-out schedule. The distribution system should be planned and built in
25
III. MEU STRUCTURAL OPTIONS
collaboration with the developers of the projects and much of the cost will be borne by the
developers. The City may need to purchase a substation and would have to interconnect to
SDG&E's system in some fashion in order to supply energy. The City would also need to
develop the distribution system configuration (overhead/underground), lines, poles, and service
extensions, as well as make arrangements for appropriate meters and related customer service
functions. As discussed and demonstrated in Section IV.D of the Report at 80-98, the Greenfield
development option can be implemented immediately in connection with current and future
development of undeveloped areas within the City with positive financial results to the City and
its electric consumers.
3. Combined Community Choice Aggregation/Greenfield Development
In this structural option, the City simple implements both the CCA option and
Greenfield development option simultaneously and administers and operates the two programs
using City Staff or outside contractors to oversee operations and the development of additional
CCA and Greenfield development projects. As discussed and demonstrated in Section IV.B of
this Report at 31-32, the City can obtain the greatest potential economic benefits in the near term
by forming a CCA program and simultaneously pursuing and implementing Greenfield
development opportunities.
4. Municipal Distribution Utility
A municipal corporation in California, unless restricted by the terms of its own
Charter, has the legal authority to provide electric utility service to its residents and businesses.
There are currently over thirty-seven municipal agencies that provide electric utility services to
communities in California, representing approximately twenty-five percent of the total electric
load within the state. With this optional utility structure, the City could acquire SDG&E's
electric distribution system by negotiated price or condemnation and perform operation and
maintenance activities. The City could also develop or acquire generation resources, and/or
purchase power to meet the City's load requirements. The City Electric Utility Department
could be used as a vehicle for providing utility services to certain customers within the City or to
provide partial requirements service under agreements to be developed with SDG&E and other
utility suppliers. However, for purposes of this section of the Report, the City Utility
Department structure contemplates the formation of a Municipal Distribution Utility (MDU)
which would acquire the electric distribution system of SDG&E and provide full utility service
to retail electric customers within the City. As discussed in Section IV.F,7 of the Report at 132-
34, the MEU Study Team recommends that the City first implement the CCAlGreenfieid options
and defer the consideration of implementation of an MDU until the 2008-10 time fÌame.
5. Joint Powers Agency/Municipal Utility District
Another optional utility structure is one in which the City forms, or becomes a
member of an existing Joint Powers Agency (JP A) with one or more public agencies or utilities
26
III. MEU STRUCTURAL OPTIONS
for the provision of electricity to their combined residents and businesses. In forming the JP A,
the City would identify other potential participants and work on the development of a JP A
agreement that would provide the legal basis of formation. The JP A agreement would also
establish the roles, rights, and obligations of the participants.
A Municipal Utility District (MUD) is an agency of the state, formed to provide
certain services of governmental or proprietary functions within limited boundaries. An MUD
may acquire, construct, own, operate, control, or use public works located inside or outside of the
district, as well as purchase power or other services, to supply the inhabitants of the district and
public agencies therein with electric power. The MUD may construct works across or along any
street or public highway, or over any lands that are property of the state, and it has the same
rights and privileges granted to municipalities within the state, including the power of eminent
domain. The MUD structure option provides for the aggregation of City electric loads and
service territory with the electric loads those of other cities or unincorporated areas. While the
City could use the MUD structure in lieu of forming its own MDU, the MEU Study Team does
not recommend that the City pursue this option at this time. The complications of organizing an
MUD and dealing with other local governments or entities would add complexities and
complications and delay the implementation plan.
The JPAlMUD options would allow the Chula Vista MDU to accrue and realize
further benefits by I) the addition of partners to share the costs and risks of the MDU option; 2)
possible aggregation of a larger load for resource procurement purposes, which, in turn, would
lead to possible lower purchase power costs; and 3) possible reductions in cost for other
activities associated with running an electric utility such as operation and maintenance functions.
As discussed in Section IV.G of the Report at 135, neither the JPA option nor the
MUD option is feasible until and unless the City forms and implements the MDU option and
becomes a full service electric distribution system. Once the MUD is formed, the JP A or MUD
options are worthy of consideration as a means of obtaining the benefits of scale in generation
projects and to allow the City to expand its portfolio of available energy options.
27
.......
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SECTION IV
EVALUATION OF
CHULA VISTA'S
MEU OPTIONS
28
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
INTRODUCTION
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
A. Introduction
As discussed and swnmarized in Section III above, the MEU Study Team initially
identified all MEU options that were available to the City under applicable State and Federal
laws and regulaûons. The initial screening of these MEU options included the possibility of
developing both an electric and gas distribuûon system within the City. As discussed below in
Section IV,H, at 152-54, the MEU Study Team has concluded that it will not be economically
feasible for the City to acquire and operate a gas distribuûon system or otherwise engage in
providing any gas utility services within the study period pending a significant change to the
current cost structure and gas rates of SDG&E.
On the basis of the initial screening of the City's electric supply options, the MEU
Study Team narrowed the number of MEU options based upon economic feasibility and then
conducted a detailed economic feasibility analysis for the City of Chula Vista encompassing
separate evaluation of three municipal electric utility options and corresponding electricity
supply portfolios. These options are: I) aggregation of electric loads within the city for purposes
of procuring wholesale electricity through a Community Choice Aggregation program (CCA), as
provided for in Assembly Bill 117 (2002); 2) ownership and operation of distribution assets in
newly developed areas only (Greenfield development); and 3) acquisition of the existing
SDG&E distribution assets within the city boundaries and assumption of ongoing distribution
operations (MDU). A combined CCAlGreenfield option was also evaluated.
In addition to the three MEU options which were identified as feasible for
immediate or near term development, the MEU Study Team also identified and evaluated two
additional MEU options which would become available to the City in the long term in the event
that the City develops a full service electric distribuûon system by acquiring the distribution
system of SDG&E. The long range options which were evaluated and analyzed were (I) the
development of a Municipal Utility District (MUD), and/or (2) participation in a Joint Powers
Agency (JPA) to broaden the City's electric power supply alternatives.
As part of the detailed economic feasibility analyses, two primary supply
strategies were evaluated for the City to serve the electric loads of its customers. The Generation
Supply Strategy is built upon City ownership of or entitlement to 130 MW of new combined
cycle gas turbine power plant capacity. This represents approximately 85% of the City electric
loads under the CCA and MDU structure options (for further discussion see Appendix C, Section
II.B.2 at 68-69). The Contracts Supply Strategy is based on the City entering into medium and
short-term (1 to 5 years) fixed price power supply contracts to meet the majority of the MEU's
load requirements.
29
IV. EVALUATION OF CHULA VISTA'S MEV OPTIONS
INTRODUCTION
The financial pro forma analysis compares the total costs of each option with the
total costs of continued utility service /Tom SDG&E, by year, through 2023. The model
combines estimates of capital costs, power supply costs, operations and maintenance costs, and
other applicable costs and then projects these costs over a 20-year period. Operations for each
MEU option are not assumed to commence until 2006 in order to reduce the City's exposure to
large CPUC exit fees. As detailed in the Appendix C, Section II.C.I at 78-81, the CPUC exit
fees that would be applicable to any of the MEU options are projected to start out high and
steadily decline over time. Beginning operations in 2006 would reduce the risk that high exit
fees would render the MEU options uneconomic. Therefore, the period analyzed to determine
financial viability was the 18-year period beginning in 2006 and continuing through 2023.
30
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- SUMMARY AND EV ALUA TION
B. Summary and Evaluation
-
Using the three basic municipal electric utility options identified above (i.e.,
CCA, Greenfield Development and MDU), the MEU Study Team evaluated seven supply
- scenario options using different combinations of those feasible MEU options. Six of the seven
combinations are expected to result in positive savings that are quantified in this section on a
nominal and net present value basis'. Throughout this section, savings means the margin between
- projected MEU option costs and SDG&E's current and projected rates.
The pro forma results of all the supply scenario options or combinations are
- summarized in the table below. The table shows the total savings over the 18-year period from
2006 through 2023 and the net present value of these savings over the same time period.
- Summary of Savings Estimated For Each Option Ranked By NPV of Savings From 2006
Through 2023
Rank Option Supply Nominal Savings NPV of Savings Average
Strategy ($ Millions) ($ Millions) Annual
Savings (%)
I CCA/Greenfield Generation 351 122 10%
2 MDU Generation 329 109 9%
3 CCA Generation 244 90 8%
4 CCA/Greenfield Contracts 170 52 4%
5 CCA Contracts 86 28 2%
6 Greenfield Contracts 89 21 10%
7 MDU Contracts 16 (12) -1%
The year-by-year savings estimates for each option are shown in the following graph.
, Net present value is a standard technique used in financial analysis of capital projects to account for the
timing cash flows. Future cash flows are discounted to recognize the time value of money; i.e., dollars
received in the future are worth less than dollars received today. A discount rate of 10% was used in the
net present value calculations.
31
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EV ALUA TION -
Annual Savings in Dollars For Each Option
-
City of Chula Vista MBJ Options -
Annual Cost Savings Versus SDG&ERates ($)
<0,000"'" -
",000"," ---
".0'""'" /' --------
~ -
".000.,"0
".'"0.000 --=,a"""."""ærn
",".""'ærn -
",000,000 -8-œA""'ærn
-+-=,a""".'ccr"~'
,",000,000 --><-œA.Ccr«=
--a""".""',=
'.'"0"'" --",".Ccr«= -.
, , "'"
".0,",000<
_.
['"',",000<
["",",000<
-
The analysis demonstrates that the City can obtain the greatest potential benefit by forming a
CCA and simultaneously pursuing Greenfield opportunities. Ideally, to maximize benefits, the -
City would acquire equity in a generation project within the City to supply the combined
CCAlGreenfield loads. A CCA program gives the City the operational scale required to
efficiently source electricity for the CCA and Greenfield customers and compete with the electric -.
supply portfolio of SDG&E. The best approach for the City to obtain electricity at a lower cost
than SDG&E is to secure an ownership interest in or entitlement to generation facilities located
within the City. Such generation would give the City a competitive advantage relative to
SDG&E, which should provide sustainable cost savings opportunities.
Another advantage to the CCAlGreenfield combination is that it positions the City -
for the possibility of forming an MDU if warranted by future circumstances. The City would
obtain valuable experience in power supply and distribution system operations and would be in a
more favorable position to form a City-wide MDU from a perspective developed by that
expenence.
32
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EVALUATION
The analysis reveals the importance of generation ownership to the economics of
any of the MEU options. The Generation Supply Strategy, with in-City generation, provides the
maximum opportunity for electricity cost savings; savings are positive in every year for the
hybrid CCAlGreenfield, CCA, and MDU options.
The Contracts Supply Strategy, under which the City purchases its electricity
requirements /Tom the market predominantly through long-tenn contracts, offers less benefit to
the City than the Generation Supply Strategy. However, using the Contracts Supply Strategy the
combined CCAlGreenfield option is projected to provide savings in all years and is a viable
alternative. The CCA option is projected to provide savings in all years except for 2011 through
2014, when SDG&E rates are expected to decrease as a result of the expiration of DWR
contracts embedded in the SDG&E generation portfolio cost. The Greenfield option is expected
to lose money in the near tenn and commence realizing savings in 2012. The Contracts Supply
Strategy does not support a viable MDU option at this time.
The Tables below highlight the projected Chula Vista rates for the following
options: Community Choice Aggregation (Generation and Contract), Greenfield (Contract),
CCAlGreenfield (Generation and Contract), and Municipal Distribution Utility (Contract and
Generation). The projected average rates are for the period covering 2006 through 2023. The
SDG&E comparable projected rates are included in the tables as a benchmark.
33
. --..---..
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EVALUATION
TABLE II-I
CCA
Comparison of Projected Average Rates ($/KWH)6,7
SDG&E
2006 862,186,12 $0.086 $0.070 $0.078
2007 886,372,50 $0.083 $0.068 $0.077
2008 908,901,63 $0.080 $0.068 $0.075
2009 942,024,55 $0.081 $0.069 $0.076
2010 994,545,51 $0.081 $0.070 $0,077
2011 1,015,112,12 $0.075 $0.071 $0.079
2012 1,035,872,16 $0.076 $0.073 $0.080
2013 1,056,828,91 $0.078 $0.073 $0.080
2014 1,091,483,20 $0.080 $0.073 $0.080
2015 1,166,627,011 $0.082 $0.073 $0,080
2016 1,187,937,78 $0.084 $0.073 $0.082
2017 1,209,473,82 $0.086 $0.072 $0.082
2018 1,231,238,76 $0.088 $0.074 $0.082
2019 1,256,964,94 $0.090 $0,075 $0.082
2020 1,293,123,651 $0.092 $0.075 $0.082
2021 1,310,182,03 $0.094 $0.077 $0.086
2022 1,327,483,48 $0.094 $0.079 $0.086
2023 1,345,031,63 $0.090 $0.074 $0.082
Note: This table compares only the electric energy commodity. Under the CCA option SDG&E
would continue to own and operate the distribution system,
6 The Projected Average Rates are a composite of the actual rates for: Residential, Small Commercial (A),
Medium Commercial (AL-TOU), Large Industrial (AL-TOU, +500KW), Street Lighting and Traffic
Control.
7 These rates include CCA costs associated for generation. CCA customers would be separately responsible
for transmission and distribution costs incurred by SDG&E.
34
-_.~~_~_~H~- ~ .....-.---
_hH
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EVALUATION
TABLE 11-2
Greenfield
Comparison of Projected Average Rates ($/KWH)8
Greenfield
Contracts
SDG&E 0 tion
2006 87,863,44 $0.147 $0.151
2007 93,848,66 $0.146 $0.152
2008 99,171,623 $0.142 $0.149
2009 114,758,65 $0.143 $0.145
2010 152,995,84 $0.144 $0.144
2011 163,334,325 $0.139 $0.141
2012 173,712,79 $0.141 $0.139
2013 184,132,061 $0.143 $0.138
2014 208,090,40 $0.146 $0.132
2015 271,146,613 $0.148 $0.128
2016 280,195,38 $0.151 $0.127
2017 289,286,261 $0.154 $0.126
2018 298,422,10 $0.157 $0.128
2019 311,332,41 $0.160 $0.127
2020 334,684,73 $0.163 $0.130
2021 340,374,37 $0.166 $0.131
2022 346,160,73 $0.166 $0.131
2023 352,045,471 $0.162 $0.127
Note: This table compares the total "bundled-service" cost for power supplied by SDG&E
including costs associated with owning and operating the distribution system.
s These rates include costs for generation, transmission and distribution.
35
- ------ -- -- ---------- ---------
IV. EV ALUA TION OF CHULA VISTA'S MEV OPTIONS
SUMMARY AND EVALUATION
TABLE 11-3
Combined CCAlGreenfield
Comparison of Projected Average Rates ($/KWH)9
CCAlGreenfield CCAlGreenfield
Projected Loa Generation Contracts
Term K SDG&E 0 tion 0 tion _.
2006 862,186,12 $0.092 $0.074 $0.083
2007 886,372,50 $0.089 $0.073 $0.083
2008 908,901,63 $0.087 $0.072 $0.081
2009 942,024,55 $0.088 $0.074 $0.082
2010 994,545,51 $0.091 $0.076 $0.085 -
2011 1,015,112,12 $0.084 $0.077 $0.087
2012 1,035,872,16 $0,086 $0.079 $0.088
2013 1,056,828,91 $0.089 $0.080 $0.088
2014 1,091,483,20 $0.092 $0.080 $0.088
2015 1,166,627,011 $0.096 $0.081 $0.090
2016 1,187,937,78 $0.099 $0.081 $0.091
2017 1,209,473,823 $0.101 $0.081 $0.091 -
2018 1,231,238,76 $0.103 $0.083 $0.092
2019 1,256,964,94 $0.106 $0.084 $0.092
2020 1,293,123,651 $0.109 $0.085 $0.093 _.
2021 1,310,182,03 $0.112 $0.087 $0.096
2022 1,327,483,48 $0.112 $0.088 $0,097
2023 1,345,031,63 $0.107 $0.084 $0.092
9 These rates include CCA costs associated for generation and Greenfield costs associated with generation,
transmission and distribution. Non-Greenfield customers would be separately responsible for transmission
and distributions cost incurred by SDG&E.
36
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EV ALUA TION
TABLE 11-4
MDU
Comparison ofPro'ected Average Rates ($/KWH)IO
MDU
Projected Load Contracts
Term SDG&E 0 tion
2006 862,186,12 $0.151 $0.137 $0.153
2007 886,372,50 $0.150 $0.136 $0.153
2008 908,901,63 $0.143 $0.132 $0.147
2009 942,024,55 $0.145 $0.133 $0.148
2010 994,545,51 $0.146 $0.134 $0.148
2011 1,015,112,12 $0.140 $0.135 $0.151
2012 1,035,872,16 $0.142 $0.137 $0.152
2013 1,056,828,91 $0.145 $0.138 $0.153
2014 1,091,483,20 $0.148 $0.138 $0.152
2015 1,166,627,011 $0.150 $0.136 $0.150
2016 1,187,937,78 $0.153 $0.136 $0.153
2017 1,209,473,823 $0.156 $0.136 $0.154
2018 1,231,238,76 $0.159 $0.138 $0.155
2019 1,256,964,94 $0.162 $0.139 $0.154
2020 1,293,123,651 $0.165 $0.140 $0.154
2021 1,310,182,03 $0.168 $0.144 $0.159
2022 1,327,483,48 $0.168 $0.144 $0.159
2023 1,345,031,63 $0.164 $0.143 $0.158
10 These rates include costs for generation, transmission, and distribution.
37
. -..--.-...
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
SUMMARY AND EVALUATION
The following sections of this Report describe each of the MEU options and the
pro forma financial results of each option, Additional detail regarding the methodology and
assumptions used to derive the financial pro forma are contained in Appendix C, Section II at 64-
89.
-
38
.-.... ....--- "_00..-----_____.00_"'- 00--__00'____-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
C, Community Choice Aggregation
--
Under a CCA scenario, the City would procure electric supply for customers of
the CCA, and SDG&E would continue to deliver the electricity to end use customers over
distribution facilities owned and operated by SDG&E. Customers would pay SDG&E the retail
rate for non-generation charges (e.g., transmission and distribution), as they do today. SDG&E
would provide a credit on the bill to remove its costs related to generation and procurement of
- electricity that would be procured by the CCA. The bill credit that SDG&E will provide for
generation-related charges is assumed to be the entire generation rate, net of the applicable exit
fees. SDG&E would continue to perform metering and billing services for end use customers,
the costs of which are largely bundled in existing retail distribution rates.
1. Customer Base
A CCA program would encompass all electric customers within the City
boundaries, except for those who have notified the City of their desire to opt out of the CCA
program and continue to receive electric commodity supply service from SDG&E. Section ll. B
at 9-16, describes, in detail, the customer and load projections used in the analysis, and these are
summarized in the following table.
CCA Projected Customers, MWh, And Peak MW By Year
Year Customers MWh (usa!!e) Peak MW (demand)
2006 86,652 862,186 147
2007 89,412 886,373 151
2008 91,761 908,902 155
2009 94,149 942,025 160
2010 95,737 994,546 170
2011 96,567 1,015,112 174
2012 97,403 1,035,872 177
2013 98,244 1,056,829 181
2014 99,146 1,091,483 188
2015 100,028 1,166,627 201
2016 100,738 1,187,938 205
2017 101,449 1,209,474 209
2018 102,161 1,231,239 213
2019 102,875 1,256,965 217
2020 103,589 1,293,124 224
2021 103,881 1,310,182 227
2022 104,174 1,327,483 230
2023 104,469 1,345,032 233
39
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
-
The above chart asswnes that the City, through its CCA program, will serve all
customers within the City, including those in newly developed areas and that the City does not -
undertake a Greenfield Development project.
2. Functional Elements -
3. Infrastructure Requirements
-
Assembly Bill 117 permits California cities, counties, or city and county JP As, to
implement a CCA to aggregate the electric loads of electric service customers within their -
jurisdictional boundaries to facilitate the purchase and sale of electricity. Within the context of
CCA, "electricity" means the electric energy commodity only. CCA's enabling legislation
requires the serving utility, in this case SDG&E, to provide electricity delivery over its existing -
distribution system and provide end-conswner metering, billing, collection and all traditional
retail customer services (i.e., call centers, outage restoration, extension of new service).
Accordingly, the infrastructure requirements of the CCA utility structure option do not include -
any electric transmission or distribution related facilities to serve CCA retail loads.
To support financial settlements and energy procurement, an accurate record of -
total, time-of-day specific, electricity demand and energy usage is essential. Lacking this, the
CCA operator is required to rely on the distribution utility's recorded usage for each individual
customer. All customer classes are not metered in the same way. In particular, residential and -
small commercial conswners (electric demand less the 20 kW) typically have simple electro
mechanical meters capable of metering only cwnulative energy conswnption. Mediwn
commercial customers (electric demand in the range of20 to 500 kW) are typically metered with -
energy and demand meters, but still lack time-of-day recording. Large commercial and industrial
customers (electric demand greater than 500 kW) are typically equipped with data recording
meters recording electric demand on five, ten or fifteen minute intervals (interval data recording .-
meters or IDR).
The CCA will be required to purchase energy on the wholesale market for each -
hour of the day. Without a time-of-use record of energy conswned, the operators will have to
rely on prototypical rateclass load profiles. These load profiles are derived by distribution utility
load research based on IDR metering of a stratified random sample /Tom each rateclass -
(residential, small commercial, mediwn commercial). Hence, they represent the average or
typical customer and not the CCA's actual customers. Further, since not all customers use
energy at the same time, there will be diversity between each conswner's time-of-day usages. -
Simple aggregation, consisting of summing the metered values, will not reflect this diversity,
and, since load diversity serves to reduce the total electric capacity required to serve the electric
load, the operator will tend to over-procure capacity and increase operating costs.
40
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
CCAs have the option, under the law, to meter electricity supplied to the
jurisdictional territories comprising the CCA to obtain an accurate record of aggregated loads.
For the City's prospective CCA, SDG&E is required to "install, maintain and calibrate metering
devices at mutually agreeable locations within or adjacent to the CCA's political boundaries" at
the request and at the expense of the CCA. SDG&E will also be required to "read the metering
devices and provide the data collected to the CCA at the aggregator's expense."ll Utilities are
directed under CPUC Order Instituting Rulemaking R.03.09.007 (August 21, 2003) to develop
specific tariff language to meet the requirements, Assessing the size, type, location, quantity and
installation cost of such CCA wholesale metering will require an analysis of SDG&E's
distribution system, in concert with SDG&E service planners, and, will require SDG&E to
comply with the CPUC's Order to develop applicable tariff terms and conditions.
In addition to the upstream metering facilities described above, to facilitate
electric portfolio operations required to procure wholesale energy for CCA supply, the systems
identified below should be employed. The City may elect to procure or alternatively obtain
system functionality by arrangement, which could be obtained through a full-requirements
supply contract where the required systems and support services are bundled into a power
contract and embedded in the commodity cost. However, such services are not free and systems
and service costs must be known to quantify the embedded commodity premium to make
informed procurement decisions.
System Requirements
~ Initial Cost Maintenance Annual Cost Potential Outsourcing
Scheduling/SeWements Software $650.000 40% $476.667 Scheduling Coordinator
Risk Management Software $150.000 40% $110.000 Power Marl<eter
EDI/IOU Transadions $100.000 40% $73.333 ConsuRant
Scheduling SelVer $50.000 10% $21 667 Scheduling Coordinator
Total Systems Costs $681,667
Operations required for the systems are described under Section IV.C.2.c -
Operations and Maintenance below at 44 and in Appendix C, Section II.B.3, Portfolio
Operations at 77-78, Associated costs are included in financial analyses and pro forma results.
b. Resource Management
The MEU Study Team has modeled generation options for the City using
operating and cost parameters of a new combined cycle gas turbine operating as a base load
plant. These parameters include the unit's heat rate, capacity cost, variable O&M costs,
availability factor, hours of planned operation, and the year the resource becomes operational.
II Cal. Pub. Until. Code §366.2(c)(l8).
41
-.
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
Sales of any excess production beyond what's needed to serve the city's load are sold into the
market. The price for excess sales reflects a 25% discount relative to the prevailing peak or off-
peak price to reflect the probability that excess sales will occur in the lowest priced hours of the
on- or off-peak periods.
The following assumptions were used in the calculation of generation costs:
Capacity: 130MW
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh
Capacity Factor: 90%
Variable O&M: $2 PerMWh
Excess Sales: 75% of Market Price
The CCA would benefit by ownership of generation within the City to supply the
CCA relative to securing power through power purchase contracts, There are several reasons
why a Generation Supply Strategy reduces total power supply costs. First, the production costs
of a new combined cycle gas turbine are expected to be below market-clearing prices. In
essence, the CCA would be able to capture generation profits within the CCA operation.
In addition, generation located within the City boundaries would enable the City
to avoid paying grid management and transmission congestion charges which are assessed by the
CAISO for use of the transmission grid when congestion is present. Electricity obtained via
power purchase contracts may, or may not, be subject to charges for transmission congestion,
depending on the point of delivery specified in the contract. Transmission charges for the fixed
costs of the transmission network, as opposed to transmission congestion charges, are not
impacted by the location of the generator due to the fact that, under CCA, the retail transmission
rates ofSDG&E will continue to apply.
The Contracts supply portfolio evaluated for CCA includes the following fixed
priced contracts12.
12 Commercially traded power product descriptions in parentheses denote days per week and hours per day.
"(6 X 16)" means six days per week, Monday through Saturday, and 16 hours per day, hours ending 07:00
through 22:00. Such definition is industry standard practice.
42
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
Power Purchase Contracts - CCA Option
Year Product Quantity (MW) Price ($/MWh) Term
2006 Base (7 x 24) 50 49 5 Years
2006 Peak(6xI6) 75 59 5 Years
2011 Base (7 x 24) 50 51 5 Years
2011 Peak (6 x 16) 75 61 5 Years
- 2016 Base (7 x 24) 75 51 5 Years
2016 Peak (6 x 16) 100 61 5 Years
2021 Base (7 x 24) 75 55 3 Years
2021 Peak(6x 16) 125 66 3 Years
The following renewable energy contracts were assumed in the CCA portfolios
for both the Generation and Contracts Supply Strategy:
Renewable Energy Contracts - CCA Option
-
Year Product Quantity (MW) Price ($/MWh) Term
2006 Base (7 x 24) 7 52 I Year
2007 Base (7 x 24) 8 51 I Year
2008 Base (7 x 24) 10 52 I Year
2009 Base (7 x 24) II 52 I Year
2010 Base (7 x 24) 13 52 I Year
2011 Base (7 x 24) 15 53 I Year
2012 Base (7 x 24) 17 54 I Year
2013 Base (7 x 24) 18 54 I Year
2014 Base (7 x 24) 20 54 I Year
2015 Base (7 x 24) 23 54 I Year
2016 Base (7 x 24) 25 53 I Year
2017 Base (7 x 24) 28 53 I Year
2018 Base (7 x 24) 29 55 3 Years
2021 Base (7 x 24) 30 58 3 Years
The CPUC has yet to determine how the Renewable Portfolio Standard (RPS)
would apply to a CCA, and it is not clear whether an MDU would be required to meet the RPS.
The MEU Study Team has assumed that the City's portfolio would match the minimum
standards applicable to SDG&E in all of the MEU options. Accordingly, the portion of the
43
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
-
portfolio comprised of renewable energy is established at 7% in 2006 and gradually increases to
20% in 2017, consistent with RPS requirements.
Additional details regarding the power supply portfolios modeled for the City,
including treatment of spot market purchases and the RPS, are included in the Appendix C, -
Section II.B.2 at 68-77.
c. Operations and Maintenance
-
The primary operations and maintenance requirements for operation of a CCA
program are activities related to electric portfolio operations. These activities include those
necessary to procure electricity in the wholesale markets, schedule electricity transactions with -
the CAISO, conduct financial settlements for wholesale electricity purchases and sales, and
interface with SDG&E which would be providing billing, metering, and customer services to -
CCA customers.
Portfolio operations costs are the costs associated with various activities related to -
procuring electricity for retail customers. Portfolio operations activities include load forecasting,
procurement of electricity /Tom wholesale electricity sellers, risk management and controls.
Activities related to retail pricing (Le., load research, cost of service, rate design) are also -
included in this cost category for purposes of the pro fonna analysis.
Scheduling coordination costs are the costs associated with scheduling and -
settling electric supply transactions with the CAISO. The analysis assumes that the City would
become a CAISO certified Scheduling Coordinator, which would require acquisition of
scheduling and settlements software and operation of an around-the-clock scheduling desk. -
Total costs of portfolio operations and scheduling coordination are modeled as a
combination of fixed and variable costs. Fixed costs, largely associated with the minimum
required personnel are approximately $2,000,000 per year. Variable costs are estimated at $2.50
per MWh to account for increases in the size and sophistication of the portfolio operations
corresponding with increases in the overall size of the utility.
d. Human Resources
To facilitate electric portfolio operations described above, the City could develop
the in-house capabilities or outsource the functions to a greater or lesser degree. As a base case
to evaluate the efficacy of its potential outsourcing options, the following full-time employees
(FTE) are required.
44
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
CCA Human Resource Requirements
Function FTE Potential Outsourcina
Rates/Forecasting 3 Consultant
Resource Planning 2 Consultant
Trading/Risk Management 4 Power Marketer
Wholesale Settlements 2 Scheduling Coordinator
Pre-Schedulers 2 Power Marketer
Real Time Desk 6 Scheduling Coordinator
Credit 1 Consultant
Management 3
IOU Transactions/Audits 2 Consultant
IT Support 1 Scheduling Coordinator
Total 26
FTE Average Annual Salary $69.500
Fringe Benefits (15%) $10,300
Annual Labor Estimates $2.083.000
Associated costs are included in the financial analyses and pro fonna results.
3. Cost-Benefit Analyses
a. Financial Analysis
A financial analysis was perfonned in order to develop financial pro fonna, which
was then structured as consolidated statement of income for each MEU structure option. The
consolidated statements based on the financial pro fonna for the CCA option are located in this
Report in the Appendix C, Section II.I at 90-91. As noted above, savings or potential income is
the margin between current retail power costs, as provided by SDG&E, and the given MEU
structure option's projected cost to provide the power. The MEU Study Team began its
evaluation of each utility structure option with a planning horizon beginning in 2004 and then
projected costs 20-years forward to 2023. Evolving legislation, regulation, implementation lead
times and cost considerations caused the MEU Study Team to project MEU implementation
beginning in 2006. The resulting study period was subsequently revised /Tom 2006 to 2023 as
reflected in the financial pro fonna for each MEU structure option.
As a regulated public utility, SDG&E provides utility services at regulated cost-
based rates, Hence, SDG&E's rates are directly tied to a demonstrated revenue requirement and
its rate structures are required to reflect an equitable cost allocation among customer classes.
The financial analysis provided herein compares SDG&E's revenue requirement with the
revenue requirement of each MEU structure option to detennine potential savings or income.
Pro fonna summary tables compare each MEU structure option based on their relative ability to
produce operational cost savings or benefits.
45
---~
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
In the CCA option, customer service is limited to the electric energy commodity
only. SDG&E would continue to provide electricity delivery over its existing distribution system
and provide end-consumer metering, billing, collection and all traditional retail customer
services (i.e., call centers, outage restoration, extension of new service). Accordingly, to
evaluate the potential benefits for CCA, only costs associated with wholesale electric commodity
procurement and related business expenses were evaluated to assess potential savings or benefits.
b. Financial Analysis Structure --
CCA customer population electric loads, evaluated under Section IJ,B at 9-16 and
summarized above at 39 , were applied to SDG&E current and projected generation rates to yield
its revenue requirement or retail customer energy costs. MEU operating expenses were projected
and subtracted from SDG&E's revenue requirement to yield the projected financial benefit.
Elements contained in the analysis are summarized below:
SDG&E Forecast Generation Rates 13
- Utility Retained Generation
- Qualifying Facility Generation
- Bilateral Power Purchase Contracts
- CAISO charges
- Residual Spot Market Purchases or Sales
CCA Enemy Cost (Commoditv CostS)14
- Spot Market Purchases
- Power Purchase Contracts
- Renewable Energy Contracts
- Generation Ownership
California Independent System Operator Charges (CAISO)15
Transmission
Ancillary Service
Grid Management
Reliability Services
Congestion Costs
Grid Operations
Unaccounted for Energy
13 Detailed explanation of inputs, assumptions and sources are provided in Appendix C, Section II.A at 64-67.
14 Detailed explanation of inputs, assumptions and sources are provided in the Appendix C, Section 11.8.2 at
68-77.
15 Detailed explanation of inputs, assumptions and sources are provided in the Appendix C , Section 11.D at
83-84.
46
- -----------------.-- --- - ------.. .---
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
Neutrality Adjustments
Deviation Charges
Operation and Scheduling Costsl6
Scheduling and Settlements System - Procurement and Maintenance Costs
Labor
Non-Bvuassable Chargesl?
CPUC Exit Fees
Uneconomic Utility Retained Generation and Power Contracts
DWR Power Purchase Contracts
DWR Bond Charges - Financing Past Purchases
As related in Section ILC, MEU structure option cost benefits are assessed based
upon two energy supply strategies. In the first supply strategy, it is assumed the City's MEU will
take an ownership position in a power generation facility (Generation Supply Strategy), In the
second, it is assumed the City's MEU will purchase all of its energy requirements in the
wholesale energy market by executing power contracts with suppliers (Contracts Supply
Strategy). Power costs are allocated to portfolio supply options for each supply strategy as
follows:
Power Supply Portfolio Energy Cost ($)
Illustrative - 2006 Only
Generation Contracts
Market Purchases 8.6% 5.6%
Contracts 6.4% 94.4%
Power Production 85.0%
c. PrO Forma Results
Financial pro forma results were prepared for the CCA option for both of the
Generation and Contracts Supply Strategies, See Appendix C, Section ILl at 90-91.
16 Detailed explanation of inputs, assumptions and sources are provided in Appendix C, Section II.B.3 at 77-
79, as well as in Sections IV.c.2.a, b and c at 40-44, above, addressing Inftastructure Requirements,
Operations and Maintenance, and Human Resource Requirements, respectively.
17 See Appendix C, Section II.C at 78-81.
47
. ..-..-....---------- -"..- ..,.. . ....--- .. ..... ...------..
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
(1) CCA - Generation Supply Strategy
Total estimated costs of CCA operations are summarized in the table below for
the Generation Supply Strategy and these costs are compared to projected SDG&E electric
commodity related charges. The costs of CCA operations are broken out among the major cost-
of-service elements, The most significant of these costs is the electric commodity costs, which
are primarily the capital and operating costs of the CCA's generator, plus renewable energy
contracts and residual spot market purchases. The next largest cost category relates to the non-
bypassable charges or exit fees that SDG&E will impose on the CCA pursuant to CPUC
authority. Other costs include ancillary services, CAISO charges and portfolio operations and
scheduling coordination charges.
Savings are the difference between the CCA costs and the charges that SDG&E
would collect through rates under the status quo retail electric service arrangement. As shown
below, significant savings are projected to occur in every year of the study period.
48
- ---------------------- _____m..__-__--
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- CCA
- Pro Forma Summary and Projected Savings - CCA Generation Supply Strategy
(Millions of DolÚlrs Per Year)
- Year Commodity Ancillary Operations & Non- Total SDG&E Savings
Costs ServicesiiSO Scheduling bypassable Costs Charges
Costs Charges
2006 44.2 2.4 4.2 9.8 60.5 73.9 13.3
2007 44.3 2.5 4.2 9.1 60.2 73.4 13.2
2008 46.6 2.7 4.3 7.8 61.4 73.0 11.6
2009 48.7 2.9 4.4 8.7 64.6 76.2 11.6
2010 51.6 3.2 4.5 9.9 69.2 81.1 11.9
2011 53.5 3.4 4.5 10.5 71.9 75.7 3.8
2012 55.5 3.6 4.6 11.5 75.2 78.8 3.6
2013 56.5 3.7 4.6 11.8 76.7 82.4 5.7
2014 58.7 4.0 4.7 12.0 79.4 87.0 7.5
2015 63.0 4.4 4.9 12.9 85.3 95.5 10.3
2016 63.4 4.6 5.0 13.1 86.1 99.6 13.5
2017 64.4 4.7 5.0 13.3 87.5 103.7 16.3
2018 67.4 5.0 5.1 13.6 91.1 108.1 17.0
2019 69.8 5.3 5.1 13.9 94.1 113.0 18.9
2020 72.4 5.6 5.2 14.3 97.6 119.1 21.5
2021 75.6 5.9 5.3 14.5 101.2 123.5 22.3
2022 78.5 6.1 5.3 14.6 104.6 125.1 20.5
2023 78.9 6.3 5.4 9.1 99.7 121.0 21.3
The following Chart I graphically compares the total CCA cost of service, to the
generation-related charges projected for SDG&E.
49
--------.------
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
-
Chart 1: Comparison Of CCA Costs Based On Generation Supply Strategy -
SD""'E AND CHDLA VISTA -
POWER SUPPLY REVENUE REQUIREMENT COMPARISON
,."
-
,~,
'00.' -
§
~ ".
~
g... -
~
.,D
-
~,
===~~=---=----==== -
The components of the CCA costs on a dollar per MWh basis are shown in Chart -
2 for the Generation Supply Strategy and are compared to SDG&E electric commodity related
rates.
-
-
-
-
50
--------
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- CCA
Chart 2: CCA Cost Components On A Per MWh Basis
CCA System Ave.... CoSI
Compono"s of Roven,o Roq,;..monl
- "°.00
00.00
- 80.00
70.00
. 00.00
- ~
l 50.00
,
.
;¡ 40.00
30.00
20.00
".00
2006 2007 2008 2009 20"20" 20" 20" 2014 20OS 2016 20172018 2019 2020 202' 2022 2023
51
IV. EY ALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
-
(2) CCA - Contracts Supply Strategy
Total estimated costs of CCA operations are summarized in the table below for -
the Contracts Supply Strategy and are compared to projected SDG&E electric commodity related
charges. The most significant of these costs is the electric commodity costs, The commodity
costs primarily reflect the long-tenn power purchase contracts that fonn the core of the supply -
portfolio, as well as the renewable energy contracts and spot market purchases.
Cost savings are 'projected to occur in years 2006 through 2010. Projected -
SDG&E rate reductions in 201118, resulting /Tom the expiration of DWR power purchase
contracts in SDG&E's supply portfolio, eliminate the savings /Tom 2011 through 2014. At that -
time, modest annual increases in SDG&E rates are projected to provide persistent savings
opportunities for the CCA throughout the remainder of the study period.
-
-
-
-
-
-.
-
-
18 See Appendix C, Section ILA at 64-65 for SDG&E Forecast Rates.
52
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
Pro Forma Summary and Projected Savings - CCA Contracts Supply Strategy
(Millions of DolÚlrs Per Year)
Year Commodity Ancillary Operations & Non- Total SDG&E Savings
Costs ServicesilSO Scheduling bypassable Costs Charges
Costs Charges
2006 49.6 3.9 4.2 9.8 67.5 73.9 6.3
2007 50.8 4.0 4.2 9.1 68.2 73.4 5.3
2008 52.2 4.3 4.3 7.8 68.5 73.0 4.5
2009 54.1 4.5 4.4 8.7 71.6 76.2 4.6
2010 57.1 4.8 4.5 9.9 76.3 81.1 4.8
2011 60.2 5.0 4.5 10.5 80.2 75.7 (4.5)
2012 61.7 5.2 4.6 11.5 83.0 78.8 (4.2)
2013 62.9 5.4 4.6 11.8 84.7 82.4 (2.4)
2014 65.0 5.7 4.7 12.0 87.4 87.0 (0.4)
--
2015 69.4 6.1 4.9 12.9 93.3 95.5 2.2
2016 72.5 6.5 5.0 13.1 97.1 99.6 2.4
2017 73.9 6.7 5.0 13.3 99.0 103.7 4.7
2018 75.4 7.0 5.\ 13.6 IOU 108.1 7.0
2019 76.6 7.3 5.1 13.9 102.9 113.0 10.1
2020 78.3 7.6 5.2 14.3 105.5 119.1 13.6
2021 85.3 7.9 5.3 14.5 112.9 123.5 10.6
2022 86.2 8.2 5.3 14.6 114.4 125.1 10.7
2023 87.1 8.4 5.4 9.1 110J 121.0 11.0
53
IV. EVALUATION OF CHULA VISTA'S MEUOPTIONS
CCA --
The following Chart demonstrates that the implementation of the Generation
Supply Strategy would result in substantially greater benefits than the Contracts Supply Strategy
if the City implements the CCA option:
Chula Vista Municipal Electric Utility Annual Cost -
Savings $(000)
25,000
~~oo -
20,000
17,500 -
15,000
12,500
10,000
7,500
5~ -
2,500
0 -
N N N N N N N N N N N N
(2,500) § § ¡¡¡ § ~ ~ ~ ~ ~ ~ ~ ~
(5,000)
(7,500)
I ~ CCA - Generation -8- CCA - Contracts I
54
------- ------
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
Chart 3 graphically compares the total CCA cost-of-service to the generation-
related charges projected for SDG&E.
Chart 3: Comparison ofCCA Costs Based on Contracts Supply Strategy
SOGOEANOCHULA VISTA
POWER SUPPI.V REVENUE REQUIREMENT COMPARISON
'we
no.o
"""
M'
"
~ w.o
0
,.
0
~, 00.0
A
"
w.o
~O
,~~"=,=""o,""~n~,,,",,,",,,"",""'m,~,",","'m,,"">m'
The components of the CCA costs on a dollar per MWh basis are shown below in
Chart 4 for the Contracts Supply Strategy and compared to SDG&E electric commodity related
rates.
55
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA -
Chart 4: CCA Cost Components On A Per MWh Basis
cc, System .....ge Cost
Components 01 Revenue R....i.ement
"".00
-
",00
>00.00
"00 -
~ >0000
~ 50.00
J
~ ".00
00.00
".00
00.00
,~=,="<"'"oo,,«""""""""""""""""""""" """"
d. Intangibles
(1) Benefits
The major benefit available through the electric utility aggregation option is that
the City could begin procuring electric energy and supplying it to retail customers without the
need to purchase the SDG&E electric distribution system.
(2) Risks
On the electric utility side, if the City elects to pursue this option, the CPUC must
confinn or approve the City's implementation plan before final steps to implementation can
occur. At this juncture, it is uncertain how the CPUC will analyze any implementation plan
submitted by the City in light of the current controversy over direct access, exit fees and
scheduling coordination services. As stated above, while AB 117 does provide a statutory basis
for CCA programs, the CPUC has not yet established and implemented the rules for the approval
of a CCA implementation plan.
56
--.---------.--
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
4. LegaJ/Regulatory
CCA is governed b~ the Community Choice Aggregation legislation (AB 117,
Chapter 838, September 24, 2002 9), and the CPUC's corresponding proceeding, Rulemaking
03-10-003 (R03-10-003). If the City elects to pursue the CCA option, the CPUC must confirm
or approve the implementation plan before final steps to implementation can occur. Pursuant to
R.03-IO-OO3, the CPUC is to determine the implementation requirements for CCA, including the
level of any applicable cost responsibility surcharges, IOU administrative charges, and other
costs and restrictions that may be developed. The parameters of the CPUC's proceeding will
dictate the rules governing CCA programs. On November 26, 2003, the assigned Administrative
Law Judge in R03-10-003 issued a ruling bifurcating the proceeding into two phases. The first
phase, which is scheduled for hearings for February 2004, will address many of these cost related
issues. Administrative and ministerial matters will be the subject of the second phase of the
proceeding. Because AB 117 authorized an "opt out" program rather than an "opt in" program,
the City can sign up customers willing to switch /Tom SDG&E generation service to City service
without the necessity of developing an active marketing effort to lure customers. Instead, the
City would merely need to notify customers of the impending community choice aggregation
program. Any customers that do not want to participate in the program would be required to
notify the City of their election to "opt out" within a specified amount of time. The specific rules
governing customer notices will be developed during the course ofR03-1O-003.
AB 117 also requires full cooperation by the host investor owned utility
(SDG&E) in any CCA program implemented by the City. In this regard, SDG&E is required to
provide necessary load information and other important data to the City, and continue to provide
transmission, distribution, metering, meter reading, billing and other essential customer services,
Under ABI17 and the initial rules outlined by the CPUC in R03-IO-OO3, SDG&E would remain
the backup service provider for the City's CCA customers.
5. Financing Options
Implementing a CCA program would not require major capital outlays, with the
possible exception of capital required for generation acquisition. Acquiring interest in a
generation project to support the Generation Strategy would require initial capital expenditures
estimated at $78 Million. This figure is derived on the basis of an assumed ownership of 130
MW of generation at an installed capital cost of $600,000 per MW. Annual debt service to
support this investment would be approximately $5.4 million at an assumed tax-exempt debt
interest rate of 5.5% for an amortization period of 30 years.
19 AB 117 became effective January I, 2003 amends Sections 218.3, 366, 394, and 394.25 of the Public
Utilities Code and adds Sections 331.1, 366.2, and 381.1 to the same Code.
57
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
The City would have a variety of financing mechanisms available to finance its
MEU projects depending upon the specific asset and/or activity. Financing techniques might
include the following:
- General Obligation Bonds -
- Limited Obligation Bonds
- Special Assessment
- Certificates of Participation
- Revenue Bonds
- Commercial Paper
In Appendix C, Section IV.A, at 126-27, the MEU Study Team has provided an
overview and comparative analysis of each type of financing vehicle that is available to the City.
6. Implementation Schedule
a. Major and Critical Steps
The MEU Study Team recommends a two-track approach to evaluate and
implement a CCA project. The following outlines the associated critical path elements for each
track of work:
(1) Track 1 Tasks
1.1 - Project Initiation - Orientation Sessions for Elected Officials and Staff
1.2 - Base Case Feasibility Studies
- Load Forecasts
- Cost-of-Service Analyses
1.3 - Regulatory Engagement-A
Participation in CPUC CCA proceedings and workshops for the development of
costs and credits, rules and protocols; use base case feasibility studies performed
under (1.2) as the basis to demonstrate the impacts of proposed decisions.
1.4 - Track-I Report:
Update base case feasibility study with fmal CPUC adopted costs, credit rules and
protocols; evaluate results and make threshold decision whether or not to proceed
with implementation.
58
-, _..,-----
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
1.5 - CPUC Implementation Plan
- Develop program structure, organization, operations plans and
funding
- Perform Rate Design (cost allocation methodology and disclosure)
- Document participant rights and responsibilities
- Finalize energy supply resource portfolio
- Adopt Implementation Plan in a public hearing20
- Pass City Ordinance to implement CCA as defined in the Implementation Plan21
- File the Implementation Plan with the CPUC
Where third-party suppliers are indicated, evaluate and document their financial,
technical and operational capabilities. If the City intends to pursue an equity
position in generation resources document the same capabilities of the City and/or
its equity partners.
1.6 - Regulatory Engagement-B
Monitor, participate and respond as required to CPUC proceedings and processes
to approve or reject the City's filed Implementation Plan. Pending CPUC
approvals, begin Track 2 tasks.
(2) Track 2 Tasks
2,1 - CCA Implementation
2.1.1. - Register the CCA with the CPUC (may become part of 1.5 above)
2.1.2. - Execute Investor-Owned Utility (IOU) Service Agreement 22
2.1.3. - Determine Required Aggregated Load Metering Facilities 23
20 Cal. Pnb. Util. Code §366.2 (c)(3). ("The implementation plan, and any subsequent changes to it, shall be
considered and adopted at a duly noticed public hearing".)
21 Cal. Pnb. Util. Code §366.2 (c)(lO)(A).
22 The City, as a CCA operator, will need to establish a legal relationship with SDG&E. It is anticipated that
a service agreements will include processes for infonnation exchange, including electronic data
interchange, procedures for settling financial transactions, treatment of customer bill payment funds
transfer, credit tenDs, access to confidential customer infonnation, audit provisions, and regulatory
oversight and complaint processes.
59
_. ""--'""'-""~--'---'"'--"'--- --...---....
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
CCA
2.1.4, - Complete Arrangements for 60-Day Customer Notification
And Opt-Out Provisions
2.1.5. - Notify SDG&E When CCA Service Will Begin
2.2 - CCA Operation (iterative and on-going activities)
2.2.1. - Activate Energy Supply Resource Plan
- Execute Supply Contracts
- Schedule Generation Resources
2.2.2. - Update Load Forecast and Optimize Scheduling
2.2.3. - Manage Supply Portfolio and Risk Management
2.2.4. - Process Financial Settlements "-
2.2.5. - Produce Operating Statements and Reports
b. Timelines
At the tennination of this study period, the City will have completed Tasks 1.1
and 1.2. The CPUC proceedings began on August 21, 2003 and appear to be moving ahead in a
manner to meet the CPUC's expectation of lasting between six and nine months or until
approximately mid-2004. The MEU Study Team strongly recommends that the City remain
actively involved in the ongoing CPUC proceedings in order to help shape the CCA
implementation costs, credit rules and protocols. The MEU Study Team estimates that a CCA
could be operational by 2006. Please refer to Section V.C at 165 and Appendix C, Section Vat
130, for Gantt Chart time requirement projections for each Task described above.
7. Recommendaôon
The MEV Study Team recommends that, subject to the establishment of
satisfactory rules and protocols by the CPUC, the City perfonn Track 1 and 2 Tasks leading to
the fonnation and implementation of Community Choice Aggregation program within the City to
enable the City to commence providing electric utility services to electric consumers within the
City as early as 2006.
23 Identify whether additional metering devices described in Section IV.C.2.a at 40 can be employed. If
feasible and warranted, place a service orders with the IOU to have them installed.
60
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
-
D. Greenfield Development
- The Greenfield municipal utility structure entails the City owning the new electric
distribution facilities in selected developing areas. In newly developing areas in which SDG&E
has yet to install distribution inftastructure, the City can exercise its constitutional authority to
begin to provide electric utility service, and avoid the challenges and expense of acquiring the
existing electric distribution system of SDG&E. The process of implementing a Greenfield
- MEU structure is detailed below in Section IV.D. 6 at 77-79 (Implementation Schedule, (a)
Major and Critical Steps).
Typically, these steps involve land developers performing the identical
-. distribution system construction elements required of them as if the area were to be served by
SDG&E. The difference occurs when the City, as a serving public utility, takes delivery of
wholesale power at the development site's interconnection point (substation) and then resells the
power to end-use consumers located within the newly developed areas. The City utility will
operate and maintain the facilities, establish retail electric rates, and perform all of the functions
- of a traditional municipal utility (customer service, account services, metering and billing). The
creation of a Greenfield utility is possible for the City's consideration at any or in all of the
currently undeveloped portions of the City. The MEU Study Team has worked with City
Planning Division Staff to identify such prospective new development areas. Based upon
planned land use in these areas, the MEU Study Team modeled the site-specific energy
requirements in each of the undeveloped areas identified by the Planning Division Staff.
1. Customer Base
A Greenfield operation would encompass all future electric customers within
selected newly developing areas of the City. Section H.B at 9-16 describes, in detail, the
customer and load projections used in the analysis, and these are summarized in the following
table.
61
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD -
Greenfield Projected Customers, MWh, And Peak MW By Year -
Year Customers MWh Peak MW
2006 4,017 87,863 16 -
2007 4,950 93,849 17
2008 5,728 99,172 18
2009 6,540 ] 14,759 20 -
2010 7,424 152,996 27
2011 7,656 ]63,334 29
2012 7,888 173,713 3] -
2013 8,120 184,132 33
2014 8,408 208,090 37
2015 8,8] I 271,149 48
2016 9,040 280,]95 50 -
2017 9,270 289,286 52
2018 9,499 298,422 53
20]9 9,729 311,332 55 -
2020 9,965 334,685 60
2021 10,041 340,374 61
2022 10,117 346,161 62 -
2023 10,]93 352,046 63
2, Functional Elements -
a, Infrastructure Requirements
-
(1) Distribution System Infrastructure
Prior to addressing the distribution system requirements for the Greenfield option,
an overview of the Greenfield opportunity and load forecast bases is instructive. The MEU
Study Team worked with City Planning Staff to identify the potential development areas that are
not currently served by existing SDG&E distribution infrastructure. Development areas and -
planned land-uses were identified, as well as estimated development schedules. Development
areas were defined according to SANDAG Traffic Analysis Zones (TAZ) and Land-Use
Definitions. The approach supports a City-wide Greenfield utility market potential based on the
analysis and the load forecast discussed in detail in Section ILB at 9-16 and summarized above.
The development areas identified are located within eighteen traffic analysis
zones that are grouped roughly into six potential Greenfield development areas. These areas are
geographically dispersed from one another and with varied development schedules. These are
described below:
62
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Potential Greenfield Develooment Areas
Most Active
Development
Area Descriotion Commercial Residential Periods
1 Bayfront 7.3% 10.8% continuous
2 SunbowlVillage 2 5.1% 25.1% 2005-2010
Village 2-West.
Village 3, Area 18b
3 EastlakelOtay Ranch! 7.2% 41.3% 2010-2015
McMillin Freeway
Commercial
4 University Areas 7.8% 0.0% 2015
5 Vii/age 4, 8 and open space 43.4% 21.4% 2015
6 Remote University Land 29.1% 0.0% not active
100.0% 100%
The "major and critical steps" to implementation provided in Section IV.D.6
below at 77-79 identify the need for electric distribution design firms to work with developers to
design and specify system requirements in compliance with applicable design standards to serve
the planned developments. Given the varied and yet-to-be defined infTastructure requirements of
potentially six different development areas, it would be inappropriate and practically impossible
for the MEU Study Team to attempt an estimate of the number, size and location of trenching,
conduit, vaults and other substructures or required electrical equipment such as conductors,
connectors, switches, transformers or substations.
Suffice it to say, that the Greenfield option requires the investment in the
distribution infiastructure described above. The Greenfield utility activity would also require
infTastructure to support the operations and maintenance of the distribution system. These
include service vehicles, maintenance crews and equipment inventories as well as infTastructure
to support customer service functions and investment in customer call centers and billing
operations.
Additional infTastructure requirements include those necessary for the activities
related to electric portfolio operations. These activities include those necessary to procure
electricity in the wholesale markets, schedule electricity transactions with the CAISO, and
conduct financial settlements for wholesale electricity purchases and sales,
To estimate distribution facilities cost, the MEU Study Team relied on the
benchmarked replacement-cost-new amount of $3,000 per customer described and supported in
Appendix C, Section ILE at 84-87.
63
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Section IV.D.6.a below at 77-79 identifies major and critical steps required to
implement a Greenfield utility option. Step 6.a (8) describes high-voltage subcontractors
installing the electrical components. Currently, developers are reimbursed for certain costs
associated with this step by SDG&E and most of the state's electric utilities, The financial
analyses of potential Greenfield benefits must show that the City can capture these costs. If
Greenfield promoters fail to account for costs, the affect is a cost shift /Tom utility operations to
developers and ultimately to project occupants, Developers and the California Building Industry
Association oppose such practices.
(2) InterconnectionlWDA T Costs
The development of a Greenfield utility option would require that the City take
wholesale transmission service /Tom SDG&E and/or the CAISO. The City will need to develop
the necessary in/Tastructure to interconnect with SDG&E. The City may not be interconnected
with SDG&E at a transmission voltage, but rather at a distribution voltage, and therefore, the
City would not only take wholesale transmission services /Tom SDG&E, but also take service
under SDG&E's WDAT, a copy of which is included as Appendix D.
The cost for taking wholesale distribution service under the WDAT would be
detennined by SDG&E based on an assessment of the actual distribution facilities utilized by the
City. SDG&E would perfonn a study to determine the allocated portion of pre-existing facilities
that should be assigned to the Greenfield utility as well as any new facilities, which are required
to interconnect the Greenfield utility to SDG&E's system. SDG&E would then apply a fixed
carrying charge percentage to detennine an annual revenue requirement and monthly demand
charge for the distribution facilities. The fixed carrying charge is derived to recover SDG&E's
cost of capital, depreciation, operations and maintenance expenses, and tax expenses related to
the facilities. The monthly demand charge would be applied to the monthly kW demand
recorded at the meter at the interconnection point between the Greenfield distribution system and
SDG&E's system.
The first year costs for constructing the distribution infTastructure needed to serve
the Greenfield areas are estimated at $13.8 million. These costs include the following:
64
- --------------- ___On -- -----------.-
IV. EV ALVATION OF CHULA VISTA'S MEV OPTIONS
GREENFIELD
Investment Cost
Distribution Facilities $12.1 Million
InterconnectionlWDA T $0.7 Million
RegulatorylLitigation $0.5 Million
Inventory $0.5 Million
Total $13.8 Million
--
The infrastructure requirements identified herein will result in implementation
- costs of $13.8 million. These costs will be amortized over 30 years with an annual debt service
to support the investment of approximately $1.3 million, at an assumed tax-exempt debt interest
rate of 5.5% (see Pro Forma table below at 74under Distribution Capital. Operational costs are
reflected as annual costs in financial pro fonna under "Distribution O&M,,)?4
b. Resource Management
In developing the resources for the Greenfield utility business model, the MEV
Study Team detennined the stand-alone Greenfield utility was not of a sufficient size to support
the development of a generation project. Therefore, the projected power supply for the
Greenfield utility is 100 percent contract based. The electric supply portfolio evaluated for
Greenfield includes the following fixed priced contracts.
Power Purchase Contracts - Greenfield Option
Year Product Quantitv (MW) Price ($/MWh) Tenn
2006 Base (7 x 24) 5 49 4 Years
2006 Peak (6 x 16) 10 59 4 Years
2010 Base (7 x 24) 12 50 5 Years
2010 Peak (6 x 16) 15 60 5 Years
2015 Base (7 x 24) 15 51 5 Years
2015 Peak(6x 16) 25 61 5 Years
2020 Base (7 x 24) 20 54 4 Years
2020 Peak(6x 16) 25 65 4 Years
24 See Appendix C, Section II.I at 92, line V.(B)(i).
65
IV. EVALUATIONOFCHULA VISTA'S MEUOPTIONS
GREENFIELD
Renewable Energy Contracts - Greenfield Option
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) I 52 I Year
2007 Base (7 x 24) I 51 1 Year -
2008 Base (7 x 24) 1 52 1 Year
2009 Base (7 x 24) I 52 I Year
2010 Base (7 x 24) 2 52 I Year -
2011 Base (7 x 24) 2 53 I Year
2012 Base (7 x 24) 2 54 1 Year
2013 Base (7 x 24) 3 54 I Year -
2014 Base (7 x 24) 3 54 I Year
2015 Base (7 x 24) 5 54 1 Year
2016 Base (7 x 24) 5 53 I Year -
2017 Base (7 x 24) 5 53 I Year
2018 Base (7 x 24) 7 55 3 Years
2021 Base (7 x 24) 8 58 3 Years
-
A generation portfolio was not evaluated for the Greenfield option due to the
infeasibility of sizing and locating a base load facility within the small geographic areas served
by the Greenfield utility. Small, distributed generation (DG) could be used to supply the
Greenfield areas. However, stand-alone DG units operate at a lower efficiency than central
station power, and the use of DG would not represent a cost-effective substitute for wholesale
market purchases, absent some cost-mitigating factor. The benefits of DG are typically
attainable where there is a cogeneration opportunity that utilizes thennal energy for a different
production process or when "behind the meter" DG can be used to reduce the retail rates paid to
the local utility. Under the Greenfield option, the City becomes the incumbent utility. Under
this scenario, a significant portion of the DG benefits (avoidance of certain incumbent utility
charges) would no longer be applicable to the City in consideration of DG in the Greenfield
utility model.
In the case of cogeneration, the efficiency gain from converting waste heat to
usable energy can make DG cost-effective. In the case of behind the meter DG, the DG unit can
cost-effectively compete with the higher retail rate of the utility. In contrast, a standalone DG
used to supply the Greenfield utility would be forced to compete directly with the wholesale
market price, which typically reflects the superior operating efficiency of central station power.
Additional details regarding the power supply portfolios modeled for the City is
included in Appendix C. 25
25 See Appendix C. Section II.B at 68-73.
66
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
c. Operation and Maintenance
Operations and maintenance cost assumptions for the City's Greenfield operations
are based upon benchmarking the operation of similar sized utilities on a per customer served
basis (see Appendix C, Section VLA at 133 National Public Utility O&M Benchmarking).
However, it is assumed that, in the early years (team recommendations are until 2011), the City
will outsource most required functions and the utility cost-basis serves as an effective proxy for
competitive subcontract services.
The benchmarking studies reflect a high correlation of O&M costs, on a per
customer basis, with the size of the given utility. The Greenfield utility business model projects
customer populations beginning in 2006 of 4,017 increasing to 10,193 by 2023. As reflected in
the study, the City's prospective Greenfield utility customer populations align with benchmark
panel strata 5 and 6 (see Appendix C, Section VLA at 133). Accordingly, Greenfield utility
business model financial pro fonna reflect annual O&M ranging /Tom $478 to $333, per
customer, depending upon customer populations.
d. Human Resource Requirements
The human resource requirements to operate the Greenfield utility distribution
system present the City with two distinct options. The first is to develof and staff an
organization capable of perfonning the required activities (construction,2 maintenance,
operation, customer service, and billing). The second option would be to outsource these
functions. The MEU Study Team recommends, if the City pursues a business model consisting
solely of a Greenfield utility, that the City outsource most of these functions for the first several
years of operation. Alternatively, minimum staffing requirements are estimated as follows:
26 As described above, most of the necessary construction work on the electric distribution system will be
perfonned by the developers and their contractors or subcontractors on a reimbursable basis.
67
~~~~_.~ ~-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Greenfield Human Resource Requirements
Function Number of Staff
Management 2
Oistributi>n Engineering and Opemti>n 12
Customer Service 6
Power Opemtions 2
Finance ---1.
Total 23
Based upon the projected buildout of the Greenfield development areas described
in Section II, and the benchmark of utility personnel per 1,000 customers served as shown in the
Appendix C , Section VLB at 134, the minimum functional staff of twenty-three (23) would be
justified in approximately 2011 (see Greenfield Area Projected Customer Population Chart
below).
Prior to full operational status of the Greenfield option, the MEU Study Team
recommends that the City staff this activity with a project manager and two distribution system
engineers, and that the City time this staffing to coincide with the onset ofthe f¡rst Greenfield
area development. Further, the City should rely on objective discipline area specialists to
manage requisite subcontractor activities (RFPs, evaluation of bids, and selection of contractors).
68
.--
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Greenfield Areas Projected Customer Populations
12,000
10,000
8,000
6,000
- 4,000
2,000 - -----
In addition to operating the distribution system, the operation of a Greenfield
utility will require wholesale power procurement and scheduling. The MEU Study Team
assumes the City will outsource most required functions, such as scheduling coordination (24-
hour per day operation), trading, risk management, pre-scheduling, and real-time operations.
However, the MEU Study Team has identified the following minimum functions which will need
to be staffed:
Minimum Portfolio Operations - Greenfield
Function Staff
Settlements 1
Procurement/Contracts 1
Rates 1
Credit 1
Management 1
5
The cost to support these minimum requirements is estimated at $400,000 per
year (see Appendix C, Section VI.D at 140). Wholesale power providers will support the
remaining functions as part of a full-requirements service contract. The premium for these
services can range between $5 and $10 per MWh depending upon the supplier and procurement
volumes. To be conservative, the MEU Study Team adopted a projected cost of $10 per MWh.
69
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Based upon this asswnption and projected Greenfield utility energy requirements,
it becomes less expensive to perfonn the services in-house in year 2011. In 2011 the minimwn -
staffing costs identified above, escalated at 2.5% per year, are projected to be $452,000. Charges
for the outsourced services are projected to reach $1.6 million in 2011, at that time the City
should consider staffing all portfolio operations and scheduling positions.
3. Costs and Benefits
-
a. Financial Analyses
A financial analysis was perfonned in order to develop financial pro fonna, which -
was then structured as consolidated statement of income for each MEU structure option. The
consolidated statement based on the financial pro fonna for the Greenfield option is located in
this report in Appendix C, Section II.I at 92. As noted above, savings or potential income is the
margin between current retail power costs, as provided by SDG&E, and the given MEU structure
option's projected cost to provide the power. The MEU Study Team began its evaluation of each
utility structural option with a planning horizon beginning in 2004 and then projected costs
forward to 2023. Evolving legislation, regulation, implementation lead times and cost
considerations caused the MEU Study Team to project MEU implementation beginning in 2006. -
The resulting study period was subsequently revised /Torn 2006 to 2023 as reflected in the
financial pro fonna for each MEU structure option.
As a regulated public utility, SDG&E provides utility services at regulated cost-
based rates. Hence, SDG&E's rates are directly tied to a demonstrated revenue requirement and
its rate structures attempt to provide an equitable cost allocation among customer classes. The
financial analysis provided herein compares SDG&E's revenue requirement with the revenue
requirement of each MEU structure option to detennine the City's potential savings or income.
Pro fonna summary tables compare each MEU structural option based on its relative ability to
produce operational cost savings or benefits.
The Greenfield utility structure option financial analysis evaluates the costs and
benefits for the City to take the following actions: 1) acquire development area distribution
system in/Tastructure /Torn developers (trenching, conduits and substructures); 2) subcontract the
installation of high-voltage and other electrical components, and establish interconnection of the
Greenfield distribution system; (3) procure and schedule energy to supply the needs of
development occupants; 4) operate and maintain the Greenfield electric distribution system; and
5) provide retail customer service as required by Greenfield development area occupants.
70
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
b. Financial Analysis Structure
Greenfield utility customer population electric loads, evaluated under Section II.B
at 9-11 and summarized above at 61-62, are applied to SDG&E current and projected generation
rates to yield its revenue requirement or retail customer energy costs. Greenfield operating
expenses are projected and subtracted /Torn SDG&E's revenue requirement to yield the projected
financial benefit. Elements contained in the analysis are summarized below:
J;. SDG&E Forecast Generation Rates27
- Utility Retained Generation
- Qualifying Facility Generation
- Bilateral Power Purchase Contracts
- CAISO charges
- Residual Spot Market Purchases or Sales
J;. Greenfield Energy Cost (Commodity CostS)28
- Spot Market Purchases
- Power Purchase Contracts
- Renewable Energy Contracts
J;. California Independent Svstem Operator Charges (CAISO)29
- Transmission
- Ancillary Service
- Grid Management
- Reliability Services
- Congestion Costs
- Grid Operations
- Unaccounted for Energy
- Neutrality Adjustments
- Deviation Charges
J;. Transmission and Scheduling Costs30
-Scheduling and Settlements System
27 See Appendix C, Section II.A at 64-67.
28 See Appendix C, Section 1I.B.2 at 68-77
29 See Appendix C, Section II.D at 83-84.
30 See Appendix C, Section 11.8.3 at 77-78.
71
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
-Procurement and Maintenance Costs
-Labor
~ Non-Bvuassable Charges31
-CPUC Exit Fees
Uneconomic Utility Retained Generation and Power Contracts
DvrRPowerPurchaseContrac~
DvrR Bond Charges - Financing Past Purchases
-Other Non-Bypassable Charges
Public Purpose Program Charges32 --
Nuclear Decommissioning Charges
Fixed Transition Amount Charges
~ Distribution System Capital cosr3
Costs Associated with Acquiring the Distribution System Assets
~ Distribution System Operations and Maintenance Costs34
~ In-Lieu Pavrnents to Replace Lost Revenues35
Lost or Reduced Franchise Fee Payments
Lost or Reduced Property Tax Payments
c. Pro Forma Modeling Results
Total estimated costs of Greenfield operations are summarized in the table below
for the Contracts Supply Strategy and are compared to projected SDG&E electric commodity
related charges. The costs of Greenfield operations are broken out among the major cost of
service elements. The most significant of these costs is the electric commodity costs. The
31 See Appendix C, Section 1I.C at 78-81.
J2 Public Purpose Program Charges are included herein to support an evaluation of savings based on a
comparison of baseline SDG&E customer bill charges and the charges customers would pay under this City
MEV business model. However, revenue collected by the City associated with this charge would be
available to the City to allocate to various activities that are identified in the Appendix C, Section 1I.C.2 at
81-82.
33 See Appendix C, Section 1l.E at 84-87.
34 See Appendix C, Section 1l.F at 87-88.
3S See Appendix C, Section 1I.H at 88-89.
72
--~---------_.
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
commodity costs primarily reflect the long-tenn power purchase contracts that fonn the core of
the supply portfolio, as well as the renewable energy contracts and spot market purchases.
-
The next largest cost category is transmission, operations and scheduling. One
.- reason for the lack of early year savings for the Greenfield operation is the incurrence of start-up
and fixed costs related to staffing the portfolio operations and scheduling coordinator functions.
At start up, these costs must be spread over a relatively low volume of MWh sales. Lower costs
could likely be achieved if the City outsourced these functions during the ramp-up stage of
Greenfield operations. Potential outsourcing vendors include power marketers, scheduling
coordinators, or consulting finns possessing the specialized knowledge and skill to enable them
to perfonn these wholesale procurement functions. Such cost savings would very likely make
the Greenfield operations revenue neutral or slightly positive during the initial years. As the load
of the Greenfield operation grows, the City could then staff-up and perfonn these functions in-
- house.
Another major cost category relates to the non-bypassable charges or exit fees that
SDG&E will impose on the Greenfield utility operation, pursuant to CPUC authority. Other
significant costs include the financing charges for the Greenfield's distribution capital
investments and distribution operations, which includes operations and maintenance, customer
service and infonnation (billing), and administrative and general expenses. Less significant costs
include ancillary services and ISO charges and foregone franchise fee payments and in lieu
payments for county property taxes.
-
As stated earlier, savings are the difference between the Greenfield costs and the
charges that SDG&E would collect through rates under the status quo retail electric arrangement.
Persistent savings begin to occur in 2012 as the Greenfield load profile benefits /Tom the addition
of a larger number of electricity users. The addition of large commercial and industrial loads
over time enables the distribution infTastructure to be used more intensively, lowering average
costs and rates. The fixed costs of the distribution system and other fixed costs can be spread
over a larger volume of electricity sales. However, the large savings shown to begin in 2015
should be interpreted with some caution due to the fact that an increasing proportion of high
average use customers are projected for the Greenfield development, and these customers may
require greater than average distribution infTastructure costs. A conservative conclusion would
be that a Greenfield utility operation would lose money in the near tenn and commence
producing savings in 2012. See chart below.
73
IV. BV ALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
Pro Forma Summary and Projected Savings - Greenfield Contracts Supply Strategy
(Millions of Dollars Per Year)
Ancillary Transmission Non- -
Commodity Services/lSO & Bypassable Distribution Distribution Franchise To",1 SDG&E
Year Costs Costs Schedulin. Char.es Caoital O&M Feesffaxes Costs Char.es Savin.s
2006 5.2 0.7 2.8 1.9 1.3 1.2 0.1 13.3 13.0 (0.3)
2007 5.5 0.7 2.8 2.0 1.6 1.5 0.1 14.2 13.7 (0.5)
2008 5.8 0.8 2.9 1.6 1.8 1.8 0.1 14.7 14.1 (0.7) -
2009 6.6 0.9 3.0 1.9 2.0 2.1 0.1 16.7 16.5 (0.2)
2010 9.5 1.3 3.5 2.7 2.3 2.4 0.1 22.0 22.1 0.1 -
2011 9.9 1.4 3.6 2.9 2.4 2.6 0.1 23.0 22.6 (0.3)
2012 10.4 1.5 3.6 3.2 2.4 2.7 0.1 24.1 24.5 0.4 --"
2013 11.0 1.6 3.7 3.4 2.5 2.9 0.1 25.3 26.4 1.1
2014 12.3 1.8 3.9 3.8 2.6 3.1 0.1 27.5 30.4 2.9
2015 16.5 2.5 4.6 4.9 2.7 3.3 0.1 34.6 40.3 5.7
--
2016 16.9 2.5 4.7 5.1 2.8 3.4 0.1 35.5 42.4 6.8
2017 17.3 2.7 4.7 5.2 2.9 3.6 0.1 36.6 44.6 8.0
-
2018 18.1 2.8 4.9 5.4 2.9 3.8 0.1 38.1 46.8 8.8
2019 18.8 3.0 5.0 5.6 3.0 4.0 0.1 39.5 49.8 10.3
--
2020 21.3 3.4 5.3 6.1 3.1 4.2 0.1 43.5 54.5 11.0
2021 21.9 3.5 5.4 6.2 3.1 4.3 0.1 44.7 56.5 11.8
2022 22.2 3.7 5.5 6.3 3.1 4.5 0.1 45.5 57.4 12.0
2023 22.6 3.8 5.5 4.9 3.1 4.6 0.1 44.7 56.9 12.2
74
IV. EVALUATIONOFCHULA VISTA'S MEUOPTIONS
GREENFIELD
Chart 5 graphically compares the total Greenfield cost of service to the
generation-related charges projected for SDG&E.
Chart 5: Comparison of Greenfield Costs Based on Contracts Supply Strategy
rÆIJ 9,SBn /INenq! QJOts
Carporø1Is á -.... Recl-iÆlTEl1l
100
100
140
""
~
" 100
:.
.
.. 00
;3
00
40
'"
= == """ 2)10 2)1' ""22)132)1'2)15 ""6""72)18 ""9 = "'" """ "'"
Pro forma detail for the Greenfield option is located in the accompanying Appendix C.36
d. Intangibles
(1) Benefits
Many of the benefits previously discussed under the CCA option would also
apply with this utility structure, including the likelihood of lower-priced energy, local control,
improved reliability, and economic development enhancements. An additional benefit of a
36 See Appendix C, Section 11.1 at 92.
75
--~------- -----.
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD -
Greenfield municipalization effort would be that the City would not need to purchase the existing
distribution facilities /Tom SDG&E and go through a lengthy condemnation process. --
(2) Risks
-
One of the impediments that would play out, at least through the initial
infTastructure development period, is the economic viability of the program. Since at least part
of the in/Tastructure would need to be in place before customers began to consume the energy, -
there would need to be enough working capital and cash flow to get through the first few years as
development came "on-line." Construction of some distribution facilities such as line, poles, and
extensions would be phased in as development progresses. However, some facilities may need -
to be constructed first, such as a substation with capacity to meet future load growth. Previous
analysis and studies have shown that, if the load growth and development plan are well
constructed, no more than a three-year "float" period should occur before energy revenue begins -
to pay for all related Greenfield start-up costs and operational expenses. Another major cost
impediment is that the amount of energy required to serve the Greenfield utility operation starts
out very small. Under those circumstances, the City may not be able to secure power at as
competitive rates as it could if it was purchasing power to serve a larger load.
4. LegallRegulatory
With the exception of rules requiring the payment of Cost Responsibility -
Surcharges, or "exit fees," discussed in Appendix B, Section H.C.4 at 35-39, there are no specific
state laws or Commission rules regulating the implementation of the Greenfield development
option. Furthermore, such implementation is not restricted by the terms of the Chula Vista City
Charter, and the City has adequate authority under the California Constitution and state statutes
to provide electric service to its inhabitants. Federal law governs the interconnection of the city-
owned distribution facilities with the facilities of SDG&E and the CAISO. The law regarding
interconnection requirements is also addressed in Appendix B, Section H.C.3 at 33-35.
5. Financing Options
Implementation of a Greenfield Utility will require a significant initial capital
investment, as well as ongoing annual capital investments. The investment will be mainly for -
distribution plant, including physical distribution equipment, associated equipment required for
maintenance, and computer hardware and software. Assuming an initial Greenfield utility with
approximately 4,000 customers, the start-up capital costs are estimated at $13.8 million, Annual
debt service to support the initial investment would be approximately $1.3 million at an assumed
tax-exempt debt interest rate of 5.5% (amortization period 30-years). Annual debt service
requirements would increase over time as additional Greenfield areas are developed, as shown in
the financial pro forma results.
76
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
The City would have a variety of financing mechanisms available to finance its
Greenfield projects depending upon the specific asset to be required or built and/or activity.
Financing techniques might include the following:
~ General Obligation Bonds
~ Limited Obligation Bonds
~ Special Assessment
~ Certificates of Participation
~ Revenue Bonds
~ Commercial Paper
In Appendix C, Section IV.A, at 126-27, the MEU Study Team has
provided an overview and comparative analysis of each type of financing vehicle that is
available to the City.
6. Implementation Schedule
a. Major and Critical Steps
(I) Ordinance:
City passes an ordinance to form a municipal utility (City has already
passed Ordinance No. 2835).
(2) System Design:
Electric distribution design firms will work with developers to design and
specify system requirements in compliance with applicable design
standards to serve the planned development. (2-3 mo.)
(3) Determine Interconnection ReQuirements:
Assess technical requirements and cost to achieve interconnection of the
development distribution system with adjacent transmission or distribution
facilities. If the given Greenfield development is going to be
interconnected with facilities operating below transmission system voltage
levels (which for SDG&E is 138kV), and served at distribution voltage
levels (most likely 12-69 kV), it will need to be served under SDG&E's
WDAT. If this is the case, the City must complete an application for
service according to the SDG&E WDAT.37 SDG&E will perform a
37 A copy of the SDG&E WDAT is attached in Appendix D.
77
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
facilities requirement and system impact study to detennine the logistics
and the cost to implement an interconnection with the SDG&E system, A
successful application will result in the execution of a service agreement
which sets forth the costs, terms and conditions of service. (6-9 mo.)
(4) Final Evaluation:
Evaluate and assess projected loads, costs and benefits (at this point,
primarily interconnection costs) and determine whether to proceed with
the project. (I mo.)
(5) Procure and Schedule Power:
Based on load studies and forecasts derived /Tom information provided
under item (2), tailor and initiate a resource and schedule power delivery
to coincide with project completion and estimated development
occupancy. Update power delivery schedules, as required before
operational status as provided in power contract terms and conditions, to
balance loads and resources. (2 mo.)
(6) Staffing/Outsourcing:
Initiate human resources plan. Update plans to reflect development
schedules and requirements; perform staffmg or solicit outsource staffing
services. (2 mo.)
(7) InfTastructure Construction:
Land developer subcontractors will install electric system infTastructure,
including trenching, conduit, backfill, vaults, manholes and transformer
pads (as they would ifSDG&E were to serve the area). (2-5 weeks)
(8) High Voltage Eauipment Installation:
The City will engage subcontractors specializing in high-voltage
interconnection to pull conductors through the conduit, install substations,
connectors, switches, transformers and connections with metered panels
(residents, businesses, etc). (2-3 weeks)
78
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
GREENFIELD
(9) PeriDherai EauiDment:
City will install peripheral electrical equipment (traffic
controllers/irrigation pedestals/street lights). (2-3 weeks)
(10) Initiate ODerations:
Schedule and initiate Greenfield utility operations to coincide with the
occupancy date for newly developed area. (I mo. - occupancy date)
b. Timelines
The MEU Study Team estimates that the steps identified above would take
between 15 and 20 months to complete /Tom the time electric distribution system design finus
begin working with developers. Operation of a new Greenfield utility project will depend upon
actual project completion and building occupancy in the newly developed area. The project
implementation schedule Gantt chart, Section V.C at 168 and Appendix C, Section II.V.B at 131,
is structured in months /Tom the onset of any given Greenfield development project.
7. Recommendation
The MEU Study Team recommends that the City immediately commence the
implementation of Steps 6 (a)(2) through (10) above to enable the City to commence providing
electric utility services through Greenfield utility projects in the developing areas of Mid-
Bay/Tont, Otay Ranch and Sunbow Planning area. Establishment and operation of Greenfield
utility projects in newly developed areas within the City will provide a vehicle for the City to
establish an operating electric utility and to gain the experience and staffing necessary to
combine its Greenfield utility operations with its CCA program (see discussion in Section E
below) and, eventually, to acquire and operate a full service municipal electric distribution
system (see discussion in Section F below).
79
------------------------------.--
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD
E. Combined Community Choice Aggregation/Greenfield Development
-
As identified in Section III.B, the MEU Study Team's analysis demonstrates that
the City can obtain the greatest potential benefit by forming a CCA and simultaneously pursuing
Greenfield project opportunities. Ideally, the City would acquire equity in a generation project
within the City to supply the combined CCAlGreenfieid loads. A CCA program would give the
City the operational scale required to efficiently source electricity for the CCA and Greenfield
customers and compete successfully with the electric supply portfolio of SDG&E.
The Greenfield utility option, in and of itself, is not of a sufficient size to support
- the development of a cost-effective generation project. However, implementing the combination
of CCA and Greenfield options would capture the benefits of CCA in areas where there is an
SDG&E distribution inftastructure. This would produce commensurate levels of savings on the
- electric energy commodity component for Greenfield areas and significantly increase Greenfield
project cost-effectiveness.
- In this scenario, the City would implement a city-wide CCA program concurrent
with efforts to begin distribution utility operations in Greenfield development areas. The City
- would supply electricity to all electric customers within the City38 and distribute electricity to
electric customers within the Greenfield development areas.
For non-Greenfield areas, the City would procure electric supply for customers of
the CCA, and SDG&E would continue to deliver the electricity to end use customers over
distribution facilities owned and operated by SDG&E. Customers would pay SDG&E the retail
rate for non-generation charges (e.g., transmission and distribution) as they do today. SDG&E
would provide a credit on the bill to remove its costs related to generation and procurement of
electricity that would be procured by the CCA. The bill credit that SDG&E will provide for
generation-related charges is assumed to be the entire generation rate, net of the applicable exit
fees. SDG&E would continue to perform metering and billing services for end use customers,
the costs of which are bundled within existing retail distribution rates.
For the Greenfield development areas, the City would take wholesale
transmission service /Tom SDG&E and the CAISO, and its customers in the Greenfield
development area would no longer pay SDG&E electricity retail rates. Once the Greenfield
development is interconnected to SDG&E's distribution system, the City would take service
under SDG&E's WDAT.
The cost for taking wholesale distribution service under the WDA T would be
determined by SDG&E based on an assessment of the actual distribution facilities utilized by the
38 Except those that "opt out" under the CCA option. In studying this option, the MEV Study Team assumed
100% participation in the CCA program.
80
IV. EVALUATION OF CHOLA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD -
City. SDG&E would perform a study to determine the allocated portion of pre-existing facilities
that should be assigned to serve the Greenfield utility, as well as any new facilities required to -
interconnect the Greenfield utility. It would then apply a fixed carrying charge percentage to
determine an annual revenue requirement and monthly demand charge for the distribution
facilities, The fixed carrying charge is derived to recover SDG&E' s cost of capital, depreciation, -
operations and maintenance expenses, and tax expenses related to the facilities. The monthly
demand charge would be applied to the monthly kW demand recorded at the meter at the
interconnection point between the Greenfield distribution system and SDG&E's system. -
The City, or its customers, would be subject to the payment of the exit fees and
other non-bypassable charges mandated by AB 1890 and CPUC orders. 39 The distribution -
capital costs associated with City-owned distribution system serving the Greenfield development
will be determined based on the cost to construct the required new facilities,
1. Customer Base
A CCA program would encompass all electric customers within the City -
boundaries, except those in the Greenfield development areas and those who have notified the
City of their desire to opt out of the CCA program and continue to receive electric commodity -
supply service from SDG&E. As mentioned above, the feasibility analysis assumes 100%
participation in the CCA program, The chart below is based on the same assumption. Section
II describes in detail the customer and load projections used in the analysis, and these are
summarized in the following table, The customer base is shown below for the CCA program,
with the loads of the Greenfield development customers removed.
39 See Appendix C, Section II.C at 78-81.
81
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCNGREENFIELD
CCA Projected Customers, MWh, And Peak MW By Year, Excluding Greenfield Customers
-
Year Customers MWh Peak MW
2006 82,635 774,323 131
- 2007 84,462 792,524 134
2008 86,032 809,730 137
2009 87,608 827,266 140
- 2010 88,313 841,550 143
2011 88,911 851,778 145
2012 89,515 862,159 146
2013 90,124 872,697 148
- 2014 90,738 883,393 150
2015 91,218 895,478 153
2016 91,698 907,742 155
- 2017 92,180 920,188 157
2018 92,662 932,817 160
2019 93,145 945,633 162
- 2020 93,624 958,439 164
2021 93,840 969,808 166
2022 94,058 981,323 168
- 2023 94,276 992,986 170
This chart assumes that all customers in newly developed areas will be served as
- Greenfield project customers and that CCA projected customers will be limited to areas now
served by SDG&E.
- A Greenfield operation would encompass all future electric customers within
newly developing areas of the City. Section II.B at 9-17 describes in detail the customer and
load projections used in the analysis, and these are summarized in the following table.
82
-
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCA/GREENFIELD -
Greenfield Projected Customers, MWh, And Peak MW By Year
-
Year Customers MWh Peak MW
2006 4,017 87,863 16
2007 4,950 93,849 17 -
2008 5,728 99,172 18
2009 6,540 114,759 20
2010 7,424 152,996 27 -
2011 7,656 163,334 29
2012 7,888 173,713 31
2013 8,120 184,132 33
2014 8,408 208,090 37 -
2015 8,811 271,149 48
2016 9,040 280,195 50
2017 9,270 289,286 52 -
2018 9,499 298,422 53
2019 9,729 311,332 55
2020 9,965 334,685 60 -
2021 10,041 340,374 61
2022 10,117 346,161 62
2023 10,193 352,046 63 -
2. Functional Elements -
a, Infrastructure Requirements
-
(1) CCA Infrastructure
The infrastructure requirements for the development of a CCA program is fully -
discussed and set forth in Section IV.c.2.a above at 40 and will not be repeated herein.
(2) Greenfield Infrastructure
-
(a) Distribution System Infrastructure
The Distribution System Infrastructure necessary to implement a Greenfield -
development project is fully described and set out in Section IV.D.2.a(l) above at 62 and will not
be repeated herein.
-
-
83
-
-
-
IV, EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD
-
- (b) InterconnectionlWDA T Costs
- The wholesale distribution costs which would be imposed pursuant to the
SDG&E WDAT are fully described and set out in Section IV.D.2.a (2) above at 64 and will not
be repeated herein.
- b. Resource Management
- An advantage of pursuing the Greenfield option in conjunction with the CCA
option is that the larger combined customer loads provide critical mass and would enable the
City to pursue generation ownership as a feasible supply option. Internal generation would
- minimize the total electric supply costs of the combined CCAlGreenfield operation for several
reasons. First, the production costs of a new Combined Cycle Gas Turbine are expected to be
below market-clearing prices. In essence, the CCAlGreenfield option would allow the City to
- capture generation profits within the CCAlGreenfield operation. In addition, generation located
within the City boundaries would enable the City to avoid paying transmission congestion
charges, which are assessed by the CAISO for use of the transmission grid when congestion is
- present. Electricity obtained via power purchase contracts mayor may not be subject to charges
for transmission congestion, depending on whether the point of delivery specified in the contract
would require the use of the CAISO-controlled transmission grid.
For CCA customers, the transmission charges for the fixed costs of the
transmission network, as opposed to transmission congestion charges, are not impacted by the
- location of the generator due to the fact that, under CCA, the retail transmission rates of SDG&E
will continue to apply.
For Greenfield areas, internal generation would minimize wholesale transmission
charges and other charges assessed b6' the CAISO. So long as the internal generator operates at a
capacity factor greater than 50%,4 FERC rules require transmission access charges to be
assessed on a net load basis, i.e., the internal generation is subtracted /Tom the gross load
requirements of the Greenfield utility before applying the transmission rates. In addition,
internal generation reduces the exposure to charges for reliability services and certain elements
of the CAISO's grid management charge.
These wholesale transmission related benefits would not be obtained if the City
were to supply its load through power purchase contracts or ownership of remote generation that
40 Capacity factor is a measure of utilization for a power plant. A plant with a maximum generating capacity
of 130 MW would have to produce at least 47,450 MWh in a month (130 MW x 730 hours x 50%) in order
to obtain a capacity factor of at least 50%.
84
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCA/GREENFIELD -
must utilize the CAISO-controlled transmission network for delivery to the CCA/Greenfield
utility. -
The MEU Study Team has modeled generation options for the City using
operating and cost parameters of a new combined cycle gas turbine operating as a base load -
plant. These parameters include the unit's heat rate, capacity cost, variable O&M costs'"
availability factor, hours of planned operation, and the year the resource becomes operational.
Sales of any excess production beyond what is needed to serve the City's load could be sold into -
the market. The price for excess sales reflects a 25% discount relative to the prevailing peak or
off-peak price to reflect the probability that excess sales will occur during the lowest priced
hours of the on- or off-peak periods. -
The following assumptions were used in the calculation of generation costs:
Capacity: 130MW -
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh -
Capacity Factor: 90%
Variable O&M: $2 Per MWh
Excess Sales: 75% of Market Price -
The Contracts supply portfolio evaluated for the CCA/Greenfield option includes
the following fixed priced contracts. -
Power Purchase Contracts - CCA/Greenfield Option
-
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 50 49 5 Years
2006 Peak (6 x 16) 75 59 5 Years -
2011 Base (7 x 24) 50 51 5 Years
2011 Peak (6 x 16) 75 61 5 Years
2016 Base (7 x 24) 75 51 5 Years -
2016 Peak(6xI6) 100 61 5 Years
2021 Base (7 x 24) 75 55 3 Years
2021 Peak (6 x 16) 125 66 3 Years
--
41 See discussion in Section (I.e.! at 21-22.
-
85
--
-
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- COMBINED CCAIGREENFIELD
The following renewable energy contracts were assumed in the MEU portfolios
- for both the Generation and Contracts Supply Strategies:
Renewable Energy Contracts - CCAIGreenfield Option
-
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 7 52 1 Year
- 2007 Base (7 x 24) 8 51 I Year
2008 Base (7 x 24) 10 52 I Year
2009 Base (7 x 24) II 52 I Year
2010 Base (7 x 24) 13 52 1 Year
- 2011 Base (7 x 24) 15 53 I Year
2012 Base (7 x 24) 17 54 1 Year
2013 Base (7 x 24) 18 54 1 Year
- 2014 Base (7 x 24) 20 54 1 Year
2015 Base (7 x 24) 23 54 1 Year
2016 Base (7 x 24) 25 53 I Year
- 2017 Base (7 x 24) 28 53 I Year
2018 Base (7 x 24) 29 55 3 Years
2021 Base (7 x 24) 30 58 3 Years
-
Additional details regarding the power supply portfolios modeled for the City are
- included in the Appendix C, Section TI.B.2 at 68-77.
c. Operations and Maintenance
(1) Operations and Maintenance CCA
- The operations and maintenance requirements for a CCA program, modeling
projected costs, are discussed and set forth in Section IV.C.2.c at 44 and will not be repeated
herein.
(2) Operations and Maintenance Greenfield
The operation and maintenance requirements for a Greenfield development
project, including projected costs, are discussed and set forth in Section IV.D.2.c at 67 and will
not be repeated herein.
86
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD
-
d. Human Resource Requirements
(1) Human Resource Requirements - CCA -
The human resource requirements for a CCA program, including both in-house
personnel and outsourcing, are discussed and set forth in Section IV.C,2.d at 44 and will not be -
repeated herein.
(2) Human Resource Requirements - Greenfield -
The human resource requirements for a Greenfield Utility, including projected -
costs to operate the distribution system, are discussed in Section IV.D.2.d at 44-45 and are not
repeated herein. The human resource requirements to perform wholesale power procurement,
including the need to outsource related functions, would no longer be required of the Greenfield -
utility operation and can be performed by CCA portfolio operations and scheduling personnel.
This reduces the Greenfield utility staffing and operational costs by between $1.2 and $2.0
million per year, as reflected in the financial pro forma. -
3. Costs and Benefits
-
a. Financial Analysis
The financial analysis for the CCA option is set forth in Section IV.C.3.a at 45-46 -
above. The financial analysis for the Greenfield option is set forth in Section IV.D.3.a at 70
above.
-
b. Financial Analysis Structure
CCA and Greenfield customer population electric loads, evaluated under Section
ILB at 9-16 and summarized above at 81-83, are applied to SDG&E current and projected
generation rates to yield the City's revenue requirement or retail customer energy costs. CCA
and Greenfield operating expenses are projected and subtracted from SDG&E's revenue
requirement to arrive at the projected financial benefits for the City. Elements contained in the
analysis are summarized below:
þ> SDG&E Forecast Generation Rates42
- Utility Retained Generation
- Qualifying Facility Generation
- Bilateral Power Purchase Contracts
- CAISO charges
42 See Appendix C, Section I1.A at 64-67.
87 -
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- COMBINED CCAIGREENFIELD
- Residual Spot Market Purchases or Sales
» CCA and Greenfield Energy Cost (Commodity CostS)43
- Spot Market Purchases
- - Power Purchase Contracts
- Renewable Energy Contracts
- Generation Ownership
-
» California Independent Svstem Operator Charges charges (CAISO)44
Ancillary Service
- Grid Management
Reliability Services
Congestion Costs
Grid Operations
Unaccounted for Energy
Neutrality Adjustments
Deviation Charges
» Transmission and Scheduling Costs45
- Scheduling and Settlements System
Procurement and Maintenance Costs
Labor
» Non-Bvoassable Charges46
-CPUC Exit Fees
Uneconomic Utility Retained Generation and Power Contracts
DWR Power Purchase Contracts
DWR Bond Charges - Financing Past Purchases
-Other Non-Bypassable Charges (applies to Greenfield portion only)
Public Purpose Program Charges47
43 See Appendix C, Section II.B.2 at 68-77.
44 See Appendix C, Section H.D at 83-84.
4S See Appendix C, Section II.B.3 at 77-78.
46 See Appendix C, Section II.C at 78-81.
47 Public Purpose Program Charges are included herein to support an evaluation of savings based on a
comparison of baseline SDG&E customer bill charges and the charges customers would pay under this City
MEV business model. However, revenue collected by the City associated with this charge would be
available to the City to allocate to various activities that are identified in Appendix C, Section II.C.2 at 81-
82.
88
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD -
Nuclear Decommissioning Charges
Fixed Transition Amount Charges -
» Greenfield Distribution Svstem Capital Cost48
Costs Associated with Acquiring the Distribution System Assets -
» Greenfield Distribution System Operations and Maintenance Costs49
-
» Greenfield In-Lieu Pavrnents to Replace Lost Revenues50
Lost or Reduced Franchise Fee Payments
Lost or Reduced Property Tax Payments -
The hybrid CCAlGreenfield business model cost benefits are assessed based upon
two energy supply strategies. In the first supply strategy, it is assumed the City's MEU will take -
an ownership position in a power generation facility (Generation Supply Strategy). In the
second, it is assumed the City's MEU will purchase all of its energy requirements in the
wholesale energy market by executing power contracts with suppliers (Contracts Supply _.
Strategy).
Power costs are allocated to resource supply options for the given supply strategy -
as follows:
-
-
--
-
--
48 See Appendix C, Section 1l.E at 84-87.
49 See Appendix C, Section II.F at 87-88.
50 See Appendix C, Section II.H at 88-89.
89
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD
2006 Energy Resource Costs ($) by Supply Strategy
Greenfield Areas
-
Generation Contracts
- Market Purchases $106.014 2.3% $92,684 1.6%
Contracts $455.520 10.0% $5.594.200 96.4%
Power Production $3,983.306 87.6%
-,
$4.544,840 $5.686.884
CCA Areas
Generation ~
Market Purchases $4.382,988 11.1% $3.069,022 6.9%
Contracts $2,733,120 6.9% $41.500,040 93.1%
Power Production $32,532,245 82.1%
$39.648.353 $44.569.062
Generation Strategy - Major Capital Expenditures:
Implementing a CCAlGreenfield business model with the Generation Supply Strategy requires
acquiring an interest in a generation project. The Generation Supply Strategy would require an
initial capital expenditure estimated at $78 million. This figure is derived based on an assumed
ownership of 130 MW at an installed capital cost of $600,000 per MW. Annual debt service to
support this investment would be approximately $5.4 million at an assumed tax-exempt debt
interest rate of 5.5%. This cost, as well as generation facility operations and maintenance and
fuel cost, is included in the Pro Forma Table at 92 below under "Commodity Costs" and in
Appendix C, Section ILl at 93 and 94, Section V. Operating Expenses, (A)(iii) Power
Production.
c. Pro Forma Results
Financial pro forma results were prepared for the CCAlGreenfield option with
both supply strategies, See Appendix C, Section ILl at 93-96.
90
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD -
(1) CCAlGreenfield - Generation
-
Total estimated costs of the CCAlGreenfield combined option are summarized in
the table below for the Generation Supply Strategy and compared to projected SDG&E electric
commodity charges. The costs of CCAlGreenfield operations are broken out among the major -
cost of service elements. The most significant of these is the electric commodity costs, which
consist primarily of the capital and operating costs of the CCAlGreenfield's generator, plus
renewable energy contract costs and spot market purchases. The next largest cost category is the -
non-bypassable charges or exit fees that SDG&E will impose on the CCAlGreenfield operation,
pursuant to CPUC authority.
-
Other significant costs include transmission, operations, and scheduling, ancillary
service, CAISO charges, financing charges for the Greenfield distribution capital investments,
and distribution operations, which includes operations and maintenance, customer service and -
infonnation (billing), and administrative and general expenses. Less significant costs include
foregone /Tanchise fee payments and in lieu payments for county property taxes related to the
Greenfield facilities. -
Savings represent the difference between the CCAlGreenfield costs and the
charges that SDG&E would have collected through rates under the status quo retail electric -
service arrangements. Significant savings are projected to occur in every year of the study
period as shown on the following chart.
-.
-
-
-
-
-
91
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- COMBINED CCAIGREENFIELD
Pro Forma Summary and Projected Savings - Combined CCAIGreenfield Generation
- Supply Strategy
(Millions of Dollars Per Year)
- Year Commodity Ancillary Transmission Non- Distribution Distribution Franchise Total SDG&E Savings
Costs ServiceslISO & bypassable Capital O&M Feesffaxes Costs Charges
Costs Schedulin. Char.es
- 2006 44.2 2.4 4.2 10.6 1.3 1.2 0.1 64.0 78.9 14.9
2007 44.3 2.5 4.3 10.0 1.6 1.5 0.1 64.3 79.1 14.7
- 2008 46.6 2.7 4.4 8.4 1.8 1.8 0.1 65.8 78.8 13.0
2009 48.7 3.0 4.5 9.3 2.0 2.1 0.1 69.8 83.0 13.3
- 2010 51.6 3.4 4.8 10.8 2.3 2.4 0.1 75.5 90.1 14.6
2011 53.5 3.6 5.0 11.4 2.4 2.6 0.1 78.5 85.6 7.0
- 2012 55.5 3.8 5.1 12.5 2.4 2.7 0.1 82.2 89.4 7.3
2013 56.5 4.0 5.2 12.9 2.5 2.9 0.1 84.1 93.8 9.7
- 2014 58.7 4.3 5.4 13.2 2.6 3.1 0.1 87.4 100.0 12.5
2015 63.1 5.0 6.0 14.4 2.7 3.3 0.1 94.6 112.4 17.8
- 2016 63.5 5.2 6.1 14.7 2.8 3.4 0.1 95.9 117.2 21.3
2017 64.5 5.4 6.3 14.9 2.9 3.6 0.1 97.7 122.2 24.4
-
2018 67.5 5.7 6.4 15.3 2.9 3.8 0.1 101.8 127.3 25.6
2019 69.9 6.1 6.6 15.6 3.0 4.0 0.1 105.3 133.3 28.0
-
2020 72.6 6.5 6.8 16.2 3.1 4.2 0.1 109.6 141.1 31.5
2021 75.8 6.9 6.9 16.4 3.1 4.3 0.1 113.6 146.1 32.6
2022 78.7 7.2 7.0 16.7 3.1 4.5 0.1 117.3 148.1 30.8
2023 79.1 7.4 7.2 11.2 3.1 4.6 0.1 112.7 144.5 31.7
92
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCAIGREENFIELD
-
(2) CCAlGreenfield - Contracts
The total estimated costs of the CCAlGreenfield combined option are summarized -
below for the Contracts Supply Strategy and compared to projected SDG&E electric commodity
charges. The costs of CCAlGreenfieid operations are broken out among the major cost of
service elements. The most significant of these is the electric commodity costs. The commodity -
costs primarily reflect the long-term power purchase contracts that form the core of the supply
portfolio, as well as the renewable energy contracts and spot market purchases. The next largest -
cost category includes the non-bypassable charges or exit fees that SDG&E will impose on the
CCAlGreenfield operation, pursuant to CPUC authority.
Other significant costs include transmission, operations, and scheduling, ancillary -
service, CAISO charges, financing charges for the Greenfield distribution capital investments,
and distribution operations, which includes operations and maintenance, customer service and -
information (billing), and administrative and general expenses. Less significant costs include
foregone /Tanchise fee payments and in lieu payments for county property taxes related to the
Greenfield facilities. --
Significant savings are projected to occur in all but two years of the study period.
Projected SDG&E rate reductions in 2011, resulting /Tom the expiration of DWR power -
purchase contracts, would eliminate any savings until 2013. At that time, annual increases in
SDG&E rates, combined with the cost efficiencies gained /Tom the addition of more or larger
customers to the overall Greenfield customer mix are projected to provide persistent savings -
opportunities for the City as shown on the chart below.
-
-
-
-
-
-
93 -
-
IV. EV ALVATION OF CHULA VISTA'S MEV OPTIONS
- COMBINED CCAIGREENFIELD
Pro Forma Summary and Projected Savings - Combined CCA/Greenfield Contracts
- Supply Strategy
(Millions of Dollars Per Year)
Year Commodity Ancillary Traosmission Non- Distribution Distribution Franchise Total SDG&E Savings
- Costs ServiceslISO & bypassable Capital O&M Feesffaxes Costs Charges
Costs Schedulin. Char.es
2006 49.7 4.2 4.7 10.6 1.3 1.2 0.1 71.9 78.9 7.1
-
2007 50.8 4.3 4.8 10.0 1.6 1.5 0.1 73.2 79.1 5.9
- 2008 52.2 4.5 4.9 8.4 1.8 1.8 0.1 73.8 78.8 5.0
2009 54.1 4.8 5.1 9.4 2.0 2.1 0.1 77.6 83.0 5.4
- 2010 57.8 5.4 5.6 11.0 2.3 2.4 0.1 84.7 90.1 5.5
2011 60.3 5.6 5.7 11.6 2.4 2.6 0.1 88.3 85.6 (2.7)
- 2012 61.7 5.8 5.8 12.6 2.4 2.7 0.1 91.2 89.4 (1.8)
2013 62.9 6.1 5.9 13.0 2.5 2.9 0.1 93.3 93.8 0.4
- 2014 64.8 6.4 6.1 13.3 2.6 3.1 0.1 96.4 100.0 3.6
2015 69.8 7.2 6.8 14.5 2.7 3.3 0.1 104.4 112.4 8.0
- 2016 72.6 7.6 6.9 14.8 2.8 3.4 0.1 108.3 117.2 8.9
2017 74.0 7.8 7.0 15.1 2.9 3.6 0.1 110.6 122.2 11.6
-
2018 75.5 8.2 7.2 15.4 2.9 3.8 0.1 113.2 127.3 14.2
2019 76.7 8.6 7.3 15.8 3.0 4.0 0.1 115.5 133.3 17.8
-
2020 79.8 9.1 7.7 16.4 3.1 4.2 0.1 120.4 141.1 20.7
2021 85.0 9.4 7.8 16.6 3.1 4.3 0.1 126.4 146.1 19.8
2022 85.9 9.8 7.9 16.8 3.1 4.5 0.1 128.2 148.1 19.9
2023 86.8 10.0 8.0 11.3 3.1 4.6 0.1 124.1 144.5 20.4
Pro fonna detail for the CCAlGreenfield option is located in the accompanying
Appendix C, Section II.! at 93-96.
94
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCA/GREENFIELD -
The following chart demonstrates that the adoption of a Generation Supply
Strategy would result in substantially greater benefits than the Contracts Supply Strategy if the -
City implements a combined CCA/Greenfield option:
Chula Vista Municipal Electric Utility Annual Cost
Savings $(000) -
35,000 -
32,500
30,000
27,500 -
25,000
~ßOO -
20,000
17,500
15,000
12,500
10,000 -
7,500
5,000 -
2,500
0
'" '" '" '" '" '" '" '" '" '" '" -
(2,500) 8 8 8 ~ ~ ~ ~ ß ß ß ß
m ~ 00 m ~ 00 ID 0 ~ '" ~
(5,000)
I-*"' CCA/Greenfield . Generation --a- CCA/Greenfield - Contracts I -
95
IV. EVALUATION OF CHULA VISTA'S MEV OPTIONS
COMBINED CCNGREENFIELD
4. LegallRegulatory
Pursuing a program which combines both Greenfield development and a CCA
program will not alter the legal requirements for either option. There are no legal impediments
- (or advantages) to pursuing both options simultaneously or in tandem.
5. Financing Options
-
a. CCA Financing
.- Implementing a CCA program would not require major capital outlays, with the
possible exception of capital required for generation acquisition. Acquiring interest in a
generation project to support the Generation Supply Strategy would require initial capital
- expenditures estimated at $78 million. This figure is derived based on an assumed ownership of
130 MW at an installed capital cost of $600,000 per MW. Annual debt service to support this
investment would be approximately $5.4 million at an assumed tax-exempt debt interest rate of
5.5%.
b. Greenfield Financing
Implementation of Greenfield projects will require a significant initial capital
investment, as well as ongoing annual capital investment. The investment will be mainly for
distribution plant for physical distribution equipment, associated equipment required for
maintenance, and computer hardware and software. Assuming an initial Greenfield development
with approximately 4,000 customers, start-up capital costs are estimated at $13.8 million.
Annual debt service to support the initial investment would be approximately $1.3 million at an
assumed tax-exempt debt interest rate of 5.5%, Annual debt service requirements would
increase over time as additional Greenfield areas are developed, as shown in the financial pro
forma results.
c. Methods of Financing
The City would have a variety of fmancing mechanisms available to finance its
MEU projects depending upon the specific asset and/or activity. Financing techniques might
include the following:
~ General Obligation Bonds
~ Limited Obligation Bonds
~ Special Assessment
~ Certificates of Participation
~ Revenue Bonds
~ Commercial Paper
96
IV, EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCNGREENFIELD
In Appendix C, Section IV.A at 126-27, the MEU Study Team has provided an overview and -
comparative analysis of each type of financing vehicle that is available to the City.
6. Implementation Schedule -
a. Major and Critical Steps
-
The major and critical steps to implement a CCA project are discussed and
outlined in Section IV.C.6.a at 58-60 and will not be repeated herein. The major and critical
steps to implement a Greenfield project are discussed and outlined in Section IV.D.6(2) at 77-79 -
and will not be repeated herein. Suffice it to say that, in combining the Greenfield and CCA
options, the critical steps and timing will remain relatively unchanged.
-
b. Timelines
The implementation schedules for the CCA and Greenfield MEU options can -
move forward simultaneously and the two options can be implemented on approximately the
same schedule depending on separate variables.
-
In the case of the CCA option, the largest unknown is the development and
implementation of final CCA rules and regulations by the CPUC. As discussed earlier, the
CPUC initiated its CCA rulemaking procedure on August 21,2003 and issued Rulemaking No. -
R-03-09-007 on September 4, 2003. On October 2, 2003, the CPUC reissued the rulemaking
under Docket No. R.03-10-003 and an initial pre-hearing conference and a workshop have been
held. It is anticipated that final CCA rules and regulations will be implemented by mid-2004, -
and, under this schedule, the MEU Study Team estimates that a CCA program could be
operational by mid-2005. (Please refer to Section V.C at 167 and Appendix C, Section V.A at
130 for Gantt chart time requirement projection for each critical path necessary to form a CCA,)
In the case of a Greenfield Project, the operation of any Greenfield Project will
depend upon actual project completion and building occupancy in the newly developed areas
designated for Greenfield development. The MEU Study Team estimates that the steps
necessary to implement a Greenfield Project would take from 15 to 20 months to complete /Tom
the time the City Staff and an electric distribution design firm begin working with the developers
of the Greenfield areas. The project implementation schedule (Gantt Chart) in Section V.C at
169 and Appendix C, Section V.8 at 131, is structured in months /Tom the onset of any given
Greenfield development project.
97
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
COMBINED CCA/GREENFIELD
7. Recommendation
The detailed economic and financial analysis performed by the MEU Study Team
demonstrates that the City can obtain the greatest potential benefit in the short term by forming a
- CCA and simultaneously pursuing Greenfield project opportunities. Under the most beneficial
option, the City would build or acquire equity in a generation project (130 MW) within the City
to supply the combined CCA/Greenfield loads. The CCA program would give the City the
.- operational scale required to effectively source electricity for the CCA and Greenfield customers
and successfully compete with the electric supply portfolio ofSDG&E.
Based on the financial pro forma performed by the MEU Study Team, the
combined CCA/Greenfield utility option, using in-City generation would produce savings
amounting to $14.9 million in 2006 and increase to $31.7 million in 2023 (again with significant
reductions in savings in the 2011-2014 time /Tame).
The MEU Study Team strongly recommends that the City implement the
combined CCA/Greenfield utility option in the immediate future. The MEU Study Team
estimates that a CCA program would be operational by mid-2005 (assuming that the CPUC
issues final rules and regulations by mid-2004). With respect to Greenfield development, the
MEU Study Team estimates that the initial Greenfield project could be implemented in a 15 to
20 month time /Tame depending upon the construction schedule and building occupancy within
the designated Greenfield areas. Thus, a combined CCA/Greenfield operation could be
implemented as early as 2006.
98
-- -~-----~---- --~-------
.-
IV. EV ALVA TION OF CHULA VISTA'S MEU OPTIONS
MDU
-
F. Municipal Distribution Utility
- Under the Municipal Distribution Utility (MDU) option, the City would acquire,
by negotiation or through the exercise of eminent domain, the electric distribution facilities of
SDG&E within the City's boundaries. The MDU would provide retail electric service to all
- customers within the City after interconnecting its distribution system with SDG&E and
establishing an electric resource portfolio by installing generation facilities, through power
- purchases /Tom California electric markets, or a combination of internal generation and
purchased power contracts.
- To the extent that the City relies on purchases /Tom other suppliers, the MDU
would take wholesale transmission service /Tom SDG&E under SDG&E's WDAT, which
defines the applicable charges and tenus and conditions of transmission service and customers
- would no longer pay SDG&E's retail rates.
Once the City elects to acquire the SDG&E distribution system, SDG&E would
- be required to perfonn a study to detennine the cost of any reconfiguration of the SDG&E
system in order to separate and interconnect the MDU system with the remaining SDG&E
system. The FERC would, in the event of a dispute, detennine the tenus and conditions of the
- interconnection of the MDU with the SDG&E transmission system and the interconnection and
related costs would be directly assigned to the MDU.
- If the City and SDG&E cannot agree on the tenus and conditions of the
acquisition, including the pricing of the distribution system, the City will be required to initiate
and prosecute the condemnation of SDG&E distribution system and allow the condenmation
- court (or, alternatively, the CPUC) to detennine the value of the facilities acquired and any
related severance costs.
- The MDU option would require a substantial investment in distribution
in/Tastructure to distribute electric power to the customers of the City's MDU. These costs have
been identified and estimated by the MEU Study Team at approximately $185 million. 51 The
City or its customers would also be subject to the payment of exit fees and other non-bypassable
charges mandated by Assembly Bill 1890 and related CPUC orders. 52
Once established, the MUD would become a full service electric distribution
utility and commence serving some 86,652 retail electric customers with an electric load of
approximately 147 megawatts.
51 Annual debt service to support this investment is approximately $20.2 million at an assumed taxable debt
interest rate of 6.5%. See Appendix C, Section Il.E at 84-87.
" See discussion in Section IV.F.4.b.(4) below at 125-26.
99
_.
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
1. Customer Base -
An MDU would encompass all current and future electric customers within the
City bonndaries. Section ILB at 9-16 describes in detail the customer and load projections used -
in the analysis, and these are summarized in the following table.
MDU Projected Customers, MWh, And Peak MW By Year -
Year Customers MWh Peak MW
2006 86,652 862,186 147 -
2007 89,412 886,373 151
2008 91,761 908,902 155
2009 94,149 942,025 160
2010 95,737 994,546 170 -
2011 96,567 1,015,112 174
2012 97,403 1,035,872 177
2013 98,244 1,056,829 181 -
2014 99,146 1,091,483 188
2015 100,028 1,166,627 201
2016 100,738 1,187,938 205 -
2017 101,449 1,209,474 209
2018 102,161 1,231,239 213
2019 102,875 1,256,965 217 -
2020 103,589 1,293,124 224
2021 103,881 1,310,182 227
2022 104,174 1,327,483 230 -
2023 104,469 1,345,032 233
2. Functional Elements
a, Infrastructure Requirements
(1) Distribution Infrastructure
The MDU option would require substantial investment in distribution infrastructure
to distribute power to customers of a City MDU. Such infrastructure would include:
. Distribution Substations
. Primary Distribution Transformers
. Primary Distribution Wires and Poles
. Final Line Transformers
-
100
-
-
IV. EV ALUA TION OF CHULA VISTA'S MEU OPTIONS
- MDU
. Secondary Distribution Feeders
- . Meters
Under the MDU planning scenario, the City would acquire the SDG&E
- distribution plant and equipment located within the City's jurisdiction by negotiated purchase or
by exercising its power of eminent domain and condemning the property, A comprehensive
engineering analysis of distribution equipment inventories, system configuration and condition is
- required in the valuation phase, prior to the system's negotiated purchase or condemnation. In
this phase of evaluation, the MEU Study Team applied average per customer distribution
investment benchmarks, as well as SDG&E's reported depreciated book values, to estimate the
- value of SDG&E facilities within the City. These estimates are set forth in the Appendix C,
Section II.E.2 at 84-87.
The SDG&E distribution system value is estimated at $170 million. System start-
up costs (service vehicles, inventory, customer service call center and billing equipment) are
estimated at $15 million, making the total acquisition costs of implementing the MDU option
- approximately $185 million.
(2) Supply Portfolio Operations Infrastructure
-
To procure wholesale energy, the systems identified below must be employed.
The City may elect to procure these systems or in the alternative, obtain these services under a
- full-requirements supply contract. Under a full-requirements supply contract, the required
systems and support services would be provided and the associated costs would be bundled into
a power contract and embedded in the commodity cost. However, systems and support service
costs must be known to quantifY the embedded commodity premium in order to allow the City to
make informed procurement decisions.
101
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-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
System Requirements
~ ~ ~ ~ Potential Outsourcino -
Scheduling/Settlements Software $650.000 40% $476.667 Scheduling Coordinator
Risk Management Software $150.000 40% $110.000 Power Marketer
EDI/IOU Transactions $100.000 40% $73.333 Consultant -
Scheduling Server $50.000 10% ruMI Scheduling Coordinator
Total Systems Costs $661.667
-
b. Resource Management
(1) Energy Supply - Generation -
The MEU Study Team has modeled generation options for the City using
operating and cost parameters of a new combined cycle gas turbine operating as a base load
plant. These parameters include the unit's heat rate, capacity cost, variable O&M costs,
availability factor, hours of planned operation, and the year the resource becomes operational. 53
Sales of any excess production beyond what is needed to serve the City's load could be sold into
the market. The price for excess sales reflects a 25% discount relative to the prevailing peak or
off-peak price to reflect the probability that excess sales will occur during the lowest priced
hours of the on or off peak periods.
The following assumptions were used in the calculation of generation costs:
Capacity: 130MW
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh
Capacity Factor: 90%
Variable O&M: $2 Per MWh
Excess Sales: 75% of Market Price
The MDU operation would benefit by ownership of generation within the City as
compared to securing power through power purchase contracts for several reasons. First, the
production costs of a new combined cycle gas turbine are expected to be below market-clearing
prices, In essence, the MDU would able to capture generation profits within the MDU operation.
In addition, generation located within the City boundaries would enable the City to avoid paying
transmission congestion charges, which are assessed by the CAISO for use of the transmission
grid when congestion is present. Electricity obtained under power purchase contracts mayor
may not be subject to charges for transmission congestion, depending on whether the point of
" See discussion in Section 1I.c.2 at 21-22.
102
-
IV. EV ALOATION OF CHOLA VISTA'S MEO OPTIONS
- MOO
delivery specified in the contract would require the use of the CAISO-controlled transmission
- grid.
Internal generation minimizes wholesale transmission charges and other charges
- assessed b~ the CAISO. So long as the internal generator operates at a capacity factor greater
than 50%, 4 FERC rules require transmission access charges to be assessed on a net load basis,
i.e., the internal generation is subtracted from the gross load requirements of the MOO before
- applying the transmission rates. In addition, internal generation reduces the exposure to charges
for reliability services and certain elements of the CAISO's grid management charge. The
benefits of internal generation to the MOO's cost-of-service from reduced transmission and
- CAISO charges are estimated to be approximately $6 million per year.55
These wholesale transmission related benefits would not be realized if the City
were to supply its load through power purchase contracts or ownership of remote generation that
- must utilize the CAISO transmission grid for delivery to the City's MOO.
(2) Energy Supply - Power Contracts
-
The Contracts supply portfolio evaluated for MOO includes the following fixed
priced contracts:
-
Power Purchase Contracts - MDU Option
- Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 50 49 5 Years
2006 Peak (6 x 16) 75 59 5 Years
2011 Base (7 x 24) 50 51 5 Years
2011 Peak (6 x 16) 75 61 5 Years
2016 Base (7 x 24) 75 51 5 Years
2016 Peak (6 x 16) 100 61 5 Years
2021 Base (7 x 24) 75 55 3 Years
2021 Peak (6 x 16) 125 66 3 Years
54 Capacity factor is a measure of utilization for a power plant. A plant with a maximum generating capacity
of 130 MW would have to produce at least 47,450 MWh in a month (130 MW x 730 hours x 50%) in order
to obtain a capacity factor of at least 50%.
55 The CAISO transmission and other charges are discussed and quantified in Appendix C, Section ILD at 83-
84.
103
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
The following renewable energy contracts were used in modeling the MDU
portfolios for both the Generation and Contracts Supply Strategies: -
Renewable Energy Contracts - MDU Option
-
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 7 52 I Year
2007 Base (7 x 24) 8 51 1 Year -
2008 Base (7 x 24) 10 52 I Year
2009 Base (7 x 24) 11 52 I Year
2010 Base (7 x 24) 13 52 1 Year
2011 Base (7 x 24) 15 53 I Year -
2012 Base (7 x 24) 17 54 I Year
2013 Base (7 x 24) 18 54 I Year
2014 Base (7 x 24) 20 54 1 Year -
2015 Base (7 x 24) 23 54 1 Year
2016 Base (7 x 24) 25 53 I Year
2017 Base (7 x 24) 28 53 I Year -
2018 Base (7 x 24) 29 55 3 Years
2021 Base (7 x 24) 30 58 3 Years
-
See Appendix C, Section ILB.2 at 68-77.
c. Operations and Maintenance -
(1) Distribution Operations and Maintenance Costs
The MEU Study Team used the results of a nationwide benchmarking study of -
municipal electric utilities to estimate distribution O&M costs for the City. The study groups
municipal electric utilities by size into five strata and reports average per customer O&M costs
within each strata for distribution O&M, customer service expenses, and administrative and -
general expenses. The average total annual distribution O&M costs reported by participants in
the study range from $246 to $594 per customer. reflecting a wide range of urban and rural
municipal utilities of various sizes and population densities. -
The MEU Study Team has also used a targeted set of case studies of California
municipal electric utilities to obtain O&M estimates that would be more reflective of the costs
expected for the City municipal electric utility. Data are available for years 1998-2001, and the
average total annual distribution O&M costs range from $231 to $380 per customer. For this
analysis, the four-year average per customer O&M costs of California municipal utilities of
similar size as Chula Vista was used to predict the cost for distribution operations. Four
municipal utilities with between 50,000 and 90,000 customers were selected. These were
Burbank, Glendale, Pasadena, and the Turlock Irrigation District.
104
-
.-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
-. MDU
- Based on this analysis, the average annual O&M cost estimated for the City is
$270 per customer. By comparison, the MEU Study Team has calculated the average
distribution O&M costs for the entire SDG&E system to be $198 per customer, using the
- following SDG&E FERC Form I data:
Categorv Amount
-
Distribution O&M $76,310,456
Customer Service O&M $78,025,205
- Allocation of A&G $94,739,319
Total Distribution O&M $249,074,980
Total Customers 1,255,268
- Distribution O&M Per Customer $198
The lower figure for SDG&E reflects the economies of scale in distribution
.- operations that are not available to smaller distribution systems. The capital financing and tax
advantages of municipal electric utilities are offset to a degree by higher per capita O&M costs
typical of smaller utilities.
-
(2) Electric Portfolio Operations
- O&M activities related to electric portfolio operations include those necessary to
procure electricity in the wholesale markets, schedule electricity transactions with the CAISO,
conduct financial settlements for wholesale electricity purchases and sales, and interface with
SDG&E who would be providing billing, metering, and customer services to CCA customers.
Portfolio operations costs are the costs associated with various activities related to
procuring electricity for retail customers. Portfolio operations activities include load forecasting,
procurement of electricity /Tom wholesale electricity sellers, risk management and controls.
Activities related to retail pricing (load research, cost of service, rate design) are also included in
this cost category for purposes of the pro forma analysis.
Scheduling coordination costs are the costs associated with scheduling and
settling electric supply transactions with the CAISO. The analysis assumes that the City would
become a CAISO certified Scheduling Coordinator, which would require acquisition of
scheduling and settlements software and operation of an around-the-clock scheduling desk.
Total costs of portfolio operations and scheduling coordination are modeled as a
combination of fixed and variable costs. Fixed costs, largely associated with the minimum
required personnel, are approximately $2,000,000 per year. Variable costs are estimated at $2.50
105
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
per MWh to account for increases in the size and sophistication of the portfolio operations and
corresponding increases in the overall size of the utility. -
d. Human Resources
-
The MDU human resource requirements were detennined through a six-step
approach. The first step assessed the number of full-time employees (FTE) per utility customer at
fifteen publicly owned California electric utilities. 56 The second step applied the number of -
employees into the following five functional work groups based upon the percentage of total
FTE population in four prototypical utility operations:
-
1. Executive Management (and support staff)
2. Distribution Engineering & Operations
3. Customer and Energy Services -
4. Power Operations
5. Finance
-
The third step identified the percentage of employees in each position within the
given work group; position specific FTE requirements were derived. The fourth step identified
those functional positions where the number of employees correlates highly with the number of -
customers they serve. Such positions include meter readers, call center customer service
representatives, line crew technicians and foremen, substation technicians and supervisors. The
number of employees required in these positions was adjusted to reflect that correlation based on -
benchmarked transactional volumes.
The fifth step identified those positions that are not correlated with customer
numbers or transaction volumes. Such positions correlate with system and shift requirements
such as SCADA system operators, power schedulers and real-time operators where operations -
often operate across 3-shifts, 24 hours per day. The sixth step applied employee payroll, benefits
and overhead expense to employee populations to provide a cross check with pro fonna O&M
cost assumptions based upon reported national, state and regional electric utility O&M costs. -
No employees were allocated to power plant operation and maintenance. The
MEU Study Team recommends that, if the City takes an equity position in generation facilities, it -
rely upon the primary equity holder to operate or subcontract the operation of the facilities,
The chart on the following page lists the MDU human resource requirements by
organization and position:
" See Appendix C, Section IV.B at 134-38, California Public Utility Statistics.
106
-.-- ----
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MDU
- MDU Human Resource Requirements
Director & Support Staff
- 3
Finance Mgr. & Sup! Staff
3
- Dlstribullon Englnaering & Operations Cuatom.. & Enargy Sarvlces Pow.. Operations Group
Manager & Support Staff 2 Customer & Energy Services Mgr. 1 Portfolio Operations
ESRs 4 Management 3
- Substations (SuperviSOrs and Tech.s)
19 Field Sarvices 2 Rates/Forecasting 3
Mater Readers 14 Resource Planning 2
Dispatch (SCADA) 3 Trading/Risk Management 4
Operat... 12 Credo & Cc>lections 1 WholesaJe Settiements 2
- Accounting 3 Pr..Schedulers 2
Construction 4 Call Ctr CSRs 8 Real Time Desk 8
Troubleshooters 5 Billing Clerks 5 Credit 1
Materials Techs 2 IOU Transactions/Audits 2
Une Crew and Foremen 32 IT Support 1
Metering
Electronics Techs 4 Power Production
Power Plant Op.s 0
Service Planning (New Services) 1
Engineering Techs 5
Orafting Techs 4
Engineering 1
Power Engineers 5
Computer Maintenance 1
100 38 28
rotal MDU Staff 170
3. Costs and Benefits
a. Financial Analyses
A financial analysis was perfonned to render financial pro fonna structured as
consolidated statements of income for each MEU structure option. The consolidated statements
based on the financial pro forma are located in this report in Appendix C, Section ILl at 97-98.
As noted above, savings or potential income is the margin between current retail power costs
charged by SDG&E, and each MEU option's cost to provide the power. The MEU Study Team
began its evaluation of each utility structure option with a planning horizon beginning in 2004
and projected costs 20-years forward to 2023. Evolving legislation, regulation, implementation
lead times and cost considerations caused the MEU Study Team to project MEU implementation
107
.-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
-
beginning in 2006. The resulting study period was subsequently revised /Tom 2006 to 2023, as
reflected in financial pro forma for each MEU option. -
As a regulated public utility, SDG&E provides utility services at regulated cost-
based rates. Hence, SDG&E's rates are directly tied to a demonstrated revenue requirement and -
its rate structures are required to affect equitable cost allocation among customer classes. The
financial analysis provided herein compares SDG&E's revenue requirement with the revenue
requirement of each MEU option to determine potential savings or income. Pro forma summary -
tables compare each MEU option based on its relative ability to produce operational cost savings
or benefits.
-
The financial analysis for the MDU option evaluates the costs and financial
benefits for the City to take the following actions: I) acquire SDG&E's electric distribution
system and perform operation and maintenance activities; 2) obtain required electric energy -
resources through entitlement to power plant production and/or /Tom wholesale power contracts;
and 3) provide full electric utility services to the City's residents and businesses.
-
b. Financial Analysis Structure
SDG&E's current and projected electric rates were applied to the MDU customer -
population electric loads, evaluated under Section ILB at 9-16 and summarized above at 100, to
arrive at SDG&E's revenue requirement or retail customer energy costs. The MDU's operating
expenses were projected and subtracted from SDG&E's revenue requirement to arrive at the -
projected financial benefit. The elements contained in the analysis are summarized below:
~ SDG&E Forecast Generation Rates57 .-
- Utility Retained Generation
- Qualifying Facility Generation
- Bilateral Power Purchase Contracts -
- CAlSO charges
- Residual Spot Market Purchases or Sales .-
~ MDU Ener!!:Y Cost (Commodity CostS)58
- Spot Market Purchases -
- Power Purchase Contracts
- Renewable Energy Contracts
- Generation Ownership
57 See Appendix C, Section ILA at 64-67.
58 See Appendix C, Section II.B.2 at 68-77.
108
-
IV. EV ALUA TION OF CHULA VISTA'S MEU OPTIONS
- MDU
- þ> California Independent System Operator Charges charges (CAISO)59
Ancillary Service
Grid Management
- Reliability Services
Congestion Costs
Grid Operations
- Unaccounted for Energy
Neutrality Adjustments
Deviation Charges
-
þ> Transmission and Scheduling Costs60
Scheduling and Settlements System
Procurement and Maintenance Costs
Labor
- þ> Non-Bvpassable Charges61
-CPUC Exit Fees
Uneconomic Utility Retained Generation and Power Contracts
- DWR Power Purchase Contracts
DWR Bond Charges - Financing Past Purchases
-Other Non-Bypassable Charges (applies to Greenfield portion only)
- Public Purpose Program Charges62
Nuclear Decommissioning Charges
Fixed Transition Amount Charges
þ> Distribution Svstem Capital Cost63
Costs Associated with Acquiring the Distribution System Assets
59 See Appendix C, Section II.D at 83-84.
60 See Appendix C, Section II.B.3 at 77-78.
61 See Appendix C, Section ILC at 78-87.
62 Public Purpose Program Charges are included herein to support an evaluation of savings based on a
comparison of baseline SDG&E customer bill charges and the charges customers would pay under this City
MEV business model. However, revenue collected by the City associated with this charge would be
available to the City to allocate to various activities that are identified in Appendix C, Section II.C.2 at 81-
82.
63 See Appendix C, Section II.E at 84-87.
109
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
-
Þ> Distribution Svstem Operations and Maintenance Costs64
Þ> In-Lieu Pavrnents to Replace Lost Revenues65 -
Lost or Reduced Franchise Fee Payments
Lost or Reduced Property Tax Payments -
The MDU option cost benefits were assessed based upon two energy supply
strategies. In the first supply strategy it is assumed the City's MDU will take an ownership -
position in a power generation facility (Generation Supply Strategy), In the second, it is
assumed the City's MDU will purchase all of its energy requirements in the wholesale energy
market by executing power contracts with suppliers (Contracts Supply Strategy). -
Power costs were allocated to resource supply options for the given supply
strategy as follows: -
2006 Energy Resource Costs ($) by Supply Strategy -
Generation Contracts
-
Market Purchases $4,317,306 9.8% $2,802,774 5.6%
Contracts $3,188,640 7.2% $47,094,240 94.4%
Power Production $36.644,395 83.0% -
$44,150,341 $49,897,014
.-
Generation Strategy - Major Capital Expenditures:
Implementing a CCA or MDU with the Generation Supply Strategy option -
requires constructing new generation or acquiring an interest in a generation project. To support
the Generation Supply Strategy would require initial capital expenditures estimated at $78 -
million. This figure is derived based on an assumed ownership of 130 MW at an installed capital
cost of $600,000 per MW. Annual debt service to support this investment would be
approximately $5.4 million at an assumed tax-exempt debt interest rate of 5.5%, This cost, as
well as generation facility operations and maintenance and fuel cost, is included in the Pro Forma
Table below at 112 under Commodity Costs and in Appendix C, Section ILl at 97, Section V.
Operating Expenses, (A)(iii) Power Production.
64 See Appendix C, Section 1I.F at 87-88.
65 See Appendix C, Section 1l.H at 88-89.
110
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
-
c. Pro Forma Results
- MDU option financial pro fonna were prepared for both the Generation and
Contracts Supply Strategies. See Appendix C at 97-98.
- (1) MDU - Generation Supply Strategy
- Total estimated costs of MDU operations are summarized in the table below for
the Generation Supply Strategy and compared to projected SDG&E electric commodity related
charges. The costs of MDU operations are broken out among the major cost of service elements.
- The most significant of these is the electric commodity costs, which is primarily the capital and
operating costs of the MDU's generator, plus purchases under renewable energy contracts and
spot market purchases. The next largest cost category is distribution operations, which includes
- operations and maintenance, customer service and infonnation (billing), and administrative and
general expenses. Other significant costs include the financing charges for the MDU's
distribution capital investments and non-bypassable charges/exit fees. Less significant costs
- include ancillary services and CAISO charges, portfolio operations, and scheduling coordination
charges, foregone /Tanchise fee payments, and in lieu payments for county property taxes.
Savings are the difference between the MDU costs and the charges that SDG&E
would collect through rates under SDG&E's current and projected retail electric rates. As shown
on the Chart below, significant savings are projected to occur in every year of the study period.
-
-
-
-
--
-
III
IV. EVALUATION OF CHULA VISTA'S MEUOPTIONS
MOU -
Pro Forma Summary and Projected Savings - MDU Generation Supply Strategy
(Millions of Dollars Per Year) -
Year Commodity Ancillary Transmissinn Non- Distribution Distribution Franchise Total SDG&E Savings
Costs ServiceslISO & bypassable Capital Ops. Feestraxes Costs Charges
Costs Schedulin. Charm -
2006 44.2 2.7 4.9 20.1 18.9 24.6 2.8 118.1 130.4 12.3
2007 44.3 2.9 5.1 19.7 19.7 26.0 2.8 120.5 132.5 12.0 -
2008 46.6 3.2 5.3 14.0 20.3 27.4 2.9 119.6 130.1 10.5
-
2009 48.7 3.5 5.6 15.2 21.0 28.8 2.9 125.5 136.2 10.7
2010 51.6 3.9 6.0 16.8 21.6 30.1 2.9 132.9 145.1 12.2
-
2011 53.5 4.2 6.2 17.6 21.8 31.1 2.9 137.3 142.0 4.7
2012 55.5 4.5 6.4 18.8 22.0 32.1 3.0 142.4 147.4 5.1
-
2013 56.5 4.7 6.6 19.3 22.3 33.2 3.0 145.6 153.3 7.8
2014 58.7 5.1 6.9 19.7 22.5 34.3 3.0 150.3 161.2 10.8
-
2015 63.0 5.8 7.6 21.0 22.7 35.5 3.0 158.7 175.4 16.6
2016 63.4 6.1 7.8 21.4 22.9 36.6 3.1 161.4 182.0 20.6
-
2017 64.4 6.4 8.1 21.8 23.1 37.8 3.1 164.7 188.8 24.1
2018 67.4 6.8 8.3 22.3 23.3 39.0 3.1 170.4 195.9 25.5 -
2019 69.8 7.2 8.6 22.8 23.5 40.3 3.2 175.3 203.8 28.5
2020 72.4 7.7 8.9 23.5 23.7 41.6 3.2 181.0 213.6 32.6 -
2021 75.6 8.1 9.1 23.9 23.8 42.7 3.2 186.5 220.6 34.1
2022 78.5 8.5 9.3 24.3 23.9 43.9 3.3 191.7 223.5 31.9 --
2023 78.9 8.8 9.5 18.9 25.5 47.4 3.3 192.1 220.8 28.7
112
--
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MOU
-
-
The following Chart 7 compares the total MDU cost of service to the
- generation-related charges projected for SOG&E.
Chart 7: Comparison Of MDU Costs Based On Supply Generation Strategy
-
SD""E AND CHDLA VISTA
REVENDE REQDlREMENT COMPARISON
-
"'" I I
. SIXJ&E REVENUE "",UIR»ŒNT
. CHULA I'IST' """IJE "",UIR»ŒNT
- "'"
- ~ "'O
g
5
- ~ $100
- "'.
so
- 2OOS 2007 2008 "'" :1)10 :1)11 :1)11 :1)13 :1)1' :1)1' :1)16 :1)11 :1)18 :1)1' :1):1) "'1 "" 2ll23
The components of the MDU costs on a dollar per MWh basis are shown in Chart
- 8 below for the Generation Supply Strategy and compared to SDG&E electric commodity
charges.
-
113
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MOU -
Chart 8: MDU Cost Components On A Per MWh Basis
-
MEU Syst.m Av.,... C.sts
C~pooe",e of Reveoue Requ;,~",
'"
-
os.
'"
-
""
~ '00 -
!
~ "
~
"
-
"
20
-
""" '00' "",S "",S "" "" "" "" "" "" "" "" "" ,"s "". "'" "" "'"
-
(2) MDU - Contracts Supply Strategy
Total estimated costs of MOU operations are summarized in the table below for -
the Contracts Supply Strategy and compared to projected SOG&E electric commodity related
charges. The costs of MOU operations are broken out among the major cost of service elements.
The most significant of these is the electric commodity costs. The commodity costs primarily -
reflect the long-term power purchase contracts that form the core of the supply portfolio, as well
as the renewable energy contracts and spot market purchases.
The next largest cost category is distribution operations, which includes -
operations and maintenance, customer service and infonnation (billing), and administrative and
general expenses. Other significant costs include the financing charges for the MOU's
distribution capital investments and nonbypassable charges/exit fees. Less significant costs -
include ancillary services and CAISO charges, portfolio operations and scheduling coordination
charges, foregone franchise fee payments and in lieu payments for county property taxes.
Savings are the difference between the MOU costs and the charges that SOG&E
would collect through rates under SOG&E's current and projected electric rates. As shown on
the Chart below, savings are not projected to occur until at least 2015. Based on the pro forma
results, the MEU Study Team has concluded that an MOU that relies exclusively on market
114
-
-
-
IV. EV ALVATION OF CHULA VISTA'S MEV OPTIONS
- MOV
purchases of wholesale electricity to serve the load requirements of its customers would not be a
- cost-effective option for the City in the near term.
Pro Forma Summary and Projected Savings - MDU Contracts Supply Strategy
- (Millions of Dollars Per Year)
Year Commodity Anciilary Transmission Non- Distribution Distribution Franchise Total SDG&E Savings
Costs ServicesiiSO & bypassable Capital O&M Feesffaxes Costs Charges
-- Costs Schedulino Charges
2006 49.6 6.3 9.3 20.5 18.9 24.6 2.8 131.9 130.4 (1.5)
- 2007 50.8 6.5 9.5 20.1 19.7 26.0 2.8 135.4 132.5 (2.9)
2008 52.2 6.8 9.8 14.4 20.3 27.4 2.9 133.8 130.1 (3.7)
-
2009 54.1 7.2 10.1 15.5 21.0 28.8 2.9 139.7 136.2 (3.4)
2010 57.1 7.8 10.7 17.2 21.6 30.1 2.9 147.3 145.1 (2.2)
-
2011 60.2 8.1 10.9 18.0 21.8 31.1 2.9 153.1 142.0 (11.1 )
2012 61.7 8.5 11.2 19.2 22.0 32.1 3.0 157.8 147.4 (10.4)
-
2013 62.9 8.9 11.5 19.7 22.3 33.2 3.0 161.4 153.3 (8.1)
-- 2014 65.0 9.3 11.9 20.2 22.5 34.3 3.0 166.2 161.2 (5.1)
2015 69.4 10.2 12.7 21.5 22.7 35.5 3.0 175.0 175.4 0.3
- 2016 72.5 11.2 13.7 22.3 22.9 36.6 3.1 182.3 182.0 (0.4)
2017 73.9 11.6 14.0 22.7 23.1 37.8 3.1 186.3 188.8 2.5
2018 75.4 12.1 14.3 23.1 23.3 39.0 3.1 190.4 195.9 5.5
2019 76.6 12.5 14.5 23.5 23.5 40.3 3.2 194.1 203.8 9.7
2020 78.3 13.0 14.8 24.1 23.7 41.6 3.2 198.8 213.6 14.8
2021 85.3 13.6 15.0 24.7 23.8 42.7 3.2 208.4 220.6 12.3
2022 86.2 14.1 15.3 25.1 23.9 43.9 3.3 211.7 223.5 11.8
2023 87.1 14.5 15.5 19.6 25.5 47.4 3.3 212.8 220.8 8.0
115
-
IV. EVALUATION OF CHULA VISTA'S MEV OPTIONS
MOV -
The following chart demonstrates that adoption of a Generation Supply Strategy would
result in substantially greater benefits that the Contracts Supply Strategy if the City implements -
an MOV option:
Chula Vista Municipal Electric Utility Annual Cost
Savings $(000) -
37,500
~~ -
32,500
30,000
27,500 -
25,000
22,500
20,000 -
17,500
15,000
12,500 -
10,000
7,500
5,000 -
2,500
0
(2,500) ~ ~ ~ ~ þ,¡ þ,¡ ~
~~~",ìGìG", -
(5,000) .... '" <0 a ~ '" '"
(7,500)
(10,000)
(12,500) -
(15,000)
I-*- MDU - Generation -9- MDU - Contracts I
116
-
IV. EV ALOATION OF CHULA VISTA'S MEU OPTIONS
- MOO
The following Chart 9 compares the total MOO cost of service to the generation-
- related charges projected for SOG&E.
Chart 9: Comparison Of MDU Costs Based On Contracts Supply Strategy
SDG&E AND CHULA VISTA
REVENUE REQrnREMENT COMPARISON
,~O
- ,~
M'
LL mo
- ::'
.
.
"
~ "00
""
w
- - - - -., - - - - - - - - - - --
The components of the MOU costs on a dollar per MWh basis are shown in the
Chart 10 below for the Contracts Supply Strategy and compared to SDG&E electric commodity
related charges.
117
-
IV. EVALUATION OFCHULA VISTA'S MEU OPTIONS
MOU -
Chart 10: MDV Cost Components On A Per MWh Basis
-
MEU Syotem Ave".. Coots
ComponenlS of Aevenue Aequ;'emenl
"" -
""
'" -
'20
~ 100 -
~
! eo
&
eo -
"
" -
2008 '00' 2008 2008 2000 '001 '00' 20" "" "" 2O1S 20" ""' 2018 2020 "'20 20" ""
-
Pro forma detail for the MDU option, with hatb Generation and Contracts Supply
Strategies, is located in tbe Appendix C, Section II.! at 97-98.
-
d. Intangibles
(1) Benefits -
If Chula Vista decides to pursue this option, its residents could realize a number
of benefits, including the likelihood of lower-priced power, more stable electricity rates, local -
control over the rates, rate design and the use of funds dedicated to public benefit and progress,
improved reliability, and opportunities for economic development.
-
In recent years, most of California's electric consumers have seen their electric
rates skyrocket - with a notable exception: the customers of most of California's municipal
utilities. While some municipal utility customers also saw rate increases, the increases were not
on the order of magnitude that the customers of tbe California IOUs have experienced. The
major reason municipal utility rates did not increase as dramatically as IOU rates is that
municipal utilities were not fully and forcefully committed to the failed California deregulation
experiment, and therefore not substantially reliant on the energy spot markets in 2000 and 2001.
Most municipal utilities had either developed their own generation resources, or entered into
long-term power contracts that "locked-in" and stabilized future energy costs, and were therefore
not dependent upon spot-market purchases.
1I8
--
.-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MDU
- Municipal utilities have an inherent price advantage over IOUs because the
municipal utility is not motivated to produce profits for shareholders, Municipal utilities are
permitted to set rates which cover both capital and operating expenses and also fund utility
- reserve accounts, fund in-lieu-of-tax payments to local governments, and fund other worthy
public works projects. In addition, the municipal utility has access to tax-exempt financing for
many capital expenditures. These key components provide the City with a significant
- advantages regarding retail electricity rates as compared to remaining a full requirements
customer of SDG&E.
- Another major advantage with this option would be local authority and control. For
instance, the future potential City of Chula Vista Electric Utility Department could make
resource decisions, develop maintenance practices, develop capital improvement programs, and
- make other decisions relating to the operation of the utility for the sole benefit of City residents
and businesses. For instance, the City could elect to purchase electricity /Tom more
environmentally benign resources in comparison to SDG&E's resource mix. The City Council
would be the only entity to set electric rates. Such rates would be designed to meet any unique
circumstances existing within the City's service territory. Currently, these decisions are being
made by SDG&E (for the benefit of its shareholders) under the regulation of the CPUC and the
FERC. Municipal utilities are not, for the most part, subject to CPUC or FERC regulation.66
Rather, they are, for the most part, subject to self-regulation and control by the City Councilor a
municipal utility board or commission, An important facet of local control which should not be
overlooked is the ability of the Chula Vista City Council to fashion programs to utilize public
goods charges (discussed in below and in Section III.c.La of Appendix B at 16-17). Such
programs must meet the requirements of state law, but can be designed to meet the unique
requirements of Chula Vista customers and provide direct benefits to Chula Vista residents and
businesses.
Public Utilities Code 385 authorizes and requires local publicly owned electric
utilities to collect, through rates for local distribution service, revenue allocated to public benefits
programs. The public benefits charges are to be not less that the lowest expenditure level of the
three largest IOUs on a percent of revenue basis for year ending December 21, 1994. Public
benefits related charges are currently a minimum of 2,85 percent of the publicly owned electric
utility's revenue requirement.
Public benefit programs referred to include the following:
i. Cost-effective demand-side management services to promote energy efficiency
and energy conservation;
66 See discussion in Appendix B Section l.C at 15-27.
119
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
ii. New investment in renewable energy resources and technologies (subject to
applicable statutes); -
iii. Research, development and demonstration programs for public interest to advance
science and technology that is not adequately provided by competitive and
regulated markets; and -
iv, Service for low-income electricity customers, including, but not limited to, energy
efficiency services, education, weatherization, and rate discounts.
-
Revenue associated with this charge would be available to the City to allocate to
various activities identified above.
-
Finally, the City could provide economic incentives for specific economic
development areas within the City, and design rates to match those incentives.
-
As shown on the following chart, if Chula Vista forms an MDU and commences
the operation of a full electric distribution utility, it would be the II th largest utility in California,
based on customer count and 20th based on energy sales. -
-
-
-
-
-
-
-
120
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
California Electric Utilities (SoulCe: California Energy Commission 2001 Statistics)
-
CullOmer
AIoeoun" MWh % Enlrgy Ronklng A City Municipal
Distribution Utility
- Pacific Gas and ElecIJic Company 4,756,159 79.441.589 34.06% I Would Be The llili
Southern Califomia Edison Company 4,446,024 78,453.624 33.68% 2 Lar~st Utility OIÍ
Los Angeles Department of Water and Powe 1.405.524 22,375.712 9.60% 3 OfThe State's 48 by
San Diego Gas and Electric Company 1.242.735 15,212,291 6.53% 4 Customer Count -
- Sacramento Muniapal Utility District 475.410 9.333,938 4.00% 5 20ili By Energy Sales
City of Anaheim 109,548 2.511.542 1.06% 6
Impe<lallrrigation District 102,901 2.711.321 1.16% 7
Modesto Irrigation District 99,550 2,244.939 0.96% 1:0/
- City of Riverside 96.102 1,720.653 0.74%
City of Glendale 83.489 1,114,569 0.48%
City of Chula Vista 78,317 862.186 II
-
Tunoel< Irrigation District 76,565 1,445.313 0.62% 12
City of Pasadena 59.354 1,104,676 0.47% 13
City of Burbank 51.406 1,050,244 0.45% 14
Silicon Valley Power 48,063 2.517,729 1.06% 15
Pacificorp 44,565 816.107 0.35% 16
Sierra Pacific Power Company 43,873 505.223 0.22% 17
City of Redding 39,653 671.507 0.29% 18
City of Rose~lIe 39.070 947,855 0.41% 19
City of Alameda 33.140 384,491 0.16% 20
City of PeioAito 28,200 1.100,596 0.47% 21
City of Lodi 24,618 413.600 0.18% 22
- Southem Califomia Water Company 21.603 126.596 0.05% 23
City of Crnton 17.679 299.034 0.13% 24
City of Lompoc 14.913 129,614 0.06% 25
City of Azusa 14,773 226,897 0.10% 26
Lassen Municipal Utility District 12,068 120.182 0.05% 27
Truckee-Donner Public Utility District 11,257 122.451 0.05% 28
City of Banning 10,141 129.300 0.06% 29
City of U~ah 7.360 94,106 0.04% 30
rnnity Public Utility District 6.558 75,471 0.03% 31
Plumas-Sierra Rural Eledric Cooperation 8.250 121,820 0.05% 32
City of Healdsburg 5,342 68,936 0.03% 33
City of Ne«Iles 4,100 79.344 0.03% 34
Shasta Dam Area Public Utiiity District 4,062 67,239 0.03% 35
Su~.. Valley Eledrical CorponItion 4.044 101.517 0.04% 36
Anza ElecIJic CooperatiVe. Inc. 3.567 36,109 0.02% 37
City of Gridley 2.280 28,160 0.01% 38
City of Vernon 2,067 1.128.048 0.48% 39
Merced Irrigation District 881 271.153 0.12% 40
City of Biggs 662 10.706 0.00% 41
Cal......s Pu~ic Power Agency 240 26,494 0.01% 42
Central Valley Project 86 2.743,160 1.18% 43
Tuolumne County PubliC Power Agency 85 25,133 0.01% 44
Valley Electric Association, Inc. 26 6,905 0.00% 45
City of San Franasco 14 897,947 0.39% 46
Boulder CitylPar1<er Davis nla 88,130 0.04% 47
City of Escondido nla 400 0.00% 48
Total 13.458.047 233,080.393
121
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
(2) Risks
-
One obvious and large risk inherent in this option is the amount of resistance that
SDG&E would exert against the City moving forward with a public power entity. Ideally, if the
City decided that it waÌlted to proceed with the implementation of a City MDU, the City would -
be able to reach a negotiated settlement with SDG&E for the acquisition of its distribution assets.
However, it is more likely that SDG&E would resist the acquisition of its distribution facilities,
requiring the City to resort to the use of the power of eminent domain. -
In considering the MDU option, the City should not underestimate the potential
strong opposition SDG&E will wage against the taking of its distribution assets or infringement -
on its customer base. The City should anticipate that SDG&E will use every legal and political
tool available to fTustrate, defeat or delay the implementation of the City's MDU option. The
Eminent Domain Law 67 gives the property owner several opportunities to defeat the acquisition, -
beginning with the contest of the Resolution of Necessity. SDG&E can also delay the
implementation process by contesting the terms and conditions of the interconnection before the
FERC.68 At the bottom line, SDG&E's political and legal resistance to selling its distribution
assets will substantially increase the start-up costs associated with the creation of a new utility.
It is worth noting that SDG&E recently funded a citizen's initiative in San Marcos --
in opposition to the City Council's efforts to implement a Greenfield project to serve newly
developed areas within the City.69
-
Another impediment may involve issues surrounding separation or "islanding"
/Tom other parts of the SDG&E system. There would likely be certain physical distribution asset
separation problems as portions of SDG&E's distribution lines cross other jurisdictional
boundaries. This may require the construction of additional distribution substations, installation
of net metering technologies, or other local distribution design reconfigurations resulting in the
award of severance costs to SDG&E as part of the condemnation process,70 resulting in increased
costs of financing the distribution assets.
67 See discussion in Appendix B, Section II.A at 28-30. -
68 See discussion in Appendix B, Section 1I.c.3 at 33-35.
-
69 The San Diego Union Tribune, August I, 2003. According to San Marcos Councilman Lee Thibadeau:
"SDG&E is doing everything it can to interfere with the city's right to establish our own utility and save
our residents millions of dollars."
70 See Appendix B, Section 1l.C.2 at 32-33.
122
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MDU
To provide a cost benefit over the current SDG&E service, the City would need to
- be able to acquire the distribution system, provide or obtain energy and related services, perform
operation and maintenance services, billing, settlements, and collections, and perform long-term
planning, all at a cost of less than the current provider. Based upon the financial pro forma
- performed by the MEU Study Team, the City can meet this challenge through the formation and
operation of a full service MDU.
- 4. LegallRegulatory
Cal. Const. Art. XI, §9 provides specific authority for municipal corporations to
- provide utility services both within and without of their boundaries ". . . except within another
municipal corporation which furnishes the same service and does not consent." Cal. Pub. Uti!.
Code § 10002 provides that a municipal corporation may acquire, construct, own, operate, or
- lease any public utility. A Public Utility, in this context, is defined as the supply of a municipal
corporation alone or together with its inhabitants, or any portion thereof, with water, light, heat,
- power, sewage collection, treatment, or disposal for sanitary or drainage purposes, transportation
of persons or property, means of communication, or means of promoting the public convenience.
See Cal. Pub. Uti!. Code § 10001.
Publicly owned municipal utilities (the various forms of which are set forth and
described at Ca!. Pub. Uti!. Code § 9604(d)) are not regulated by the Public Utilities Commission
or any other supervising agency, in the absence of a legislative grant of authority (Cal. Const., art
XII, § 3; see also, County of In yo v. Public Utilities Commission (1980) 26 Cal. 3d 154).
No formation or implementation process is specified by state law for the creation
of such a utility.
As discussed in Section I above, the City of Chula Vista has already taken the
initial steps in the formation of an MEU with the adoption, on June 5, 2001, of Ordinance No,
2835 establishing the City as a municipal utility.
a. Exercise of the Power of Eminent Domain
- Until Chula Vista elects to acquire or operate an electric distribution system or
other utility facilities to serve the full or partial electric and gas requirements of customers within
the City, it is premature to discuss, in any detail, the procedures and requirements applicable to
the exercise of the powers of eminent domain in the State of California. Such detailed discussion
is better left for development and analysis in the implementation phase if Chula Vista elects to
pursue this option. At the same time, it is important for Chula Vista to understand that it can
exercise the option of acquiring utility facilities, including SDG&E's electric distribution system,
and to have some understanding of both the procedures involved in exercising this option and the
public interest standard that must be met if the condemnation is challenged by SDG&E.
123
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
In this regard, in California, a public entity, such as Chula Vista, does have the -
right to acquire property for public use, including public utility facilities and /Tanchises, using the
process of eminent domain.71 The procedure which a municipality or other entity (e.g.
Municipal Utility District) must follow in acquiring public utility facilities or franchises may be -
summarized briefly as follows:
Offer: The public entity or municipality must make an offer to the property -
owners. This offer must reflect what the public entity or municipality believes is
just compensation for the property,
Notice and Hearing: Prior to issuing a resolution of necessity, the public entity -
or municipality must provide, to the property owners, notice and opportunity to be
heard with regard to public interest, public good, and the necessity of the
property's acquisition. -
Recommendation: After holding the necessary hearing, the governing body of
the public entity (normally the legislative body of the public entity) must issue a
written summary of the hearing and a written recommendation as to whether to
adopt the resolution of necessity.
Resolution of Necessity: The governing body may then issue a resolution of
necessity
Final Offer: At least 30 days prior to trial, the public entity must file its final
offer and the owner must file its final demand.
Commencement of Eminent Domain Proceeding: After issuance of a resolution
of necessity, the public entity must file a complaint with the superior court.
A detailed analysis of the California Eminent Domain Law 72 and legislation
related to the acquisition of facilities and property for the purpose of providing utility services is
set forth in Appendix B, Section ILA at 28-32. This analysis includes a discussion of the various
methods of valuation which may be used in establishing the 'Just compensation" which must be
paid to SDG&E for the taking of its electric distribution assets.
b. Cost Exposure
In the event that Chula Vista elects to form and operate an MDU through the
acquisition or condemnation of SDG&E's electric distribution system, it will be exposed to
several classes or types of costs, which must be taken into consideration in determining whether
or when to proceed with this undertaking. The legal basis for each class of potential costs are set
forth and discussed in Appendix B, Section II.C at 32-41. Those costs, which are presently
71 See Cal. Civ. Proc. Code §§ 1240.010 and 1240.110.
72 See Cal. Civ. Proc. Code §§ 1240.010, et. seq.
124
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MDU
known or can be estimated, are quantified in Appendix C, Section ILC.1 at 78-81 and Section
- E.2 at 84-89. The principal cost factors involved in this feasibility analysis are:
(1) Acquisition Costs
-
The acquisition costs are those associated with the acquisition, by negotiation or
by condemnation, of SDG&E's electric distribution system assets within the City. These costs
- are discussed in Appendix B, Section ILC.I at 32 and are quantified in Section IV.F.5, below,
and in the Appendix C, Section ILE.2 at 84-89, The MEU Study Team has estimated the
acquisition costs of the distribution facilities at $170 million.
-
(2) Severance Costs
- In addition to acquisition costs, the City will also be responsible for the payment
of severance costs, which are incidental to the taking but are not attributable to the value of the
property acquired. At this juncture, it is premature to make a detailed estimate of severance
- damages inasmuch as the final configuration of the MDU system and the reconfiguration of the
SDG&E distribution system has not been determined. The MEU Study Team has made a
preliminary estimate of severance and interconnection costs of $10 million. See Section IV.F.5
below at 126 and Appendix C, Section ILE.2 at 85. These costs are discussed in more detail in
Appendix B, Section ILC,2 at 32-33.
(3) Interconnection Costs
- In the absence of an agreement between SDG&E and the City respecting the
interconnection of the City's municipal distribution system with SDG&E, and the
reconfiguration of SDG&E's system to accommodate the interconnection, the Federal Energy
Regulatory Commission will establish the terms and conditions of the interconnection, including
the costs thereof. The City will be responsible for the payment of all costs related to the
establishment of the interconnection. At this juncture, it is not possible to provide a detailed
analysis of these costs. For purposes of this analysis, interconnection costs are combined with
severance costs and estimated at $10 million (see Section IV.F.5 below and Appendix C, Section
II,E.2 at 85), The methodology for establishing these costs is set forth in Appendix B, Section
II.C.3 at 33-35.
(4) California Cost Responsibility Surcharge for Departing
Load
On July 10, 2003, the CPUC issued Decision 03-07-028, "Order Adopting Cost
Responsibility Surcharge Mechanisms for Municipal Departing Load," (Decision 03-07-028;
125
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
-
Limited Rehearing Granted in Decision 03-08-076 (collectively, the MDL Decisions)73. IfChula
Vista fonns an operating MEU and begins to generate power or purchase power /Tom an entity -
other than SDG&E, according the MDL Decisions, it will be responsible for the payment of a
surcharge for municipal departing load. While several interested parties have filed petitions for
writ of review before the California Supreme Court (including one in which Chula Vista joined), -
as the law stands at this time, a surcharge will be applied to all municipal departing load,
including new load served by Chula Vista. Inasmuch as the CPUC is still considering the level
of these charges, the MEU Study Team has provided an estimate of these charges by proxy using -
the amount of the surcharge applicable to Direct Access customers, adopted by the CPUC in
proceeding (R.02-01-011). Those costs are quantified in Appendix C, Section ILC at 78-81 and
are discussed in more detail in Appendix B, Section II.C.4 at 35-39.
Under the MDL Decisions, the cost responsibility surcharge, or exit fee, will
apply in all cases of CCA, Greenfield and MDU development. Those costs are discussed in -
more detail in Appendix B, Section II.C.4 at 35-39 and are quantified in Appendix C, Section
ILC at 78-81.
-
5. Financing Options
Tota! costs for acquiring the distribution system are estimated at $185 million.
These costs include the following:
Investment Cost -
Distribution Facilities $170 Million
Interconnection/Severance $10 Million
Regulatory/Litigation $3 Million
Inventory $2 Million
Tota! $185 Million
The cost for the acquisition of distribution facilities assumes that the City does not
elect to pursue the Greenfield development option. If that option is pursued, the distribution
infTastructure costs of $12.1 million would be subtracted /Tom the distribution system acquisition
costs under the MDU option, to yield an acquisition cost of approximately $158.5 million.
Annual debt service to support this investment would be approximately $20.2
million at an assumed taxable debt interest rate of 6.5%.
7] For more detailed information regarding the CPUC's "Exit Fee" proceeding and the municipal departing
load cost responsibility surcharge, see Appendix 8, Section I.C.I.b at 18-20.
126
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MDU
Acquiring an interest in a generation project to support the Generation Strategy
- would require initial capital expenditures estimated at $78 million. This figure is derived based
on an assumed ownership of 130 MW at an installed capital cost of $600,000 per MW. Annual
debt service to support this investment would be approximately $5.4 million at an assumed tax-
- exempt debt interest rate of 5.5%.
The City would have a variety of financing mechanisms available to finance its
- MEU projects depending upon the specific asset and/or activity.74 Financing techniques might
include the following:
- ~ General Obligation Bonds
~ Limited Obligation Bonds
~ Special Assessment
- ~ Certificates of Participation
~ Revenue Bonds
~ Commercial Paper
-
6, Implementation Schedule
- a. Major and Critical Steps
In the event that Chula Vista elects to form an MDU, the MEU Study Team has
- identified the following major and critical steps, beginning with a focused MDU Feasibility and
Implementation Plan, which will be necessary for the City to complete before commencing the
- operation of the City's electric distribution system:
(1) Focused MDU Feasibility and Implementation Plan
(1.1) Distribution System Survey and Valuation: (I mo.)
1.1.1 Detail the distribution system configuration, inventory equipment and
facilities; document the percent condition
1.1.2 Perform a system valuation to determine just compensation for the
negotiated purchase or condemnation of the existing distribution
system
(1.2) Severance Plan and Cost Study: (3- mo.)
1.2.1 Perform an engineering evaluation of the distribution system within
and adjacent to the City's boundaries
74 See Appendix C, Section IV at 126-27, for a detailed discussion of the differences, similarities, and
applicability.
127
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
1.2.2 Document the location and configuration of substations and
interconnections required to isolate and interconnect the City electric -
system and ensure SDG&E can provide service to its remaining
customers
1.2.3 Prepare plans, specifications, drawings, material lists, cost and -
construction time estimates
1.2.4 Identify other private properties that must be purchased or condemned
and estimate just compensation and time estimates -
(1.3) Energy Resource Plan: (3 mo.)
1.3.1 Finalize generation and contract supply strategy, engage developers in -
negotiations
1.3 .1.1 Negotiate placement of generation facilities within City
Boundaries -
1.3.1.2 Negotiate a percentage of plant ownership and/or
entitlement to generation plant output
1.3.1.3 Identify a short list of wholesale energy providers; refine -
supply pricing, terms and conditions of supply
(1.4) Human Resources Plan: (3 mo.) -
1.4.1 Identify any areas of overlap with existing City organizational
structures and ways to leverage existing staff capabilities -
1.4.2 Re-evaluate human resource requirements (see Section IV,F at 106-
07) to eliminate overlaps in staffing
1.4.3 Develop detailed job descriptions for each remaining human resource -
requirement
1.4.4 Perform an analysis of the regional labor base to determine availability
of qualified candidates for key discipline areas Survey the relevant job -
market to fulfill plans to staff these positions and provide time
estimates
.-
(1.5) Facilities Plan: (3 mo.)
1.5.1 Identify facility requirements
1.5.1.1 Customer and Energy Services: (call center, staff offices,
billing system, vehicles and equipment)
1.5.1.2 Distribution Engineering and Operations (offices,
communication and control equipment, garage facilities, -
service vehicles, yard, security)
1.5.1.3 Power Operations: (staff offices, systems and equipment)
1.5.1.4 Detail availability, location and cost to build, buy, lease or
otherwise acquire the needed facilities
128
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
(1.6) Pro Forma Update: (I mo.)
1.6.1 Update cost estimates with results of the distribution system survey,
severance, energy resource, human resources and facilities plans
described in 1.1 to 1.5
1.6.1 Prepare request to SDG&E to obtain detailed customer load data
1.6.2 Update and refine load forecast based on planned development
1.6.3 Incorporate the impacts of any new regulations, cost assumptions or
City objectives
(1.7) Finance Plan: (1 mo.)
- 1.7.1 Work with financial planners and bond counsel to develop revenue
bonding and other alternatives for financing depending upon
categories and values of assets to be financed
-
(1.8) Governance Plan: (2 mo.)
1.8.1 Propose governance structures for the new municipal utility
-- 1.8,2 Obtain consensus among City leadership and establish plans for
reporting, oversight and financial management of the municipal utility
(1.9) Implementation Plan: (I mo.)
1.9.1 Incorporate all of the above into an implementation plan
1.9.1.1 Structures, costs, timelines, updated financial prospectus
1.9.1.2 Achieve City leadership's approval and move to
Implementation Phase
(2) Implementation Phase Tasks
(2.1) Establish public interest and necessity and demonstrate greatest public good,
least private injury (1 mo.)
(2.2) Ordinance No. 2835 has provided local authority establishing a public utility
- further action by City Council to authorize negotiations with SDG&E as
described in Section 2.3 below (1 mo.)
(2.3) Make an offer and attempt to negotiate the purchase of SDG&E's
distribution system (1 mo.)
(2.4) Provide an opportunity for SDG&E to appear and be heard and argue public
interest and necessity (30 days required - 1 mo.)
(2,5) Adopt Resolution of Necessity to condemn the property (1 mo.)
129
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
(Resolution of Necessity creates a rebuttable presumption that public interest
and necessity have been established75) -
(2.6) Final Offer: 30 days prior to condemnation trial the City must make another
attempt to negotiate the purchase of the property (I mo.) -
(2.7) Judicial Review:76
2.7.1 SDG&E is likely to seek judicial review of the validity of the City's -
Resolution of Necessity (see 2.5) before or during the power of eminent
domain proceeding77 (3 mo.)
-
(2.8) File Complaint in Superior Court invoking the power of eminent domain and
initiating condemnation proceedings (6 mo. to 2-years):
-
2.8.1 Obtain any final infonnation needed to confinn and support any critical
elements of the Implementation Plan
2,8,1.1 The City can secure either the written consent of the SDG&E -
or an order /Tom the Superior court to enter the property to
make photographs, studies, surveys, examinations, and
appraisals or engage in similar activities related to acquisition -
or use of the property78
2.8.1.2 If the City's Resolution of Necessity is accepted and the
City's right to affect a taking of SDG&E's property and -
setting of compensation is approved, the City may apply ex
parte to the court for an order for possession (deposit with the -
court the probable amount of compensation) and proceed to
initiate the Implementation Plan.
(2.9) Execute Implementation Plan (I-year): -
2.9.1 Negotiate the Date of Possession Based Upon the Scheduled Completion
of the Following: -
Governance Plan
Human Resources Plan
Facilities Plan
7S Cal. Civ. Proc. Code § 1245.250
76 Cal. Civ. Proc. Code § 1245.255
77 Cal. Civ. Proc. Code §§ 1250.350 and 1250.370
78 Cal. Civ. Proc. Code §§ 1245.010,1245.020, 1245.030
130
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
Severance Plan
Energy Resource Plan
2.9.2 Execute Energy Supply Agreements
2.9.2.1 - Finalize arrangements with developers for
- generation projects
2.9.2.2 Prepare RFP for Power Supply Contracts, Evaluate
Responses and Execute Contracts
2.9.2.3- Begin Scheduling power
b. Timelines
Given the many variables inherent in the eminent domain proceedings and in the
other regulatory proceedings related to the establishment of state imposed exit fees and
nonbypassable charges, it is impossible to provide a definitive implementation schedule. The
MEU Study Team estimates the following timelines for the completion of the planning elements
and implementation phases in establishing an MDU:
Planning Elements: The time to complete additional planning, consisting of the
individual elements itemized above, performed in sequence are estimated to take 20-months.
However, overlaps and concurrent work projects might reduce this estimate to one-year. The
lead time to implement generation projects, on which the MDU Generation Strategy option and
its benefits are based, is estimated between one and one-half to three years, although this might
be initiated prior to completing all of the planning elements.
Implementation Phase: It is estimated that the process leading up to a
condemnation trial will take approximately six months for Implementation Tasks 7.(a) 2.1
through 2.7. The court hearings are estimated to take between six months and two years. An
order for possession might be obtained prior to resolution and setting of just compensation. It is
estimated that the City can establish its right to take the SDG&E assets by obtaining the judicial
approval of the Resolution of Necessity within 10 months. It is further estimated that the
implementation Plan can be fully executed in /Tom one year to 18 months. Hence, the most
optimistic time projection to implement the MDU is three and one-half years.
The MEU Study Team believes the estimated two year time required to
implement a generation project will run concurrently with the additional planning activities and
the condemnation process. Accordingly, the 3.5 year time estimate would not change for
implementation of the MDU structure option with a Contract Supply Strategy. However, as
discussed above, the MEU Study Team does not recommend implementing the MDU option
with a Contracts Supply Strategy.
Based on the analysis contained herein, the City could elect to implement an
MDU employing a Generation Supply Strategy as soon as it could obtain entitlement to
131
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU -
generation output /Tom a local, modem power plant. A phased approach, as described above,
would allow the City to develop experience in the power procurement and delivery business,
If the City elects to implement the MDU option in the 20 I 0 time/Tame, after the
establishment of the Combined CCAlGreenfield option, as recommended by the MEU Study -
Team, the City would commence the MDU Planning and Implementation Elements discussed
above in mid-2008.79
In considering the time lines necessary to implement an MDU system, the City
should be cognizant of and prepared for strong legal and political opposition /Tom SDG&E.
Such opposition could substantially delay the completion of the acquisition process and increase -
the start-up costs for the MDU option,
7. Recommendation -
As discussed above, the MEU Study Team has analyzed and evaluated the
economic feasibility of an MDU option using both the Contract Supply Strategy and the
Generation Supply Strategy. Those strategies have been compared with the Combined
CCAlGreenfield development in the following chart:
79 It should be noted that, in the Gantt Chart located in Section V.C at 171 and in Appendix C, Section V.C at
132, the implementation schedule used for comparing the MEV options reviewed herein begins in 2004 for
all options.
132
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- MOU
- Chula Vista Municipal Electric Utility Annual Cost
Savings $(000)
- 37,500 -----
35.000
32.500
30,000
- 27,500
25.000
22,500
- 20,000
17.500
15,000
12.500
10,000
7.500
5.000
2.500
- 0
(2,500) 0 ~ ~ ~ ~ ~ ~
(5,000) g ëô ¡¡; ¡g " ~ t;¡
(7,500)
(10.000)
(12.500)
(15.000) --------~------------
1-<>- MDU - Gereration -a- MDU - Contracts *- CCAIGreenfiekJl
As depicted above, the MOU based on a Contract Supply Strategy is much less
advantageous to the City and does not begin to produce any tangible savings until 2017. The
MOU with a Generation Supply Strategy, by contrast, will produce savings in every year during
the study period. Although the Combined CCA/Greenfield option will produce more savings in
the early years, the MOU with a Generation Supply Strategy may be the best long-term option
open to the City when non-quantifiable benefits (i.e. local control resource, rates, and other
decisions) are considered.
Based upon the positive results of the pro forma financial studies and the other
major benefits, which will accrue from the implementation of the MOU (with the Generation
Supply Strategy) option, the MEU Study Team believes that it is feasible, from both an
economic and operational standpoint, for the City to form and operate an MDU by acquiring the
distribution assets of SOG&E. In coming to this conclusion, the MEU Study Team recognizes
that, because of the substantial capital investment required to acquire the distribution system,
generation facilities and to defray the start-up expenses for an MOU. the potential NPV of
benefits to the City is less favorable than the CCA/Greenfield option with a Generation Strategy.
At the same time. the MEU Study Team is of the opinion that. in the long run, the ownership of
133
-
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
MDU
-
the electric distribution system would allow the City to serve all electric customers within the
City at rates substantially below the current and projected rates of SDG&E and pennit the city to
build asset value in the distribution system. The MEU Study Team has also given substantial -
weight to the non-fInancial benefits to be realized by public ownership of the distribution system,
including local control of rates and service, discretion in the application of savings or benefits,
and independence /Tom SDG&E and the owner/operators of the transmission grid. -
Given the additional planning and study requirements needed to implement the
MDU option, together with the procedural steps which must be followed under the Eminent -
Domain Law, the MEU Study Team recommends that the City defer implementation of the
MDU option until the 2008-10 time frame and re-evaluate the option based on circumstances
existing at that time. Assuming that the City proceeds to develop the CCA and Greenfield -
options in the meantime, the City will have an MEU infrastructure, customer base, generation
facilities and several years of operating experience before needing to make the critical decision
of potentially acquiring the distribution system of SDG&E. In the event that CCA appears to be -
uneconomic once the CPUC has issued its final rulemaking decisions, the MEU Study Team
would recommend that the City accelerate its consideration of the MDU option.
-
-
-
-
-
-
-
134 -
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- JP AlMUD
G. Joint Powers AgencylMunicipal Utility District
-
In addition to the primary MEU options analyzed and evaluated in this feasibility
analysis, the MEU Study Team has identified two additional long range options which the City
- might take advantage of once it establishes and commences the operation of a full service
electric distribution system. These options, which are mutually exclusive, are (I) participation in
a Joint Powers Agency (JPA), and (2) the formation of a Municipal Utility District (MUD) in
coordination with another public entity. These options are discussed separately below.
1. Joint Powers Agency
-
a. Formation Requirements
- If authorized by their legislative or other governing bodies, two or more public
agencies by agreement may jointly exercise any power common to the contracting parties, even
though one or more of the contracting agencies may be located outside of California. See Cal.
Gov!. Code § 6502.
-- The agreement to form a JPA shall state the purpose of the agreement or the
power to be exercised. It shall provide for the method by which the purpose will be
accomplished or the manner in which the power will be exercised. See Cal. Gov!. Code § 6503.
Whenever a joint powers agreement provides for the creation of an agency or
entity which is separate /Tom the parties to the agreement and is responsible for the
administration of the agreement, such agency or entity shall, within 30 days after the effective
date of the agreement or amendment thereto, cause a notice of the agreement or amendment to be
prepared and filed with the office of the Secretary of State. Such notice shall contain:
(a) The name of each public agency which is a party to the agreement.
(b) The date upon which the agreement became effective,
(c) A statement of the purpose of the agreement or the power to be exercised.
(d) A description of the amendment or amendments made to the agreement, if any.
If the JP A fails to comply with the notice requirements discussed above, it may not issue bonds
or incur indebtedness until it complies. See Cal. Gov!. Code § 6503.5
Once formed, and having complied with all applicable notice requirements, the
JPA, as a separate public entity, commission or board, is authorized, in its own name, to do any
or all of the following: to make and enter contracts, or to employ agents and employees, or to
acquire, construct, manage, maintain or operate any building, works or improvements, or to
acquire, hold or dispose of property or to incur debts, liabilities or obligations, said agency shall
have the power to sue and be sued in its own name.
135
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
JPNMUD -
Any authorization pursuant to the agreement for the acquisition by the agency of -
property for the purposes of a project for the generation or transmission of electrical energy shall
not include the condemnation of property owned or otherwise subject to use or control by any
public utility within the state. See Cal. Gov!. Code § 6508. Thus, with this limitation, the JPA -
could not acquire, by condemnation, the distribution system or other utility facilities of SDG&E.
Chula Vista and its partners under the joint power agreement could exercise their own power of
eminent domain to acquire utility assets and then dedicate the use of those facilities to the Jl'> A. -
The JPA can own and operate both generation and transmission projects or facilities for the
benefit of its members or, in the alternative, enter into power supply and transmission service
agreements to complete the resource portfolio of its members. -
b. Benefits
-
The JP A option would allow the Chula Vista MDU to accrue and realize further
benefits by I) the addition of partners to share the costs and risks of the MDU option; 2) possible
aggregation of a larger load for resource procurement purposes, which, in turn, would lead to -
possible lower purchase power costs; and 3) possible reductions in cost for other activities
associated with running an electric utility such as operation and maintenance functions.
First, because a JP A is likely to spread the costs and risks associated with the
provision of electric utility services, the direct exposure of the City may be minimized. At the
same time, key capital, political, and intellectual resources could potentially be "tapped" /Tom -
the other JPA members. Second, in developing a financial case for a JPA venture, the larger the
electric load the more viable the prospect of cost-savings. This is due mainly to the fact that the -
JP A load can be substantially larger. Third, although a JP A cannot own distribution facilities, it
could construct generation facilities, purchase power through long-term contracts, sell any excess
electric power on the open market, acquire transmission facilities or enter into contracts for -
transmission service with transmission providers including SDG&E and the CAISO, lease office
space, issue bonds and incur indebtedness and provide customer services such as metering and
billing functions,
c. Risks
Since JPAs are not allowed, under applicable law, to acquire and own electric
distribution facilities, a JP A model is not useful to the City until it establishes a full service
electric distribution system. Thus, the JPA is not a substitute for an MDU, There are certain
inherent obstacles and down-side risks in the formation of a JP A structure. Specifically, the City
may be faced with the following practical problems in forming a JP A:
» The formation of the JP A may be much more time-consuming than the development of a
city department approach. It will be necessary to establish some form of work group or
136
------
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- JP AlMUD
advisory panel of the participating members, and ultimately members would need to
agree on strategy for developing a viable JP A structure with reasonable and achievable
goals.
- ~ The decision-making process of the JP A structure may prove much more cumbersome
than under the city department model. This is true during both formation and operation
of the JPA. Each member would be seeking to protect its own interests, and these
-. interests may not necessarily coincide with another member's interests or the group's
interests as a whole. This could result in the JP A not being able to provide the same
benefits or allow the new electric utility to be as "nimble" as the city utility department
option.
~ The potential of a protracted legal fight with SDG&E may also limit the enthusiasm of
- potential parties to the JPA if Chula Vista elects to acquire the distribution system of
SDG&E and, at the same time, participate in a JP A. The larger the potential service
territory (customers and load), the more likely it is that SDG&E will aggressively oppose
- the formation of a new utility or JP A.
2. Municipal Utility District
a. Formation Requirements
- A Municipal Utility District (MUD) may be formed by either Resolution or
petition8o to the Board of Supervisions of the County containing the largest number of voters
within the proposed MUD.8!
In the case of formation by Resolution, the legislative bodies of the entities
seeking to form the MUD must adopt resolutions which declare that MUD formation is
necessary and in the public interest. The resolution must state the type of utility to be acquired
and describe the exterior boundaries of the District or a list of public agencies included if the
District is made up of public agencies only. The Resolution must also include a request for an
election and be certified to the Board of Supervisors of the County containing the largest number
of voters within the proposed DistriCt.82
In the case of a request by Petition, a Petition must be presented by the forming
public entities to the Board of Supervisors of the County containing the largest number of voters
80 Cal. Pub. Util. Code § 11562.
81 [d, § 11583.
82 Cal. Pub. Util. Code § 11581-11583.
137
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
JP AlMUD -
within the proposed District. The petition must be signed by at least 10% of the voters within the
proposed District which voted in the last preceding general election, Signatures must be verified.
Once a Resolution or Petition is filed with the Board of Supervisors, an election
must be held within seventy-four (74) days after the date of the order calling for an election, An -
affinnative vote of two thirds of the registered voters within the proposed District will authorize
the establishment of the District. The Board of Supervisors shall file a certified copy of the order
declaring that result of the election to be filed with the Office of the Secretary of State, after -
which the establishment of the District will be complete.
The internal organization of a Municipal Utility District, including government, -
election of directors, additional directors, tenns of office of directors, powers and duties of
directors, meetings and legislation, other officers, and initiative and referendum is governed by
Cal. Pub. Util Code §§ 11801-11950. -
b. Benefits
-
Similar to the city utility department model, the MUD option could offer residents
within the City of Chula Vista many benefits, including the likelihood of lower-priced power,
more stable electricity rates, local control, and improved reliability. By selecting the MUD utility -
structure option and combining City electric loads and service area with those of other cities or
unincorporated territories, an additional benefit would be the ability to secure more
competitively priced power by combining the energy needs of more residents and business, -
thereby lowering the price of utility services, on a per unit basis, for all customers within the
MUD. Other economies of scale opportunities could also potentially be realized through the
purchase of distribution facilities or other assets such as utility vehicles and sharing
administrative costs. There are also possible reductions in disconnection costs /Tom the SDG&E
system.
c. Risks
One of the impediments of the MUD structure, as opposed to the city department -
structure, is that the City must come to an agreement with one or more other municipal agencies
in developing the tenns and conditions of establishing the MUD. Competing issues could arise
that must be resolved before the MUD could become operational. In some instances, the
resolution of such an issue might not be as beneficial to the City when compared to an
independent utility structure.
Fonning an MUD by combining the territories of other cities and/or
unincorporated territories with the City would require approval of the San Diego County Local
Agency Fonnation Commission (LAFCO). The LAFCO approval process generally adds
complexity and uncertainty when compared to the fonnation process for the municipal electric
138
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
- JP AlMUD
utility department described above, while still including all of the impediments described in the
City department option.
For these reasons, the MEU Study Team does not recommend using the MUD
- structure as a substitute for the formation of the City's own MDU. The formation of an MUD
involves a number of additional uncertainties and complexities in addition to those already
inherent in the formation of an MEU. Moreover, in broadening the MEU option to include other
- public entities or unincorporated areas, as required under the MUD structure, the City would lose
a considerable amount of local control and autonomy. Rather, the MEU Study Team
recommends that once the City exercises its option to establish its own MDU, it examine the
option of forming an MUD in collaboration with other public entities.
3. Implementation Schedule
-
Since the MEU Study Team has recommended that both the JPA and MUD
options be considered as long range options to be further evaluated after the City exercises its
-. options to establish its own MDU, no implementation schedule has been developed for either of
these options.
4. Recommendation
The MEU Study Team recommends that, if the City has exercised its option to
establish and commence the operation of a full service MDU, it should give serious
consideration to joining (or forming) a JPA with other publicly-owned utilities or forming an
MDU with another public entity, community or unincorporated area. In using these vehicles, the
City may be able to spread risk, enjoy the further benefits of the economies of scale, enlarge its
electric resource portfolio, and realize further savings and benefits.
139
~-
IV. EV ALVATION OF CHVLA VISTA'S MEV OPTIONS
- NA TVRAL GAS
H, Natural Gas
1, Feasibility of Acquiring Gas Distribution Facilities in Chula Vista
-~ This section presents an analysis of the feasibility of owning and operating the gas
distribution facilities located within the City of Chula Vista. These facilities are currently owned
by SDG&E, a wholesale customer of SoCal Gas whose rates and tariffs are subject to CPVC
- regulation. The analysis focuses on the economics of the gas distribution business since, as
shown in Figure I, SDG&E's gas procurement charge for core customers (Schedule GPC) is
competitive with the market price of gas at the California border at Topock. Moreover, SDG&E
does not own substantial amounts of interstate pipeline capacity or gas procurement contracts
that are likely to be "above market" under reasonable market conditions. Consequently, the
feasibility of entering the gas business will hinge almost entirely on whether Chula Vista can
provide a benefit from acquiring, owning, and operating the gas distribution facilities within the
city's boundaries. To provide a benefit, Chula Vista would need to provide gas transportation
and distribution (T&D) services to customers at a lower cost than the customers currently pay to
SDG&E. As this analysis demonstrates, it is not economically or financially feasible for the City
to undertake providing gas service to customers within the City.
Figure 1: SDG&E GPC vs, Topock Index Price
4.50 ,
4.00 -
3.50 -
3.00 '
5 2.50 - .GPC
~ 2.00 . Topock
1.50
1.00
0.50
0.00
<i>o" <9' <9' ¿,o" fl' <i>o" fl' <9' <9' ¿,o" ¿,o" <i>o" rfff
~ ~ ~ ~ ~ ~ ~ ~ R ~ ~ ú ~
':) (l'.;$-'Ii ~.;$-'Ii ,>V ':) .¡; ",0; 0'" ~o Qø .;.0;
The following sections discuss the methodology and assumptions used by the
MEV Study Team to forecast Chula Vista's T&D costs and compare them with SDG&E's costs.
140
--_._---~--
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
-
2. Gas Demand Forecast
Table I provides a breakdown of Chula Vista's annual gas requirements by
number and type of customers. The table was estimated by the MEU Study Team based on data
provided by Chula Vista and SDG&E statistics. In 2002, customers located in Chula Vista
consumed approximately 177 million thenns of gas and provided net revenues of $24.5 million -
to SDG&E, In 2002, Duke Energy's South Bay Power Plant, a transportation-only customer of
SDG&E, accounted for nearly two-thirds of total consumption but only 8.5 percent of total
revenue ($2.1 million). The power plant's small revenue share reflects the low ($0.019 per --
thenn) Sempra-wide gas transportation rate paid by all electric generation (EG) customers in
southern California in 2002. In contrast, Chula Vista's 62,500 residential users, who paid an
average bundled (commodity plus transportation) rate of nearly $0.70 per thenn, accounted for -
12 percent of total consumption and 58 percent of total revenue. Core commercial customers
(3.6 percent of consumption, 21 percent of revenues) and noncore industrial customers (20
percent of consumption, 10.3 percent of revenue) accounted for most of the remaining sales and
revenue. Residential and commercial core customers take bundled procurement plus
transportation service /Tom SDG&E. Both noncore customer classes take transportation-only
service.
To forecast future gas consumption, the MEV Study Team escalated the number -
of residential and commercial customers by an average of 1,7 percent per year, the same growth
rate used in the MEU Study Team's electricity analysis. As a result, by 2023, the number of
residential and core commercial accounts grows to 86,818 and 4,685, respectively. The number
of large energy-intensive noncore industrial users is held constant, on the assumption that the
number of new entrants equals the number of existing accounts that close down owing to
regional and global competition.
-
-
--
141
,-.-
IV. EVALUATION OF CHULA VISTA'S MEUOPTIONS
- NATURAL GAS
Table 1
Composition of 2002 Chula Vista Gas Demand
-
Avg
SDG&E
No. Therms per Tariff Rate Type of
- Customers 2002 Therms Customer Net Revenue $ $/fh 2002 Service
Residential 62,500 20.600.359 330 $14,200.760 $0.6893 0.70255 Bundled
Commercial, totai 3,390 11,365.569 3,353 $5.665.909 $0.4985
- Core Commercial 3.370 6,365.569 1.889 $5.115.909 $0.8037 0.72784 Bundled
Noncore Commercial 20 5.000.000 250.000 $550,000 $0.8037 0.09582 Bundled
Industrial & EG, Total 11 144,962,110 13,178.374 $4.621.786 $0.0319
Noncore Industriai 10 34,778.410 3.477.841 $2.528.663 $0.0727 0.07764 Transport-only
Electric Generation 1 110.183.700 110.183,700 $2.093.123 $0.0190 0.01900 Transport-only
Total 65.901 176.928.038 2.685 $24.488,455 $0.1384
---
Figure 2: Composition of Gas Demand
2002
12%
-.r;¡ . Residential
. Core Commercial
0 Noncore Commercial
~% 2~ 0 Noncore Industrial
. Electric Generation
Consistent with the assumption made in the electricity analysis, the MEU Study
Team assumed that residential gas use per customer would remain relatively flat over the next 20
years while core commercial use per customer would increase 0.5 percent per year. Multiplying
the change in gas use per customer by the change in customer numbers yields a forecast of gas
consumption through 2023. In the forecast, residential consumption expands 36 percent to 28
million therms per year by 2023, while core and noncore commercial usage expands 54 percent
to 17.5 million therms per year (versus 11.4 million thenns in 2002). Noncore industrial usage
remains a constant 34.8 million thenns per year.
142
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
-
To forecast gas supply for power plant usage, the MEU Study Team assumed that
the South Bay Power plant would continue to operate as a must-run unit through 2006. During
this period, the plant's annual generation is assumed to increase at the same 2.5 percent annual -
rate as SDG&E's overall electricity requirements. Assuming a constant heat rate of about 10,000
BtulkWh, gas consumption by South Bay is estimated to grow to 124 million thenns per year by
2006. In 2007, two new, highly efficient combined cycle power plants (Otay Mesa and -
Escondido) are assumed to start up. (Since South Bay's current configuration and attendant cost
of operation would not be competitive with the new Otay Mesa and Escondido plants, the MEU
Study Team did not include South Bay's gas requirements in this analysis.) As a result, electric
generation (EG) gas requirements fall to zero in 2007 and 2008. In 2009, the MEU Study Team
assumes a new electric generating plant is constructed within the boundaries of Chula Vista to
replace the existing South Bay power plant. Assuming that the plant has a heat rate of 7,000 -
BtulkWh and operates at a 70 percent capacity factor, annual gas consumption is projected to be
a constant 257,544 thenns per year /Tom 2009 through 2023.
-
Under the above assumptions, total gas consumption by consumers in Chula Vista
grows to nearly 338 million thenns per year in 2023, 91 percent greater than in 2002. As at
present, power generation continues to account for the lion's share offorecasted gas demand.
Table 2
Gas Demand Forecast
2002 2023 % %of
Sector Therms Therms Increase Total
A. Residential 20,600 28,075 36% 8.3%
B. Core Commercial 6,366 9,827 54% 2.9%
C. Noncore Commercial 5,000 7,719 54% 2.3%
D. Noncore Industrial 34,778 34,778 0% 10.3%
Subtotal RlCII 66,744 80,399 20% 23.8%
E. Electric Generation 110,184 257,544 134% 76.2%
Total Requirements 176,928 337,943 91% 100.0%
3. SDG&E Gas Transportation Revenue
The MEU Study Team next estimated the annual revenue SDG&E would receive
from delivering gas to customers in Chula Vista during the forecast period, As noted above, the
analysis focused only on gas distribution and transmission revenue based on our assumption that
a municipally owned gas utility in Chula Vista would provide gas procurement service at roughly
the same cost as SDG&E. This required a forecast of SDG&E's gas transportation and
distribution (T&D) rates through 2023, including SDG&E's cost of wholesale gas transportation
on the SoCai Gas system.
143
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
SDG&E's rates were forecast by escalating average 2002 rates (excluding
commodity) by the annual escalation factors assumed to result /Tom continuation of SDG&E's
CPUC-approved performance-based ratemaking (PBR) mechanism. Under the current PBR,
SDG&E is permitted to increase rates each year by the rate of inflation minus a factor for
productivity gains and a "stretch" factor intended to encourage efficient utility operation. If
actual costs increase by less than the allowed increase in rates, the savings are shared between
SDG&E and its customers according to a formula. In 2003, the existing PBR mechanism has
resulted in annual rate increases of2.6 percent.
In its current General Rate Case (GRC) (Application 02-12-028), SDG&E is
proposing to modify the PBR mechanism so that the annual increase is applied to base margin
(essentially, T&D revenue) rather than rates per se. SDG&E argues that, due to the increase in
efficiency observed since California's energy crisis and the results of CPUC-approved efficiency
programs, usage per customer is growing more slowly than in the past. Consequently, according
to SDG&E, the rate escalation method produces smaller revenue increases than were intended
when the PBR mechanism was designed. SDG&E proposes to address this issue by escalating
base margin by inflation minus a productivity factor and add the increase in miscellaneous
revenues due to inflation (currently outside the PBR mechanism). Rates would be calculated by
dividing the escalated revenues by forecasted sales.
Since it is uncertain whether SDG&E's proposal will be adopted, the MEU Study
Team escalated SDG&E's rates by an average of the escalation factors expected to result /Tom
extension of the current PBR mechanism and adoption of the proposed mechanism. This yields
an average escalation rate of 1.6 percent per year. The MEU Study Team's forecast of SDG&E
rates is presented in Table 3. Under this forecast, SDG&E's rates are projected to increase
between 1.5 and 3.5 percent per year through 2023 in nominal terms.
Table 3
Forecast SDG&E Gas Transportation & Distribution Rates
(S!Therm)
2002 2023 Annual
Sector Rate Rate % Inc.
A. Residential $0.394 $0.592 2.1%
B. Core Commercial $0.420 $0.560 1.5%
C. Noncore Commercial $0.078 $0.121 2.2%
D. Noncore Industrial $0.078 $0.121 2.2%
E. Electric Generation $0.019 $0.038 3.5%
144
---.------- ------------------------..-- ------- - -------
IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
As shown in the Table, core residential and commercial users currently pay an
average T &D rate of about $0.40 per therm ($4.00 per 00), five times the rate paid by noncore
commercial and industrial users. EG customers pay the lowest rate, $0.019 per therm ($0.19 per
Dth). The low EG rate is partly a result of the fact that most EG customers take service /Tom
high-pressure gas transmission lines and thereby "avoid" the more costly low-pressure pipelines
that distribute gas to smaller residential and commercial users. In addition, in Decision 00-04-
060 (issued April 2000), the CPUC adopted a Sempra-wide EG rate that equalizes the gas
transportation rates for EG customers on the SoCai Gas and SDG&E systems. As shown in
Table 4, the adoption of a Sempra-wide EG rate lowered the transportation rate for generators in
San Diego roughly $0.012 per therm (26 percent) below the rate that would have resulted /Tom
the previous, stand-alone rate method. As discussed below, by reducing South Bay's
transportation rate, the new rate mechanism makes it difficult, if not impossible, for Chula Vista
to serve the power plant at a profit. The MEU Study Team's analysis assumes that the Sempra-
wide EG rate will remain in place in the future, a reasonable assumption given the CPUC's goals
of promoting a "level playing field" for electric generators in the southern part of the state. The
MEU Study Team recommends that, if the Sempra-wide EG rate changes dramatically between
2006-2008, the City reconsider the feasibility of providing gas service.
Table 4
Sempra-Wide EG Rate (2000 BCAP)
Sempra-wide VB, Stand-alone EG Rate ($fThenn)
$fTherm
(1) Est Stand-alone rate $0.046
(2) Sempra-wide EG rate $0.034
Difference $0.012
Ratio (2)/(1) 0.744
% Difference 25.6%
Multiplying forecasted sales by forecasted rates yields an estimate of the revenues Chula Vista
customers would pay to SDG&E for delivering gas over the next 20 years. The revenue forecast
is presented in Table 5 below.
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
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-
Table 5
- Forecast SDG&E T&D Revenue from Cbula Vista
(000 $)
- 2002 2023 Annual
Sector (000$) (000$) % Inc.
A. Residential $8,112 $16,621 3.7%
- B. Core Commercial $2,671 $5,500 3.7%
C. Noncore Commercial $388 $935 4.5%
D. Noncore Industrial $2,700 $4,212 2.2%
- Subtotal Res/Commllnd $13,871 $27,267 3.4%
Average $rrherm $0.208 $0.339 2.5%
-
E. Electric Generation Revenue $2,093 $9,769 8.0%
Total Revenue $15,964 $37,036 4.3%
Total Average $rrherm $0.090 $0.110 1.0%
- By 2023, the MEU Study Team forecasts that Chula Vista customers will pay
SDG&E a total of $37 million per year for gas delivery services, an increase of 4.3 percent per
year over 2002 revenues of $16.0 million. For gas utility acquisition to be cost-effective, Chula
Vista must be able to deliver gas to customers for less revenue than SDG&E.
4. Estimate of Cbula Vista Operating Cost
To provide a preliminary estimate ofChuia Vista's cost of providing gas delivery
service, the MEV Study Team analyzed the revenues and costs of the two largest municipal gas
utilities in California: Long Beach Energy (Long Beach) and the City of Palo Alto Utilities
Department (Palo Alto). To further validate the results of this analysis, the MEU Study Team
benclunarked the non-gas revenues (i.e., revenue excluding commodity costs) of a representative
panel of municipally owned gas utilities in other parts of the United States. The result is a
reasonable, first-order, approximation of what it might cost Chula Vista to operate a gas
distribution utility in its service area.
Table 6 presents the gas delivery costs of Long Beach and Palo Alto based on
financial data reported by each city. Excluding transfers to the General Fund (GF), Long
Beach's cost of delivering gas to its 144,000 customers was $0.153 per thenn in the fiscal year
(FY) ending September 30, 2002 (FY 2001-02). The corresponding figure for Palo Alto was
$0.24 per thenn, based on data for the FY ending June 30, 2000, The average T &D cost for both
utilities was $0.196 per thenn.
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N. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS -
Table 6 -
Long Beach and Palo Alto Gas Delivery Costs
Lona Beach Palo Alto Avera : e
Year FY 2001-02 FY 1999-2000
No. Customers 144,000 23,400
Gas Thruput at City Gate 000 Therms 109,372 36,360
Total Operating Expense 000$ 54,474 22,787
Gas Commodity Cost 000$ 29,861 11,595
T&D Cost 000$ 24,613 11,192
General Fund Transfer 000$ 7,851 2,475
Capital Improvement Prog (CIP) 000$ 0 2,858
T&D Cost excl GF Trans 16,762 8,717
Delivery Cost per Therm 0.153 0.240 0.196
GF Transfer as % T&D Revenue 47% 28% 38%
GF Transfer as % Total Revenue 14% 11% 13%
Source: Long Beach Comprehensive Financial Plan, p. 38;
Palo Alto Adopted Budget 2001-2003 and PAU staff data.
To supplement the above analysis, the MEU Study Team compiled data on the
non-gas revenues of four other municipal gas utilities from 1995 through 2000.83 The utilities
are Richmond, VA, San Antonio, TX, Springfield, MO, and Citizens Gas and Coke of IN. The
analysis examined revenue from residential, commercial, and industrial customers, the same
classes of customers that would be served by Chula Vista. Revenue from EG customers was
excluded to provide an apples-to-apples comparison with Long Beach and Palo Alto, which do
not serve EG customers. Figure 3 compares the number of customers and annual non-EG
throughputs for four panel members plus Palo Alto and Long Beach. As shown on the left-hand
scale, the utilities serve from 23,000 (Palo Alto) to 300,000 customers (San Antonio).
Residential, commercial, and industrial throughput ranged from 36 million therms (Palo Alto) to
nearly 500 million therms (Citizens Gas & Coke). Given the breadth and geographical diversity
of the sample, we believe that it provides a reliable basis for estimating the costs of operating a
municipal gas utility in Chula Vista.
83 The data were obtained from SNL Securities, a software services company which maintains a computerized
database of EIA and other data that can be sorted by the user. EIA data can also be downloaded from the
agency's website.
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
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Figure 3: Sample Comparison
. ,oo@~~@@
~~~ ~~~0
E~~- . ~~~ê
0 200 000 ' , ..
~ 150'000 300,000,000 ~
~ 100:000 200,000,000 §
~ 50,000 100,000,000 '"
0 0
~o c¡- ..:¡,'<r- ",+ ~O ~
~o Q}/"I!' f!.Ò ~o iìi-Ò 0~"
q'l!' f'!.0" (¡!-o if' rif .§;'ÿ
--5' . §' f'!. '«' !i-~ CJ
q> '<J'I!' '<Jç
~tal Customers -+- Res/Comm/lnd Thenns I
Figure 4 provides the non-gas revenue per therm (total revenue minus gas
commodity costs) of the panel members from 1995 to 2000. General Fund (GF) transfers are not
- reported to EIA and, hence, cannot be netted out of the analysis to estimate T&D costs as was
done for Palo Alto and Long Beach. The heavy line at the center of the graph does, however,
provide the average non-gas revenue for each year. From 1995 to 2000, average non-gas
revenue for the panel members ranged from $0.18 to $0.25 per thermo The period average was
$0.22 per thermo
Figure 4: Muni Gas LDC Operating Costs per Therm
0.350 -+-Palo Alto CA
0.300
--Richmond VA
0.250
E
~ 0.200 --San Antonio TX
I-
8. 0.150 ---Springfield MO
<It 0.100
-- Citizens Gas &
0.050 Coke IN
0.000 ~Sample A\erag
2000 1999 1998 1997 1996 1995 (Excl PAU)
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
-
To provide an estimate of Chula Vista's operating costs, the panel data must be
adjusted for GF transfers. As shown in Table 6, GF transfers averaged 38 percent of non-gas
revenue for Long Beach and Palo Alto. This figure is substantially higher than the historical
average for all U.s. municipal gas utilities, which the MEU Study Team estimates to be in the
range of 10 percent of total revenue or about 25 percent of non-gas revenues, For the purpose of
a conservative analysis, the MEU Study Team assumed that the four panel members transferred -
an average of 30 percent of non-gas revenue to their General Funds during the 1995 to 2000
period. Operating expenses were assumed to comprise the remaining 70 percent. Based on this
assumption, average T&D revenue for the panel would be $0.15 per therm, In the MEU Study
Team's view, this is a reasonable proxy for the cost of providing gas delivery services to
residential, commercial, and industrial customers in Chula Vista. The estimate is comparable to
the figure estimated for Long Beach, but lower than Palo Alto's T&D cost in FY 1999-2000. -
This further underscores its reasonableness as the basis for a preliminary analysis of Chula Vista
gas utility feasibility.
-
The preliminary analysis assumed that Chula Vista could serve the South Bay
power plant for $0.001 per therm ($0.01 per Dth). The estimate assumes that the power plant is
served /Tom a relatively short lateral pipeline that connects directly to the main transmission line -
traverses Chula Vista along Interstate 5, The MEU Study Team further assumed that this
pipeline would not require any significant maintenance or upgrading during the entire forecast
period. This is probably a reasonable estimate until the power plant is expanded in 2008-09, but -
it likely understates the cost of serving an expanded power plant. However, since an engineering
analysis of the condition of the lateral and potential upgrade costs was beyond the scope of the
MEU Study Team's analysis, we were unable to determine a more precise estimate of this
potentially important variable.
Based on the above assumptions, annual operating costs are estimated to be $10.4 -
million in 2003, including $113,000 to serve the power plant. Chula Vista's operating costs were
assumed to increase by 3 percent per year through 2023. -
5. SoCal Gas and SDG&E Transmission Costs
-
To transport gas from the California border to its City Gate, Chula Vista would
need to pay SoCai Gas' wholesale rate for SDG&E plus the cost of transporting gas from the
SoCai Gas-SDG&E meter station to Chula Vista. SoCai Gas' wholesale transmission rate is
presently $0.018 per therm ($0.18 per Dth). While SDG&E does not currently have a gas
transportation rate for wholesale customers on its system, a proxy for this rate was calculated by
dividing SDG&E's total transmission cost of service by its total annual throughput. In its
decision in SDG&E's 2000 BCAP (D.00-04-020), the CPUC adopted an embedded transmission
cost of $33 million for SDG&E. Dividing by annual throughput of 1.441 billion therms, the per
unit rate works out to $0.023 per therm ($0.23 per Dth). Based on the MEU Study Team's
forecast of Chula Vista gas throughput, the annual cost of SoCai Gas and SDG&E transportation
149
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
-
service was estimated to be $7.36 million in 2003. These costs were escalated by 1.6 percent per
year, the same factor used to estimate future SDG&E's retail transportation rates,
-
6. Capital Cost Estimate
- Consistent with the analysis of electric utility ownership, the MEU Study Team
assumed that Chula Vista would acquire the SDG&E gas T &D facilities located in Chula Vista
for 1.64 times the net book value (depreciated rate base) of the facilities. The depreciated rate
- base of the Chula Vista facilities was estimated to be $20.5 million, 4.8 percent of the total net
book value ofSDG&E's gas plant in service at the end of 2002 ($423,2 million). Chula Vista's
percentage was based on its share of SDG&E's total non-EG throughput. This effectively
-- attributes minimal value to the transmission facilities used to serve the South Bay power plant.
Multiplying net book value by 1.64 yields an estimated acquisition cost of $33,5 million.
- Utility start-up costs were conservatively estimated to be 15 percent of the total
acquisition cost or $5.0 million. This is a preliminary estimate that would only cover the cost of
acquiring the land, buildings, office equipment, stores, and other items needed to fonn a gas
- distribution utility in Chula Vista. Start-up costs could turn out to be significantly greater if
additional metering facilities, regulating stations, or other systems are required to commence
utility operations.
-
The MEU Study Team assumed that the City would issue 30-year bonds to
finance the acquisition and start-up costs. At an interest rate of 6,5 percent, the annual principal
and interest cost is $418,000 per year. Annual capital investment costs are estimated to be
$958,000 per year in 2003, equivalent to the annual depreciation allowance assuming straight-
line depreciation over a 35-year period.
7. Estimated Benefit of Utility Ownership
Table 7 summarizes the results of the MEU Study Team's preliminary analysis of
the feasibility of gas utility ownership in Chula Vista. As shown on Line 10, under the
assumptions used by the MEU Study Team, the total operating and capital cost of providing gas
delivery service to Chula Vista customers in 2003 is estimated to be $19.1 million, or $0.106 per
thenn. The estimated cost of utility ownership is $777,000 greater than our estimate of the
revenues Chula Vista gas users would pay to SDG&E for these services. Upon establishing a
municipal utility, Chula Vista would cease receiving /Tanchise fees from SDG&E. Based on the
2.0 percent rate indicated in the /Tanchise fee estimates provided to the MEU Study Team, the
lost /Tanchise fee is estimate to be $657,000 in 2003. The total loss from utility operations is
thus $1.43 million in 2003. Based on the cost escalators and throughput estimates presented
above, the total loss is projected to grow to $3.6 million in 2010 and $7.0 million in 2023, Over
the study period, the MEU Study Team estimates that the City would lose approximately $24
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IV. EVALUATlON OF CHULA VISTA'S MEUOPTIONS
NATURAL GAS
million if it were to acquire the gas distribution system of SDG&E and provide gas service to
customers within the City.
Table 7
Estimated Benefits of Gas Utility Ownership in Chula Vista -
Line 2003 2010 2015 2023
1 C.V. Delivery Cost to RICII ($fTherm) $0.152 $0.187 $0.217 $0.275
2 Cost to Serve R/C/I (000$) $10,294 $14,053 $16,827 $22,102
3 Est. Cost to Serve Power Plant ($fTh) $0.001 $0.001 $0.001 $0.002
4 Cost to Serve Power Plant (000$) $113 $317 $367 $465
5 SoCalGas Wholesale Rate ($fTh) $0.018 $0.020 $0.021 $0.024
6 Est. SDG&E Trans. Rate ($fTh) $0.023 $0.026 $0.028 $0.032
7 SoCaIGas/SDG&E Cost (000$) $7,361 $15,174 $16,557 $18,963
8 Capital Expense (000$) $418 $418 $418 $418
9 Capital Improvement Cost (000$) $958 $958 $958 $958
10 Total Expenses $19,145 $30,920 $35,127 $42,907
11 $fTherm $0.106 $0.093 $0.105 $0.127
12 Estimated SDG&E Revenue $18,368 $28,157 $31,475 $37,036
13 SDG&E Revenue minus CV Cost ($777) ($2,763) ($3,652) ($5,872)
14 Lost Franchise Fee $657 $885 $978 $1,146
15 Net Benefit/(Cost) ($1,434) ($3,648) ($4,630) ($7,017)
8. SDG&E BCAP Proposal
On September 17, 2003, SDG&E issued a Notice of Proposed Change to Gas
Rates (Notice) informing customers of proposed increases in natural gas transportation rates
effective January 1,2005. The proposed rate changes are contained in SDG&E's 2005 Biennial
Cost Allocation Proceeding (BCAP) in CPUC docket A.03-09-031. The Notice was posted on
SDG&E's website and is being mailed to customers along with their natural gas bills. According
to the Notice, SDG&E is seeking relatively modest increases in bundled rates (i.e., including
commodity charges) for core residential and commercial customers, which would rise by five
and 16 percent over current levels, respectively. In contrast, noncore industrial and electric
generation customers would see rate increases of 67 and 81 percent, respectively.
Since SDG&E's gas transportation revenue requirement is proposed to increase
only 13.5 percent, it appears that the majority of the increase in noncore rates will result from a
proposal to replace the current marginal cost allocation methodology with an embedded cost
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
methodology. Marginal cost ratemaking (adopted by the CPUC in the early 1990s) tends to
assign a higher percentage of the utility's fixed costs to customer classes (especially core) that
require the most costly facilities to serve. Thus, a return to embedded cost ratemaking would be
consistent with the modest rise in core rates and the sharp increases in noncore rates described in
the Notice, Such huge rate increases pose risks for SDG&E, since the largest noncore customers
(particularly power generators) could be temped to switch to alternative fuel or take service /Tom
competing pipelines. Customers in highly competitive product markets could also be forced out
of business if they are unable to pass along the proposed rate increases to their customers. To
mitigate such risks, SDG&E is proposing "100 percent balancing account treatment" of non core
transportation revenues (i.e., any revenue shortfalls due to lower throughput or customer bypass
will be recovered by raising rates for subsequent periods). Both proposals are likely to be highly
controversial and strongly opposed by noncore customer representatives. At this time, it is
impossible to predict how the Commission will respond to this application.
It is similarly uncertain how the CPUC will respond to the concurrent application
by Southern California Gas Company (SoCal Gas) to make similar changes in its rates and
balancing accounts. If approved SoCai Gas' BCAP application (A.03-09-008) would more than
double the wholesale gas transportation rate charged to SDG&E. Since the wholesale rate is a
major cost component for Chula Vista, approval of both the SoCal Gas and SDG&E BCAP
applications could have offsetting impacts on Chula Vista. While gas consumers in Chula Vista
would pay higher rates to SDG&E, the rates Chula Vista would pay to SoCai Gas and SDG&E to
transport gas to its City Gate would also rise. Until the BCAP proceedings are much further
along, it would be speculative to assess the net impact of these changes on Chula Vista.
In the meantime, the MEU Study Team's detailed analysis of Chula Vista's gas
costs and rates remains a sound basis for determining if gas utility formation would be cost
effective in Chula Vista,
9. Conclusions
The MEU Study Team's preliminary analysis concludes that gas utility ownership
would not be cost-effective for Chula Vista. The major factors that drive this result include the
following:
(I) SDG&E's gas procurement costs are competitive with spot market prices at the
southern California-Arizona border at Topock. SDG&E owns relatively limited
interstate pipeline capacity that could become uneconomic under reasonable market
conditions. In addition, since SDG&E buys most of its gas under short-term contracts
or contracts indexed to spot market prices, there is little potential for gas contract
costs to rise substantially above prevailing market prices. Under these conditions,
there is little potential to earn a benefit /Tom gas supply aggregation in Chula Vista.
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
NATURAL GAS
As a result, the economics of gas utility operation hinge on whether Chula Vista can
serve its potential customers for less than SDG&E.
(2) SDG&E is an efficient transporter of natural gas to its retail customers, SDG&E's
cost perfonnance was documented by a benchmarking study filed with the CPUC in
the company's pending GRC (A02-12-028).84 The study benchmarked SDG&E
against a national panel of 42 gas distributors that collectively serve 52 percent of
U.S. gas customers. The panel included most of the nation's largest distributors. The
study found that SDG&E's productivity during the 1998-2000 period was 33 percent
above the nonn and ranked first among the sampled LDCs. SDG&E's average total
cost of distribution services was also reported to be 37 percent below the costs
predicted by the consultant's econometric model for this period. Another indicator of
SDG&E's cost competitiveness is the fact that its system average rate is only 3.3
percent higher than that of its sister company, SoCal Gas, a utility with total
throughput 6.6 times greater than SDG&E. The reported efficiency of SDG&E will
make it that much harder for a new gas utility to provide comparable service at a
lower cost.
(3) Competing with SDG&E was further complicated by the CPUC's adoption of a
Sempra-wide gas transportation rate in 2000. Under this rate method, all EG
customers in southern California pay the same intrastate transportation rate. At
$0.027 per thenn ($0.27 per Dth), the current rate for the largest EG customers (with
annual usage over 3 million thenns) is $0.012 per them ($0.12 per Dth) less than
SDG&E's stand-alone cost of serving power plant customers. The rate is also less
than the sum of the SoCal Gas' wholesale transportation rate for SDG&E ($0.018 per
thenn ($0.18 per Dth) plus SDG&E's estimated gas transmission rate for Chula Vista
of $0.023 per thenn ($0.23 per Dth). As a result, before adding any internal capital or
operating costs, Chula Vista is projected to lose roughly $0.014 for every thenn of
gas delivered to South Bay. A shown by Table 8, annual losses are projected to grow
substantially over time, increasing /Tom an estimated $1.5 million in 2003 and $7.0
million in 2023. Such losses are unlikely to be offset by property taxes and other
revenues /Tom the power plant.
84 Prepared Direct Testimony of Mark Newton Lowry on Behalf of San Diego Gas and Electric Company,
tiled December 20, 2002, revised May 1,2003. The study can be downloaded from the following link:
bttp://www2.sdge.com/tarifflCOS/sdge/pdflExhibitSDGE21.pdf.
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IV. EVALUATION OF CHULA VISTA'S MEU OPTIONS
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Table 8
Economics of Serving South Bay Power Plant
-
2003 2023
South Bay Gas Usage 000 Therms 113,489 257,544
- SDG&E EG Rate $rrherm $0.027 $0.038
SDG&E Cost 000$ $3,118 $9,769
- SoCaIGas/SDG&E Rate to C.V. $rrh $0.041 $0.056
SoCaIGas/SDG&E Cost 000$ $4,612 $14,452
Net Profit/CLoss) 1/ ($1,495) ($4,683)
1/ Excludes Chula Vista caoital or ooeratina costs,
(4) The MEU Study Team's benchmarking analysis of municipal gas utilities in
California and other regions of the United States indicates that Chula Vista is unlikely
to provide gas delivery service to its residential, commercial/industrial, and power
plant customers for less than the average rate of $0.10 per thenn these customers pay
to SDG&E. The average T &D cost of the two leading California municipal gas
systems, Long Beach and Palo Alto, is close to $0.20 per thenn. The average T&D
rate for the four utilities surveyed by NCI is about $0.15 per Dth. Thus, even
assuming a low $0.01 per therm rate to serve the South Bay Power Plant, the average
cost of service estimated for Chula Vista ($0.106 per thenn) is projected to be five
percent higher than SDG&E's current rate. Including the loss of franchise fee
payments after municipalization, Chula Vista is projected to lose approximately $1.5
million per year providing gas distribution service in 2003. The loss is projected to
rise to $3.6 million in 2010 and $7 million in 2023. Over the 18-year period from
2006 to 2023, the NPV of the total loss is estimated to be $24 million.
(5) As this feasibility analysis reflects, on September 17, 2003, SDG&E filed an
application for significant increases in its natural gas rates as part of its Biennial Cost
Allocation Proceedings (BCAP). If approved, SDG&E's new gas rates would
become effective on January I, 2005. In the event that SDG&E succeeds in its
proposal to increase its gas rates, the MEU Study Team recommends that the City
should reexamine the feasibility of providing gas distribution services.
154
- _m m --______m____-
V. CONCLUSIONS AND RECOMMENDATIONS
CONCLUSIONS
AND
RECOMMENDATIONS
155
V. CONCLUSIONS AND RECOMMENDATIONS
V. CONCLUSIONS AND RECOMMENDATIONS
A. Discussion and Comparison of Recommended Options
In adopting Ordinance No. 2835 establishing the City as a Municipal
Energy Utility,85 and Resolution No. 2001-162 adopting the City Energy Strategy,86 the
City of Chula Vista has laid a firm foundation and preserved its options for the
development and implementation of energy projects for the benefit of the City and its
inhabitants. In furtherance of the City Energy Strategy Plan, the City retained the MEU
Study Team to perform a "Municipal Energy Utility Feasibility Analysis" based, in part,
upon the results of earlier studies performed for the City by MRW Associates and
Science Applications International Corporation.
In conducting this feasibility analysis, the MEU Study Team performed a
thorough analysis of the energy markets in California and in the San Diego Gas &
Electric Company's service territory and prepared a comparative analysis of the City's
opportunities and options to develop and implement the City Energy Strategy. Following
the directives of the City's Council and Staff, the MEU Study Team developed a series of
conclusions and recommendations, which are summarized below. In conducting this
feasibility analysis, the MEU Study Team examined both the markets for electricity and
gas and determined the feasibility of developing a Municipal Energy Utility, that would
provide both electric and gas service. For the reasons set forth in this Report and
summarized below, the MEU Study Team has concluded that it is feasible for the City to
develop and implement a municipal electric utility on a phased basis. At the same time,
however, the MEU Study Team concluded that it is simply not financially or
economically feasible under any scenario for the City to undertake to provide gas service
to consumers within the City within the study period, barring a change in the projected
natural gas rates for SDG&E. The options examined by the MEU Study Team are
discussed separately below, together with the recommendations and conclusions reached
with the completion of this feasibility analysis.
B. Electric Service
After an initial screening to identify all MEU options available to the City
under applicable State and Federal laws and regulations, the MEU Study Team conducted
a detailed economic analysis which included a separate evaluation of three basic
municipal electric utility options. These options included: (1) ownership and operation
of distribution facilities in newly developing areas within the City (Greenfield
development); (2) aggregation of electric loads within the City for purposes of procuring
wholesale electricity through a Community Choice Aggregation program (CCA), as
provided for in Assembly Bill 117 (2002); and (3) acquisition of the existing SDG&E
distribution system within the City boundaries and assumption of SDG&E's distribution
" Ordinance No. 2835, June 5, 2001.
86 Resolution No. 2001.162, May 29, 2001.
156
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I
V. CONCLUSIONS AND RECOMMENDATIONS
operations to serve electric customers within the City (MDU). The MEU Study Team
also perfonned an economic analysis of a combined Greenfield/CCA option, Each of
these options are identified as economically feasible for immediate or near-tenn
development.
In addition to the three basic MEU options, the MEU Study Team also
identified and evaluated two additional options which would be recommended in the long
tenn only in the event that the City develops a full service electric distribution system,
The long-range options which were evaluated and analyzed were (I) the development of
a Municipal Utility District (MUD), and/or (2) participation in a Joint Powers Agency
(JPA) to broaden the City's energy supply options and take advantage of the economies
of scale.
Each of the foregoing options is separately discussed and summarized
below.
1. Community Choice Aggregation Programs
The first option analyzed and evaluated by the MEU Study Team is a
CCA program pursuant to Assembly Bill 117 (Midgen 200-2 - Chapter 838, Statutes of
2002).
Under the CCA option, the City would procure electric supply for
customers of the CCA, and SDG&E would continue to deliver the electricity to end users
over the distribution facilities owned and operated by SDG&E. Customers would
continue to pay SDG&E at retail rates for transmission and distribution services, but
would receive a credit for the costs related to generation and the procurement of
electricity that would be provided by the CCA.
The CCA option is complicated somewhat by the fact that the CPUC has
not issued fmal rules and regulations to implement CCA pursuant to Assembly Bill 117.
On September 4, 2003, the CPUC issued an order instituting rulemaking (R.03.03.007)
which establishes proposed rules for CCA and a schedule for final implementation of the
program. On October 2, 2003, the CPUC reissued the proposed Rulemaking under
Docket No. R.03-10-003, and an initial prehearing conference and workshop have been
held. At this juncture, the CPUC has not set a date for fina1 implementation of the CCA
rules and regulations.
If the City elects to pursue implementation of a CCA program, the MEU
Study Team believes it is important for the City to continue to be at the table representing
its interest in ongoing CPUC proceedings to establish the costs, credit, rules and
protocols that will ultimately decide CCA program cost-effectiveness and feasibility, By
actively participating in related CPUC proceedings, hearings and workshops, the City can
best advance its interests.
157
-
V. CONCLUSIONS AND RECOMMENDATIONS
In preparing the financial pro forma for a CCA program, the MEU Study
Team did a thorough analysis of: (I) SDG&E's forecasted rates (including potential exit
fees and lost fTanchise revenues); (2) CCA energy or commodity costs (including
generation ownership, power purchase contracts, renewable energy contracts and spot-
market purchases; (3) CAISO charges; and (4) operation and maintenance costs. In this
evaluation, the MEU Study Team assessed the cost and benefits of the CCA program
based on two energy strategies. Under the first strategy, the City would procure all of its
energy requirements in the wholesale energy market by executing power contracts with
various power suppliers at fixed prices for medium and short terms (Contracts Supply
Strategy). In the second strategy, it was assumed that the City would install its own
generating facilities or take an ownership position in a power generation facility
developed by another entity (Generation Supply Strategy). The Generation Supply
Strategy is based upon City ownership of, or entitlement to, 130 MW of new combined
cycle gas turbine power plant capacity. The financial pro forma analysis compares the
total costs of each option with the total costs of continuing to take retail utility service
/Tom SDG&E.
Under the Contracts Supply Strategy, cost savings are projected to occur
in the years 2006-10. Projected SDG&E rate reductions in 2011 resulting /Tom the
expiration of DWR power purchase contracts eliminate the savings in the years 2011
through 2014. At that time, annual increases in SDG&E's rates are projected to provide
persistent savings to the City through the study period. Savings begin at $6.3
million/year in 2006 and increase to $11 million/year in 2023.
The CCA program with a Generation Supply Strategy promises to
optimize the City's revenues and savings to its customers. If Chula Vista secures 130
MW of generation capacity, the MEU Study Team projects savings to begin at $13.3
million/year in 2006 and grow to $21.3 million/year in 2023. Here again, savings will be
reduced significantly in the years 2011-2014 due to the expiration of SDG&E's DWR
contracts and increase as SDG&E's wholesale rates are increased,
The major benefit available under the CCA program is that, under this
option, the City could begin purchasing electric energy and supplying it to its retail
customers without the need to purchase the SDG&E electric distribution system. It
would also provide a generation portfolio and the infTastructure and experience necessary
if the City later elects to establish an MDU and acquire and operate the electric
distribution system within the City.
2. Greenfield Development
Under the Greenfield utility structure, the City of Chula Vista, in
collaboration with developers, would build and own the new electric distribution facilities
in selected developing areas, In those undeveloped areas in which SDG&E has not
installed electric distribution facilities, the City may exercise its right to begin to provide
electric service and to own and operate the electric distribution system. Using these new
distribution facilities, the City can serve end use customers located in the newly
158
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V. CONCLUSIONS AND RECOMMENDATIONS
developed area with power it procures at wholesale fÌ'om suppliers under power purchase
contracts.
In performing the economic study of Greenfield development, the MEU
Study Team worked with the City Planning Division Staff to identify prospective new
development areas. Based upon planned land use in these areas, the MEU Study Team
modeled the site specific energy requirements in each of six areas. The areas found to be
especially adaptable to Greenfield development were the Mid-BayfÌ'ont area, the
Eastlake/Otay Ranch area and the Sunbow Industrial Planning area,
The Greenfield utility option would require that the City take wholesale
transmission service /Tom SDG&E and the CAISO and to develop the infrastructure to
interconnect the City's distribution facilities with SDG&E at a distribution voltage.
SDG&E would provide wholesale transmission service to the City under SDG&E's
WDAT.
The MEU Study Team projected the cost of taking wholesale distribution
service under SDG&E's WDAT and developed projections for the initial cost of
construction, the distribution infrastructure necessary to serve the Greenfield areas. The
MEU Study Team then developed a projected electric supply portfolio, including long
and short-term power purchase contracts and renewable energy contracts. The study
showed that a stand-alone Greenfield utility was not of sufficient size to support the
development of an internal generation project by the City. Therefore, the projected
power supply for the Greenfield utility is 100% contract based.
Based upon the economic analyses, the MEU Study Team concluded that
a Greenfield utility could commence service in 2006, but would suffer some losses until
2012, Beginning in 2012, the MEU Study Team projected persistent savings through the
end of the study period (2023) due to the addition of a larger number of electricity users
and the addition of large commercial and industrial loads. Accordingly, the MEU Study
Team has concluded that the development of Greenfield Projects within the City is both
economically feasible and desirable and recommends that the City immediately
implement plans to develop Greenfield projects,
In addition to the economic benefits to be derived over the study period,
the development and operation of Greenfield projects also produces other non-financial
benefits to the City. Importantly, the operation of the City's Greenfields projects will put
the City into the utility business, provide City personnel with experience in operating an
electric utility, and provide the City with the beginnings of an electric distribution
inftastructure, Moreover, as discussed below, the Greenfield option can be readily
combined with a CCA program to optimize savings to customers within the City and is
easily absorbed as part of a municipal distribution system if the City later decides to form
an MDU and acquire and operate the electric distribution facilities within the City
boundaries,
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V. CONCLUSIONS AND RECOMMENDATIONS
3. Combined CCA and Greenfield Development
The detailed economic and financial analysis performed by the MEU
Study Team demonstrates that the City can obtain the greatest potential benefit in the
short term by forming a CCA and simultaneously pursuing Greenfield project
opportunities. Under the most beneficial option, the City would build or otherwise gain
entitlement to a generation project (130 MW) within the City to supply the combined
CCAlGreenfield loads. The CCA program would give the City the operational scale
required to effectively source electricity for the CCA and Greenfield customers and
successfully compete with the electric supply portfolio of SDG&E.
In implementing the combination of CCA and Greenfield projects, the
City can capture the benefits of CCA in areas where there is presently an SDG&E
distribution infÌastructure and realize commensurate savings on the electric energy
component for Greenfield areas, thus significantly increasing the cost effectiveness of the
Greenfield projects. Administration of the combined CCA and Greenfield Projects would
be consolidated under a single City Staff (Municipal Electric Department).
In the combined CCAlGreenfield scenario, the City would implement a
City-wide CCA program concurrent with efforts to begin distribution utility operations in
Greenfield development areas. The City would supply electricity to all electric customers
within the City and distribute electricity to electric customers within the Greenfield
development areas.
For non-Greenfield areas, the City would produce or provide electric
supply for its CCA customers and SDG&E would continue to deliver the electricity to
end-use customers over its distribution facilities. The City's CCA customers would pay
SDG&E the retail rate for non-generation (transmission and distribution) services as they
do today and would receive a generation credit for electric power provided by the City
under the CCA program. SDG&E would continue to perform metering and billing
services for end-use CCA customers.
For Greenfield areas, the City would take wholesale transmission service
/Tom SDG&E or the CAISO, and its customers in Greenfield development areas would
no longer pay SDG&E retail rates. The City would take transmission service from
SDG&E under its WDAT for the Greenfield development loads at transmission rates to
be determined based on the SDG&E facilities actually used to provide this service.
Consumers in the Greenfield areas would receive a power credit for electric power
purchased or produced by the City.
As discussed above, the implementation of a CCA program is complicated
by the fact that the CPUC has not issued rules and regulations for implementation of
CCA programs. This complication would also be applicable to the CCAlGreenfield
combination and may delay the immediate implementation of the CCA option.
160
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V. CONCLUSIONS AND RECOMMENDATIONS III
Based on the financial pro fonna perfonned by the MEU Study Team, the ~
combined CCNGreenfieid utility option, using in-City generation would produce savings ~
amounting to $14,9 million in 2006 and increase to $31.7 million in 2023 (again with
significant reductions in savings in the 2011-2014 time frame),
The MEU Study Team strongly recommends that the City implement the III
combined CCNGreenfield utility option in the immediate future. The MEU Study Team
estimates that a CCA program would be operational by mid-2005 (assuming that the II
CPUC issues final rules and regulations by mid-2004), With respect to Greenfield
development, the MEU Study Team estimates that the initial Greenfield project could be
implemented in a 15 to 20 month time frame depending upon the construction schedule II
and building occupancy within the designated Greenfield areas. Thus, a combined
CCNGreenfield operation could be implemented at least by 2006,
4. Municipal Distribution Utility II
Under the Municipal Distribution Utility (MDU) option, the City would ~
acquire, by negotiation or through the exercise of the power of eminent domain, the
electric distribution facilities ofSDG&E within the City's boundaries, The City's MDU
would take wholesale transmission service nom SDG&E and the CAISO and its ~
customers would no longer pay the SDG&E retail rates.
Once the MDU is established, the MDU would take wholesale ~
transmission service from SDG&E under SDG&E's WDAT which defines the applicable
charges and tenns and conditions of transmission service.
SDG&E would be required to perfonn a study to determine the cost of any ,
reconfiguration of the SDG&E system in order to separate and interconnect the MDU
system with the remaining SDG&E system. The Federal Energy Regulatory Commission ,
would, in the event of a dispute, detennine the tenns and conditions of the
interconnection of the MDU with the SDG&E transmission system and the
interconnection and related costs would be directly assigned to the MDU. ~
If the MDU and SDG&E cannot agree on the tenns and conditions of the
acquisition, including the pricing of the distribution system, the City will be required to ~
initiate and prosecute the condemnation of SDG&E's distribution system and allow the
condemnation court (or, alternatively, at the discretion of the City the CPUC) to ~
detennine the value of the facilities acquired and any related severance costs,
Once established, the MDU would become a full service electric ~
distribution utility and commence serving some 86,652 retail electric customers with a
peak electric load of approximately 147 megawatts.
The MDU option would require a substantial investment in distribution I
infTastructure to distribute electric power to the customers of the City's MDU, including
I
161 I
~
V. CONCLUSIONS AND RECOMMENDATIONS
distribution substations, primary distribution transfonners, primary distribution wires and
poles, final line transfonners, secondary distribution feeders, and meters,
For purposes of this feasibility analysis, the MEU Study Team has, based
on data available from SDG&E, the City's tax records, and the CPUC, estimated the
value of the SDG&E distribution system at $170 million. Using this acquisition cost
figure, the MEU Study Team estimated the combined system acquisition and start-up
costs (including distribution facilities, customer service call center, billing equipment and
service vehicles) to be $185 million.
In assessing the feasibility of the MDU option, the MEU Study Team has
assumed that the City would either (I) acquire at least 130 MW of combined cycle gas
turbine capacity (Generation Supply Strategy) or procure all electric requirements under
power supply contracts and renewable energy contracts (Contracts Supply Strategy), As
shown in the results of the study, the MDU operation would benefit by ownership of
generation within the City as opposed to purchasing all requirements under contract.
Production costs of a new combined cycle gas turbine are projected to be below the
market clearing prices in the California market. Moreover, by locating and owning
generation within the City boundaries, the MDU would avoid paying high transmission
costs, including transmission congestion charges and other charges assessed by the
CAISO.
In addition to the capital costs necessary to acquire the SDG&E
distribution system and establish necessary interconnections and bulk power supply costs,
the MEU Study Team estimated the distribution operations and maintenance costs and
has taken into consideration the required payment for "exit fees" and other non-
bypassable charges mandated by legislation and related CPUC orders and any applicable
Federal stranded costs which may be required under FERC rules or regulations. The
MEU Study Team has also factored in the loss of /Tanchise and/or tax revenues. As set
out in more detail in the technical appendices, the actual amount of any applicable exit
fees or cost responsibility surcharges will vary over time and depending on the outcome
of several pending proceedings before the CPUC. To the extent that exit fees are leveled
out over time, the costs will be borne by departing customers for a longer period of time.
In the event that the fees are charged at higher rates in the beginning, they will be paid
off sooner, and therefore no longer a factor in considering longer tenn strategies.
Based upon the pro fonna financial analysis perfonned by the MEU Study
Team, a City-owned MDU would, under the MDU Generation Supply Strategy (i.e.,
with at least 130 MW of in-City generation) realize $12.3 million/year in savings in 2006
and increasing to $28.7 million in 2023. Savings would be substantially reduced in the
2011-2014 time frame due to the expiration ofSDG&E's obligations under its contracts
with DWR. Savings over the study period (2008-23) would amount to approximately
$329 million yielding an NPV of $109 million.
Under an MDU Contracts Supply Strategy (i.e., under which the Chula
Vista MDU purchases all electric power requirements in the market and pays related
162
,~~.~".."_.
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V, CONCLUSIONS AND RECOMMENDATIONS
transmission costs), the MDU would suffer losses in the first eleven years and realize
only modest savings in the period fÌOm 2017 through 2023. Based upon the pro forma
results, the MEU Study Team has concluded that an MDU that relies exclusively on
market purchases of wholesale electricity to serve the entire load requirements of its
customers would not be a cost-effective option for the City in the near term.
Under an MDU Generation Supply Strategy, based upon the positive
results of the pro forma fmancial studies and the other major benefits, which will accrue
from the implementation of the MDU option, the MEU Study Team believes that it is
feasible, /Tom both an economic and operational standpoint, for the City to form and
operate an MDU by acquiring the distribution assets of SDG&E. In coming to this
conclusion, the MEU Study Team recognizes that, because of the substantial capital
investment required to acquire the distribution system, generation facilities and to defTay
the start-up expenses for an MDU, the potential value of benefits to the City is less
favorable than the CCA/Greenfield option with a Generation Supply Strategy, At the
same time, the MEU Study Team is of the opinion that, in the long run, the ownership of
the electric distribution system would allow the City to serve all electric customers within
the City at rates substantially below the current and projected rates of SDG&E and permit
the city to build asset value in the distribution system. The MEU Study Team has also
given substantial weight to the non-financial benefits to be realized by public ownership
of the distribution system, including local control of rates and service, discretion in the
application of savings or benefits, and independence /Tom SDG&E and the
owner/operators of the transmission grid.
Given the additional planning and study requirements needed to
implement the MDU option, together with the procedural steps which must be followed
under the Eminent Domain Law, the MEU Study Team recommends that the City defer
implementation of the MDU option until the 2008-10 time frame and re-evaluate the
option based on circumstances existing at that time, Assuming that the City proceeds to
develop the CCA and Greenfield options in the meantime, the City will have an MEU
infrastructure, customer base, generation facilities and several years of operating
experience before needing to make the critical decision of potentially acquiring the
distribution system of SDG&E. In the event that CCA appears to be uneconomic once
the CPUC has issued its final rulemaking decisions, the MEU Study Team would
recommend that the City accelerate its consideration of the MDU option.
S. Joint Powers Agency and Municipal Utility District Options
As discussed in Section IV. G of this Report, once the City ofChula Vista
establishes a full service MDU and acquires the electric distribution facilities of SDG&E,
two other long-range options will be available to the City's MDU. The City, through its
MDU may be able to participate in an existing JP A, or form, in partnership with another
community, unincorporated territory, or public utility entity, an MDU. These options are
discussed briefly below,
163
r
V. CONCLUSIONS AND RECOMMENDATIONS
a. Joint Powers Agency
Under California law, a municipal electric utility, in combination with one
or more other municipal electric utilities (including other publicly-owned electric
systems, an irrigation district, public utility district or municipal utility district) may form
a JP A to provide either generation resources, transmission services, or both.
Currently, there are a number of joint action agencies operating in the
State of California including the Southern California Public Power Agency (SCPP A), the
Northern California Power Agency (NCPA), M-S-R Public Power Agency (M-S-R) and
the Transmission Agency of Northern California (TANC). Of these, based on geographic
considerations, SCPPA is the only JPA that might offer the Chula Vista MDU any
benefits in the form of generation or transmission resources in the foreseeable future.
Because JP As plan and develop transmission and generation resources to meet the
existing and prospective needs of its members, it is unlikely that SCPP A would be in the
position to provide any transmission or generation benefits to the Chula Vista MDU /Tom
existing projects and contracts, all of which are dedicated to the needs of existing
members. The Chula Vista MDU could, however, apply for membership in SCPPA for
the purpose of participating in any future generation or transmission projects. Moreover,
/Tom time to time, the Chula Vista MDU might find opportunities to acquire surplus
capacity /Tom the existing members of SCPP A on a priority basis once it becomes a
member of the JPA.
It is premature at this juncture to attempt to identifY or quantifY any
specific benefits that the Chula Vista MDU might realize /Tom membership in a JPA.
This is, however, an important option which should be explored once Chula Vista
establishes a full service electric distribution system.
Once the Chula Vista MDU becomes a member of an operating JPA, it
will be able to take advantage of possible aggregation of a larger load for resource
procurement purposes and, with the addition of power supply partners, the Chula Vista
MDU could share or spread the risks of operating the MDU. Membership in a JP A
might, in turn, lead to possible reductions in operation and maintenance costs through
cost sharing arrangements with other members of the JP A.
In the near term, there is no need for the City to take any action related to
membership in a JP A. Once it is in the business of providing full service electric
distribution service, however, the City should examine all options open to forming or
joining a JPA.
b. Municipal Utility District
Under California law, a municipality is permitted to join or form an MUD
for the purpose of developing generation and transmission resources and otherwise
conducting utility operations on a District-wide basis. Interestingly, it is not required that
the members of an MUD be located contiguously. Under these circumstances, Chula
164
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--
V, CONCLUSIONS AND RECOMMENDATIONS
Vista, once it determines to provide full electric utility distribution service, could form an
MUD with another community, unincorporated area or public power entity located in
other parts of the State,
At present, there are no MUDs operating in Southern California, There
are, however, some fifteen other municipal electric systems operating in Southern
California and a number of other cities are attempting to form municipal utilities within
their boundaries.
Like a JPA, the MUD model would allow the City MDU to spread risk,
take advantage of the economies of scale and combine electric loads to the end that it can
secure more competitively priced power by combining the needs of more residential and
commercial and industrial loads, thereby lowering the price of utility services, on a per
unit basis, for all customers within the boundaries of the MUD,
It is premature at this juncture to speculate on the potential for partners to
join with Chula Vista in forming an MUD, The options are almost endless inasmuch as
the City can join with any other community or unincorporated territory in forming an
MUD, It is not a prerequisite that the community or unincorporated territory have an
existing municipal electric system and there is no requirement that the participants in the
MUD be contiguous. Suffice it to say that, once Chula Vista elects to provide full
electric utility distribution services, it may want to identify opportunities to joint venture
the utility operation with another community or unincorporated territory under an MUD
structure.
c. Roll Out Strategy
As part of this feasibility analysis, the MEU Study Team has provided a
detailed listing of the major and critical steps necessary to implement each of the
recommended MEU options. The MEU Study Team has also provided a Gantt Chart
showing the time-line requirements for each major step or task necessary from the
initiation of the process to operations. (See Gantt Charts below and in Appendix C,
Section V at 130-32).
1. CCA - Implementation Schedule
The MEU Study Team recommends a two-track approach to evaluate and
implement a CCA project. Within Track One the following tasks are required
immediately: (1) conduct an orientation session for Elected Officials and Staff on this
option including a review of this feasibility analysis; (2) continue active participation in
the CPUC's proceedings and workshops for the development of costs, credit rules and
regulations; (3) update the feasibility analysis with information from the CPUC
proceedings; and (4) develop the CCA Implementation Plan, adopt the Implementation
Plan at a duly noticed public hearing, pass an Ordinance to implement CCA per the
~, 165
V. CONCLUSIONS AND RECOMMENDATIONS
Implementation Plan and file the Implementation Plan with the CPUC by July 2004.87
Under Track One, the MEU Study Team anticipates that the CPUC approval of the City's
Implementation Plan would take between four to seven months.
Assuming CPUC approval of the City's CCA Implementation Plan by
January 2005, the following tasks would be initiated simultaneously within Track Two:
(a) the City would execute a Service Agreement with SDG&E; (b) complete
development of CCA metering facilities; and (c) complete customer notification
regarding opt-out provisions. Between July 2005 and January 2006 the following
iterative and on-going activities should be conducted by the City: (I) activate Energy
Supply Resource Plan; (2) address Load Forecast and Optimize Scheduling; (3) manage
supply portfolio and risk management (4) process financial settlements; and (5) produce
operating statements and reports. Under this schedule and based on these assumptions,
the MEU Study Team anticipates that a CCA project could be operational by early 2006.
Please see Section IV.C.6 at 58-60 for more detail on this Implementation Schedule.
87 Although the CPUC has not approved rules for the implementation of the CCA program, the draft
rules and CPUC precedent indicate that parties have submitted applications for the CCA program.
166
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2. Greenfield - Implementation Schedule
Recognizing that the City has previously passed an ordinance to form a
municipal utility and, working back /Tom the date that occupancy of the Greenfield areas
would be initiated (as early as July 2005), the MEU Study Team recommends that the
following steps be taken by the City to implement the Greenfield option: (1) consult with
electric distribution design firms and developers to design and specifY system
requirements for the Greenfield Project, initiate in January 2004 and complete by April
2004; (2) following the development of the design and system requirements, the City
would need to determine the interconnection requirements, which includes an assessment
of technical requirements and costs to achieve interconnection of the distribution system,
initiate in April 2004 and complete no later than mid-November 2004; (3) evaluate and
assess projected loads, costs and benefits, initiate in November 2004 and complete by
mid-December 2004; 4) based upon the final evaluation ofload studies and forecasts, the
City would need to tailor and implement a resource plan and schedule power and update
power delivery schedules; (5) the City would initiate a human resource plan, in December
2004 and complete staffing by February 2005; (6) developers would complete
infTastructure construction (trenches, conduits, vaults and transformer pads) in the March
to April 2005 time /Tame; (7) high voltage contractors would install conductors,
transformers, service drops and metering in April 2005; (8) contractors would install
streetlights, traffic signals and landscape irrigation facilities (peripheral equipment) by
Mid May 2005; and (9) utility service could be provided between mid-May and mid-June
2005 or be scheduled to coincide with an occupancy. Please see Section IV.D.6 at 77-79
for more detail on this Implementation Schedule.
168
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V. CONCLUSIONS AND RECOMMENDATIONS
3. CCAlGreenfield - Implementation Schedule
The implementation schedule for the CCAlGreenfield entails utilizing the
major and critical steps identified in the implementation schedules for CCA and
Greenfield options and combining them. The major and critical steps and timelines
would remain unchanged.
- 4. MDU - Implementation Schedule
.- If the City elects to form an MDU, the MEU Study Team has identified
the following major and critical steps: (I) During the first year after electing to pursue the
MDU option, the City should complete the feasibility and implementation plan, which
- includes: (a) Distribution System Survey and Valuation, (b) Severance Plan and Cost
Study, (c) Energy Resource Plan, (d) Human Resource Plan, (e) Facilities Plan, (t) Pro
Forma Update, (g) Finance Plan, (h) Governance Plan, and (i) Implementation Plan. (2)
by the end of the first year, establish public interest; (3) begin the condemnation process:
(a) offer to purchase the distribution facilities of SDG&E, (b) public hearing on finding
of public interest and necessity, (c) adopt Resolution of Necessity to condemn property,
(d) second and final offer of purchase to be extended to SDG&E, (e) judicial review of
Resolution of Necessity, (t) conduct the condemnation proceeding; and (4) execute
Implementation Plan once condemnation proceedings have been completed and an Order
for Possession has been entered by a court of competent jurisdiction. If the City elects to
implement the MDU option in the 2010 time /Tame, after the establishment of the
Combined CCAlGreenfield option, as recommended by the MEU Study Team, the City
would commence the MDU Planning and Implementation elements in mid-2008. Please
see Section IV.F.6 at 127-131 for more detail on this Implementation Schedule.
170
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Public Copy
City Clerk's Office
~
Attachment 6
~
CITY OF CHULA VISTA
~
MUNICIPAL ENERGY UTILITY
FEASIBILITY ANALYSIS
~
~ .
~
APPENDICES
~
~ .
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Submitted Jointly by:
-
DUNCAN, WEINBERG, GENZER & PEMBROKE, P.C.
- McCARTHY & BERLIN, L.L.P
AND
NA VIGANT CONSULTING
~
- .
-
- March 19,2004
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Printed on recycled paper
-
-
APPENDIX A
- ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
-
.-
-
-
-
-
APPENDIX A
-
- ABBREVIATIONS,
ACRONYMS, GLOSSARY OF TERMS
-
~-----~--------------
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
ENTITIES
APX Automated Power Exchange
CAISO California Independent System Operator Corporation
Calpine Calpine Energy Services, LP
-
CEC California Energy Commission
CPUC Public Utilities Commission of the State of California
CRE Comision ReguJadora De Energia (Mexico's Energy Regulatory
- Commission)
DWR California Department of Water Resources
--
Duke Duke Energy North America
EPA Environmental Protection Agency
EIA Energy Infonnation Administration
FERC Federal Energy Regulatory Commission
- LADWP Los Angeles Department of Water and Power
PG&E Pacific Gas and Electric Company
PG&E NEG PG&E National Energy Group
PX California Power Exchange
SANDAC San Diego Regional Planning Agency
SDAPCD San Diego Air Pollution Control District
SMUD Sacramento Municipal Utility District
I
------ .------.-
APPENDIX A
ABBREVIA nONS, ACRONYMS
GLOSSARY OF TERMS
SDG&E San Diego Gas & Electric Company
-
SCE Southern California Edison Company
--
SoCai Gas Southern California Gas Company
WECC Western Electricity Coordinating Council -
TERMS -
APD Abnormal Peak Day -
Bcf One Billion Cubic Feet of gas
-
Btu British Thermal Unit
CAT Core Aggregation Transportation .-
CCA Community Choice Aggregation
CCGT Combined Cycle Gas Turbine
CEQA California Environmental Quality Act --.
CGR California Gas Report
--
CPCN Certificate of Convenience and Public Necessity
CRR Congestion Revenue Rights --
CRS Cost Responsibility Surcharge
CSA Comprehensive Gas on Settlement Agreement
CTS Competitive Transition Charge
DA Direct Access
DG Distributed Generation
2
------------.----------- -.-.--------- -------
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
DRP Demand Response Program
-- EG Electric Generation
ERC Emission Reduction Credits
-
ESP Energy Service Provider
- FSD Firm Demand Service
FPA Federal Power Act
-
GMC Grid Management Charge
- GW Gigawatt (I million kilowatts)
GWh Gigawatt Hour
HHD Households
- IOU Investor Owned Utility
JPA Joint Powers Agency
KW Kilowatt (one thousand watts)
kWh Kilowatt Hour
LAFCO Local Agency Formation Commission
LDC Local Distribution Company
LMP Locational Marginal Pricing
LNG Liquefied Natural Gas
LOLP Loss Of Load Probability
Mbtu One Thousand Btus
3
-.--- --
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
MCf One Thousand Cubic Feet of Gas
MDL Municipal Departing Load
Municipal Electric Utility .-
MEU
MDU Municipal Distribution Utility -
MMBtu One Million Btus
-
MMcf One Million Cubic Feet of Gas
MPPSA Master Power Purchase and Sale Agreement between Calpine and DWR -
dated May 1,2002
MW Megawatt -
NBP Mexican North Baja Pipeline
-
NPV Net Present Value
O&M Operations And Maintenance -
OFO Operational Flow Order
-
PTO Participating Transmission Owner
QF Qualifying Facility -
PUD Public Utility District
RCN Replacement Cost New
RCNLD Replacement Cost New Less Depreciation
RPS Renewable Portfolio Standard
-
SIL Simultaneous Import Capability Limitation
SMD Standard Market Design
4
---
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
--- TCF One Trillion Cubic Feet of Gas
TGN Transportado de Gas Natural de Baja California (Rosarito Pipeline)
URG Utility Retained Generation
- VOC Volatile Organic Compounds
WDAT Wholesale Distribution Access Tariff
-
GLOSSARY OF TERMS
-
Base Load The minimum constant level of electric demand, expressed in units of
watts, that a utility's generating system must meet.
-
Base Load Unit An electric generating plant, or generating unit within a plant, that is
normally operated continuously to meet the system's base load, or
minimum constant level of electric demand.
Capacity A measure of the amount of service for which a system or system
- component is rated.
Capacity Factor A measure of the degree to which the capacity of a generating unit or
utility is being used during a certain period oftime.
City gate The site where a distribution utility company receives and measures gas
/Tom a pipeline company.
Coincident (Peak)
Demand The level of demand of an electric or natural gas customer or customer
class at the time of the electric or gas system's peak demand.
Cost-of-Service The total costs incurred by a utility in providing utility service.
Customer Classes Groups of utility customers with similar characteristics that are classified
together for the setting and applying of electric and natural gas rates and
for other ratemaking and fmancial reporting purposes.
Degree Day A unit of measure used to express the extent to which temperatures vary
/Tom a specific reference temperature during a given time period.
5
---
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
Demand The amount of energy drawn by customers at a specific time.
Direct Access The ability of a retail customer to purchase electricity directly /Tom the
wholesale market rather than through a local distribution utility.
Distributed -.
Generation Small scale generation located at or near the point of end use.
Distribution The delivery of electricity to the retail customer's home or business -
through low voltage distribution lines.
Energy A measure of the quantity of units of electricity used in a give time period, -
measured in kilowatt-hours.
Heat Rate A measure of the amount of thermal energy needed to generate a given -
amount of electric energy.
Load The amount of power carried by a utility system, or the amount of power
consumed by an electric device, at a specified time.
Load Factor A ratio that indicates the amount of variability in electric demand for a -
specific period of time.
Load Profile An allocation of electricity usage to discrete time intervals over a period of
time, based on individual customer data or averages for similar customers.
Used to estimate electric supply requirements and determine the cost of
service to a customer.
Load Shape The graphed pattern of a utility's load or customer's demand for energy
over a period of time.
Local Distribution
Company A public utility that delivers natural gas to end-use customers through its
own distribution system.
Peak Load The maximum amount of energy carried by a utility system during a
specific time period. Peak load determines the required system capacity.
Peaking Unit An electric generating plant, or generating unit within a plant, operated to
meet maximum (peak) demand or to fill emergency requirements,
6
---
APPENDIX A
ABBREVIATIONS, ACRONYMS
GLOSSARY OF TERMS
.-
Rate Design The process of setting prices for utility service at levels that permit a
utility to collect the total revenues allowed by regulators in a manner that
meets current regulatory and legislative policy goals.
Rate of Return The amount earned, or allowed to be earned, by a utility, expressed as a
percentage of the utility's rate base.
Rate Structure The combination of the rate components and rate designs a utility uses to
bill its various classes of customers for the electric, natural gas, or other
utility service provided to them.
Revenue
Requirement The total amount of money a utility must collect /Tom its customers to pay
all operating and capital costs, including a fair return on investment.
Substation An assemblage of equipment that switches, changes, or regulates voltage
in the electric transmission and distribution system,
-
Transformer A device that changes the voltage of alternating current electricity.
7
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
-
-
-
-
APPENDIX B
REGULA TORY AND
LEGISLATIVE ISSUES
8
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
- TABLE OF CONTENTS
Page
- 1. REGULATORY AND LEGISLATIVE ISSUES..................................... 11
A. Historical Perspective......... .................................... ......... ...... 11
-
B. SanDiegoRegion................................................................ 14
C. Legal and Regulatory Framework... ......... ...... ............... ............. 15
1. California Regulatory Framework... ............... ................... 15
-
a. Legislation........................................................ 15
- b. Public Utilities Commission Regulation,.,......... ...,..... 18
c. California Energy Commission and other
- State and Federal Environmental Requirements...,........ 21
2. Federal Regulatory Framework......... ............ .......,........... 22
a. Federal Energy Regulatory Commission.........,........... 22
- b. Participating Transmission Owners under the CAISO
Tariff...........................................................,... 24
- c. Pending Legislative and Regulatory Proposals..............., 24
- (I) Federal Energy Regulatory Commission Standard
Market Design, Docket No. RMOI-12-000...... ... 25
- (2) California Legislation.................................... 26
II. EXERCISE OF THE POWER OF EMINENT DOMAIN................,.............28
A. Eminent Domain Proceedings...... .................. ..............................28
B, Valuation Methodologies.................. ........,... ....... ...,... ............. 30
1. Original Cost...... ..................... ......"...........,................. 30
9
-
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES -
2. Capitalized Earnings Method..................... ........................ 31 -
3. Replacement Cost New................................................... 31
-
4. Percent Condition............ ...... ....................................... 31
C. Cost Exposure........................................................................32 -
1. AcquisitionCosts........................,.,............................... 32
...
2. Severance Costs.......................................... ..................32
3. Interconnection Costs............ ..........................................33 -
4. California Cost Responsibility Surcharge for Departing Load...... 35
-
a. Direct Access Cost Responsibility Surcharge...... ............37
b. Calculation of the DA CRS Components..................... 38 -
(I) DWR Bond Costs....................................... 38
(2) DWRPowerCharges........""........................ 38
(3) Utility Retained Generation (URG) Costs............ 38
(4) DA CRS Cap............................................. 39
(5) AB 265 Under-collection.........................,.... 39
6. Federal Stranded .Costs..............................................,... 39 -
10
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
I. REGULATORY AND LEGISLATIVE ISSUES
The purpose of this section of the Report is to describe the current legal,
- regulatory, political and economic framework under which an MEU would operate, the
challenges and opportunities presented thereby, and opportunities to overcome or take advantage
of such challenges and opportunities.
A. Historical Perspective
Since the passage of the Energy Policy Act amendments to the Federal Power Act
in 19921 and the adoption ofFERC Order Nos. 8882 and 8893 in 1996 and 1997 respectively, the
FERC has attempted to develop the foundation necessary to develop competitive bulk power
markets in the United States. The foundation consisted of implementing non-discriminatory
open access transmission services by public utilities and stranded cost recovery rules that would
provide a fair transition to competitive markets.
With these changes in Federal laws and regulatory policy, various States have
responded with various types of refonn, some including major utility refonns, deregulation and
the development of Independent System Operators to consolidate the operation of state and
regional transmission grids.
Efforts to restructure the California electric industry began in 1994 in response to
high electric rates.4 Following extended hearings, negotiations and proceedings before the CPUC
which resulted in a restructuring Order issued in December 1995,5 the California Legislature
enacted Assembly Bill 1890 (AB 1890) in September, 1996. The principle factors of AB 1890
Energy Policy Act, 42 U.S.c. § 13201 et seq. (2002).
2 See Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services
by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No.
888,61 FR 21,540 (May 10, 1996), FERC Slats. & Regs.1[ 31,036 (1996)(Order No. 888), order on reh'g,
Order No. 888-A, 62 FR 12,274 (March 14, 1997), FERC Slats. & Regs. 1[ 31,048 (1997)(Order No. 888-
A), order on reh'g, Order No. 888-B, 81 FERC 1[ 61,248 (1997), order on rM:g, Order No. 888-C, 82
FERC 1[ 61,046 (1998), aff'd in Dart sub nom. Transmission Access Policv Study GraUD V. FERC, 224
F.2d 667 (D.c. Cir. 2000), cert !!l1I11ted sub nom.. New York v. FERC, 531 U.S. 1189 (2001)
J Open Access Same-Time Infonnation System (Fonnerly Real-Time Infonnation Networks) and Standards
of Conduct, Order No. 889,61 FR 21,737 (May 10, 1996), FERC Slats. & Regs.1[ 31,035 (1996), order on
~, Order No. 889-A, 62 FR 12,484 (March 14, 1997), FERC Slats. & Regs.1[ 31,049 (1997), order on
rM:g, Order No 889-B, 81 FERC 1[ 61,253 (1997).
4 At the time, California's electric rates were almost twice the national average at 10 to II cents per kilowatt
hour.
, See CPUC Decision D. 95-12-063 (December 20, 1995), modified by 0.96-01-009 (January 10, 1996) and
0.96-03-022,166 PUR 4"' I.
11
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
included (I) creation of the California Independent System Operator Corporation (CAISO) and
the California Power Exchange (PX) and simultaneous initiation of direct access; (2) creation of -.
the California Electricity Oversight Board; (3) a competitive transition charge (CTC) for the
recovery of the Investor-Owned Utility's (IOU) stranded costs; and (4) a 10% rate reduction for
residential and small customers and a rate freeze for all retail customers. Among other things,
AB 1890 mandated that the investor-owned utilities in the State: (I) turn over the operational
control of their transmission facilities to the CAISO; (2) divest at least half of their fossil fuel
fired generating plants; and (3) buy and sell through the PX.
In March 1997, the CAISO and PX submitted filings with the FERC to implement
the requirements of AB 1890 and, after significant revisions of the CAISO and PX Tariffs as -
required by the FERC's July 30, 1997 Order, the ISO and PX were pennitted to commence
operations on March 31, 1998, pursuant to the Commission's Order dated October 30, 1997.6
Immediately following the commencement of operations by the ISO and PX,
prices for power and ancillary service began to spike. The ISO sought and obtained the
imposition of price caps as a solution to the volatility and thinness in the market for ancillary
services, The FERC authorized price caps, but required the ISO to eliminate the price caps by
November 15,1999. In September 1999, the ISO filed proposed tariff revisions to extend and
increase its price caps. The FERC approved the proposal and pennitted the price caps to remain
in effect through November 15,2000.
The electricity market in California remained both chaotic and volatile despite
numerous amendments to the ISO and PX Tariffs and other attempts by the ISO and PX to
stabilize the market. These efforts notwithstanding, electricity prices in California jumped
dramatically in the summer of 2000 and affected all markets run by the PX and the ISO. High
temperatures and generation outages led the ISO to declare numerous (39) system emergencies,
These efforts did not prevent rolling blackouts in Northern California or the continuation of
increases in both electric and gas prices. 7
During the summer of 2000, the cost of electricity imports began to increase,
particularly gas costs which resulted in unprecedented increases in the cost of operating existing
gas fired units,
Because the retail rate /Teeze imposed in SDG&E's service area by AB 1890
ended in 1999, the very high wholesale prices were passed through to the utility's retail
6 Pacific Gas and Electric Co. et aI, 81 FERC ~ 61,122 (1997).
7 Based on subsequent disclosures in numerous ongoing proceedings before the FERC, certain generators
and suppliers of electricity, gas and ancillary services "gamed" the ISO and PX markets which exacerbated
the problems already faced by participants in the California electricity markets. Efforts are currently under
way to recover some of the profits which were received by those that "gamed" the California energy
markets in 2000 and 200 I.
12
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
customers, resulting in electric bills that were up to 200-300 percent higher than in the previous
year.
While the price /Teeze applicable to customers of Pacific Gas and Electric
- Company (PG&E) and Southern California Edison Company (SCE) remained in effect until
March 31, 2002, both utilities were required to absorb enormous shortfalls that could not be
recovered in retail rates. As a result, PG&E was driven into bankruptcy and is still seeking
approval of a plan to emerge /Tom bankruptcy. SCE was driven to the edge of bankruptcy, but
instead entered into a settlement with the CPUC that kept the company /Tom filing for
bankruptcy. That settlement is still the topic of appeal in the State's Supreme Court.
While electricity and gas markets have stabilized somewhat since the 2000-2001
period, no long-term solution to high electricity and gas prices has emerged. The CAISO has
now filed some fifty-nine (59) amendments to the CAISO Tariff seeking reforms which would
further stabilize the markets served by the CAISO. The PX, after two years of disappointing
results, was also driven to bankruptcy and was dismantled in 2002 after the requirement that the
IOUs purchase and sell power through the PX was terminated by the FERC.
It is relevant to point out that, while all electric and gas customers in California
have suffered dramatic increases in electric rates since the implementation of AB 1890, the
customers of publicly owned electric systems have suffered less and some have barely felt the
volatility of the market. The fact that publicly owned utilities have fared much better during
restructuring than the IOUs is attributable to the following factors:
(I) Publicly owned utilities were allowed, but not required by AB 1890 to
participate in either the CAISO or the PX markets;
(2) Publicly owned electric utilities were encouraged by the California
Legislature, but not required by the terms of AB 1890, to turn the
operational control of their transmission facilities and rights over to the
CAISO;
(3) AB 1890 did not mandate, and the FERC did not order the abrogation of
the existing contracts and service arrangements held by publicly owned
electric utilities which entitled them to long-term, reliable and relatively
low-cost power and energy. To the contrary, the FERC orders issued in
the restructuring proceedings have consistently preserved the integrity of
existing contracts of publicly owned utilities, regardless of their term; and
(4) AB 1890 and related FERC orders have not required publicly owned
utilities owning transmission assets to become Participating Transmission
13
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES -
Owners (PTOs) under the CAISO Tariff, although they have the right to
become a PTO at their option.
It is clearly the goal of the California Legislature and the FERC to eventually
require all utilities, both public and private, to participate in all markets on equal terms. Thus far -.
the CAISO has failed to demonstrate that participation in the CAISO markets would result in any
economic benefit to publicly owned electric utilities or their customers. Until that happens,
publicly owned electric utilities will continue to avoid, where possible, the imposition of costs or
obligations resulting /Tom full participation in the CAISO markets.
It is in this context that Chula Vista must weigh the alternatives for developing
and implementing a Chula Vista MEU. By all standards, the California restructuring experiment
under AB 1890 has been a miserable failure. Efforts to find viable long-term solutions which
will stabilize markets and bring both electric and gas costs down to reasonable levels are
continuing, but the market remains broken. The CAISO just filed Amendment No. 59 to the
CAISO Tariff and is mired in litigation over past amendments and practices. Each of the
investor-owned utilities is seeking increases in various rates for scheduling coordinator services,
ancillary services, interconnection charges and other services provided to their wholesale
customers or to the CAISO. The IOUs have also filed a number of cases to determine the extent
to which they can pass on to their customers the charges imposed on them by the CAISO. On
top of this, almost all participants in the California energy market are involved, directly or
indirectly, in a spate of refund cases in which the California Attorney General and other
California parties claim overcharges for electric service provided in 2000 and 2001.
Undoubtedly, the foregoing factors are the very root causes for Chula Vista to
examine its alternatives to continuing its dependency on SDG&E for full requirements electric
and gas service. At the same time, however, these factors must be carefully considered by Chula
Vista in the context of its feasibility analysis to the end that it can /Tee the City of its dependency
on the current paradigm for providing utility services and, at the same time, avoid the pitfalls
which may occur if Chula Vista becomes an active participant in the California energy markets.
B. San Diego Region
The impacts of California's 1996 restructuring legislation (AB 1890) were
particularly devastating to customers of SDG&E. Pursuant to AB 1890, retail electric rates were
"/Tozen" at levels above SDG&E's actual costs until March 31, 2002, or such earlier time as
SDG&E had recovered its uneconomic, or "stranded" costs of generation assets. Ironically, due
to SDG&E's relatively low stranded costs, the rate /Teeze originally designed to protect
customers ended during the early months of the electricity crisis, leaving customers exposed to
the volatility of the market, resulting in retail rates rising to unprecedented levels.
14
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
In response to this localized rate crisis, the California Legislature enacted
emergency legislation to address the "severe economic hardship" to SDG&E ratepayers "because
of unprecedented bill volatility and extraordinarily high rate levels." AB 265 (Stats, 2000, Ch.
328; Cal. Pub. Uti!. Code § 332.1) required the CPUC to establish, retroactive to June 1,2000 a
rate ceiling of $.065 on the energy component of electric bills for residential, small commercial,
and street lighting customers8 of SDG&E. The rate ceiling was to remain in effect until
December 31, 2002. The legislation also required an accounting procedure to track and recover
the undercollections caused by the rate ceiling.
In subsequent applications filed with the CPUC, SDG&E sought approval of a
surcharge to recover the undercollections. Due to a settlement of litigation with the CPUC and
other factors which were expected to eliminate the undercollection by the end of 2003, the
Commission denied the request for a surcharge in Decision 02-12-064.
C. Legal and Regulatory Framework
- For the most part, MEUs are self-regulated under both the laws of the State of
California and Federal laws. Neither the CPUC nor the FERC have general rate and service
jurisdiction over the activities, transactions and rates of publicly-owned and operated utilities.
That said, the restructuring of the California electric industry and changes in
F ederallaws and regulations have resulted in the extension of some regulatory authority, at both
the State and Federal level, over certain aspects of the operation of ME Us. In deciding whether
to form and operate a MEU, and in selecting the type oflegal structure to be used to accomplish
this objective, it is important for cognizant officials of Chula Vista to understand the legal and
regulatory framework with respect to MEU formation and operation.
1. California Regulatory Framework
a. Legislation
Prior to the enactment of AB 1890 in 1996, the California Legislature rarely
found it necessary to dictate how municipally owned utilities or other non-investor owned
utilities operated. The investor owned utilities, with their exclusive service territories, were
closely regulated by the CPUC, and the publicly owned uti1iûes, having no intent to expand their
service territories beyond their own borders, were regulated by their own elected boards,
councils, and commissions. The drive to introduce competition into the electric industry altered
the regulatory landscape in significant ways. Non-utility generators, marketers, and brokers
were permitted to sell power at retail, utilizing the existing distribution systems of the existing
8 The CPUC was also required to establish a voluntary program for large commercial, agricultural, and
industrial customers who bought energy from SDG&E to pay at the same $.065 rate with a true-up after a
year.
15
...
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
utilities. New entities were created to establish a trading market for electricity and to control
essential transmission facilities under FERC jurisdiction. The Califomia Legislature and the -.
CPUC struggled with the notion oflocal control of publicly owned utility systems.
As part of the California electric industry restructuring, the California Legislature
did enact a number of statutory requirements, some mandatory and some discretionary, which
now apply to "each local publicly owned electric utility" operating within the State. The term
"local publicly owned electric utility" is a term defined in Cal. Pub. Uti!. Code § 9404 (d) as
follows:
(d) "Local publicly owned electric utility" as used in this division
means a municipality or municipal corporation operating as a
"public utility" furnishing electric service as provided in Section
10001, a municipal utility district furnishing electric service
formed pursuant to Division 6 (commencing with Section 11501),
a public utility district furnishing electric services formed pursuant
to the Public Utility District Act set forth in Division 7
(commencing with Section 15501), an irrigation district furnishing
electric services formed pursuant to the Irrigation District Law set
forth in Division II (commencing with Section 20500) of the
Water Code, or a joint powers authority that includes one or more
of these agencies and that owns generation or transmission
facilities, or furnishes electric services over its own or its
member's electric distribution system.
Thus, the term "local publicly owned electric utility" would apply to any legal structure
discussed in this Report and under which Chula Vista could legally form and operate a MEU
under California law.
Several statutes applicable to investor owned utilities as well as local publicly
owned utilities were contained in the primary restructuring legislation, AB 1890. One such
measure mandates surcharges on electricity usage to fund programs considered to be in the
public interest. Cal. Pub. Uti!. Code § 385 requires each local publicly owned electric utility to
establish a nonbypassable, usage based charge (commonly referred to as a "public goods" or
"public benefits" charge) on local distribution service to fund investment in: (I) cost-effective
demand-side management services to promote energy efficiency and energy conservation; (2)
new investment in renewable energy resources and technologies; (3) research, development and
demonstration programs to advance science or technology; and/or (4) services provided for low-
income electricity customers (e.g., energy efficiency services, education, weatherization and rate
discounts). The amount of the public benefits charge (on a percent of revenue basis) is the result
of a complex formula set out in § 385, but must be "not less than the lowest expenditure level of
the three largest electrical corporations in California." Currently, the public benefits charge
16
-- .. "'._---_._-
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
percentage for local publicly owned utilities is 2.85%. The selection of public benefit programs
to be funded by the charge is at the discretion of the local publicly owned utility, but must
conform to the statutory requirements of § 385. Other legislation applicable to local publicly
owned utilities involves consumer protection programs, and addresses such issues as low-income
ratepayer assistance programs, weatherization programs, public reporting of revenues transferred
to a city's general fund, and development of renewable resources. Limited only by the
categories of "public benefits" set forth in the Code, municipal utilities have complete control
over the funds collected, and can use 100% of those funds within the community. Public Goods
Funds collected from local ratepayers by the investor owned utilities can be used on any number
of programs approved by the utility, and may never be expended within the community in which
they are collected.
One of the more controversial discretionary measures involves the extent to which
local publicly owned utilities should commit control of their transmission facilities to the
CAISO. Cal Pub. Uti!. Code § 9600 (under which AB 1890 is included) is non-mandatory with
respect to the transmission facilities of publicly owned electric utilities, although parallel Code
provisions applicable to the State's three investor-owned utilities mandated that those utilities
turn over the operational control of their transmission facilities to the CAISO. On March 31,
1998, PG&E, SCE and SDG&E transferred the operational control of their transmission systems
to the CAISO. More recently, the Cities ofVemon, Anaheim, Azusa, Banning and Riverside,
have become Participating Transmission Owners (PTO) and have transferred the operational
control of their transmission facilities and rights to the CAISO.
Section 9600 of the Public Utilities Code also sets forth the guidelines for
establishing access charge rates and rates for transmission service, but recognizes that the FERC
has jurisdiction to approve transmission rates for investor-owned utilities and the CAISO. FERC
has also asserted indirect regulatory authority over the rates charged by publicly owned electric
utilities that become PTOs by approving the terms and conditions of the Participating
Transmission Owner Agreement between the CAISO and the PTO. Currently, the terms and
conditions of the agreements between the CAISO and the publicly owned electric utilities that
have become PTOs are still in litigation before the FERc.
AB 1890 made direct access mandatory for the state's investor owned utilities,
but optional for local publicly owned utilities. Cal. Pub. Uti!. Code § 9602 requires that the local
regulatory body of each publicly owned electric utility shall, after public hearing, determine
whether it will authorize direct transactions between electric suppliers and end use customers.
However, if a program of direct access is authorized, CaI, Pub. Uti!. Code § 9601 requires that
any utility or other energy service provider that undertakes to provide partial or full requirements
electric service to customers of a local publicly owned electric utility must ensure that such
customers pay that utility a nonbypassable generation-related severance fee or transition charge
established by the regulatory body for that utility.
17
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
The parallel requirement in § 9601 requires any local publicly owned utility that
undertakes to provide full or partial requirements electric service to the customers of an investor- -.
owned utility ensure that such customers commit to pay a nonbypassable generation-related
transition charge to the investor-owned utility. This provision would apply to the City of Chula
Vista if it undertakes, through its MEU, to provide full or partial requirements electric service to
the customers of SDG&E through a direct access program.
b. Public Utilities Commission Regulation
As discussed earlier in this Report, case law supports the constitutional and
statutory rule that local publicly owned utilities are not subject to the jurisdiction of the CPUC in
the absence of a legislative grant of authority. As a rule, the CPUC has respected this lirnitation.
What many municipal utilities considered a departure /Tom this practice occurred in 1998 when,
in a controversial decision, the CPUC determined that municipal and other publicly owned
utilities were subject to the inspection and maintenance standards for electric distribution
systems set out in the CPUC's General Order 165 (Decision 98-03-036; Rehearing Denied in
Decision 98-10-059).
Of far greater significance to Chula Vista however, is a proceeding currently
ongoing at the CPUC (Rulemaking 02-01-011) in which a decision was issued that would require -.
Chula Vista's MEV customers to pay a surcharge for a variety of costs arising from restructuring
and /Tom the California energy crisis (Decision 03-07-028; Limited Rehearing Granted in
Decision 03-08-076 (collectively, the MDL Decisions)).
When the legislature enacted Assembly Bill I /Tom the First Extraordinary
Session (AB IX) in January 2001, authorizing the California Department of Water Resources
(DWR) to begin purchasing electricity for the customers of the state's IOUs, it also directed the
CPUC to suspend the state's direct access program, which the Commission did on September 20,
2001. What ensued was a protracted proceeding at the CPUC to determine if direct access
customers that left IOU service after February 1,2001 should be liable for any portion of the cost
of power that was ostensibly purchased on their behalf by DWR. An argument was raised that, if
these customers were able to avoid liability for at least a portion of the costs incurred by DWR,
then those same costs would be shifted to existing bundled service customers. The Commission
determined that direct access customers who received any power /Tom one of the three IOVs
after February I, 2001 were liable for a cost responsibility surcharge (CRS or Exit Fees), to
cover the cost of (I) DWR's bond charges (which paid for power already purchased); (2) DWR's
going forward costs to pay for long tenn contracts entered into by DWR; (3) a "tail" or residual
competition transition charge (Tail CTC); and (4) for customers within the service territory of
Southern California Edison, an historical procurement charge to cover SCE's past uncollected
procurement costs,
18
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
During the course of the proceeding, the issue of Municipal Departing Load
(MDL) was raised. Municipal departing load is generally considered to be comprised of electric
service customers that were formerly customers of an IOU, but which became customers of a
publicly owned utility by way of an annexation of land or by formation of a new municipal
utility. Municipal departing load also consists of new customers being served by a publicly
owned utility, which were located in the former service territory of an IOU. On March 29, 2002,
the assigned administrative law judge issued a ruling noting that separate hearings would be held
to determine whether MDL would be liable for any CRS. Testimony was submitted, hearings
were held, and the Commission was briefed. On July 10, 2003, the CPUC issued D.03-07-028,
Order Adopting Cost Responsibility Surcharge (CRS) Mechanisms for Municipal Departing
Load (Decision), which imposes the CRS on Municipal Departing Load.
The Decision was adopted by a three to two vote. Commission President Peevey
and Commissioner Kennedy both voted against the Decision in light of Senate Concurrent
Resolution (SCR) 39, also passed on July 10,2003 by a unanimous vote (with Senator Bowen
abstaining). SCR 39 provides "that the Legislature intends that any municipal utility serving
customers in newly developed areas shall be exempt from any exit fees, as long as the municipal
utility was formed before June 1, 2003, and demonstrates that it has expended in good faith
significant amounts of money and resources towards creation of a municipal utility that will
serve customers in newly developed areas. . . ." While SCR 39 does not have the force of law
and has no binding authority on the Commission, it did show the CPUC that the California
Legislature does not support applying the CRS to Greenfield load for new municipal utilities.
However, since the Assembly never took up this issue, the import of SCR 39 was largely lost,
and the applications for rehearing of 0.03-07-028 were, for the most part, denied by the CPUC
in Decision 03-08-076, which was issued on August 21, 2003.
Treatment of "Existing Utilities" under the MDL Decisions:
The Decision provides no exemptions for existing MDL (i.e., load that a publicly
owned utility acquires /Tom an investor owned utility by virtue of an annexation). Any newly
acquired territory that includes facilities already interconnected to the IOU's facilities would be
subject to the CRS.
For purpose of applying the CRS, MDL does not include new load of an existing
publicly owned utility (those publicly owned utilities established and providing electricity to
retail end-use customers on or before February 1,2001) providing electricity within its exclusive
service territory, However, under P.U. Code section 369, "'new load,' for purposes of CRS
recovery, excludes load being met through a direct transaction that does not otherwise require the
use of transmission and distribution facilities owned by the IOU." New municipal load where
the municipal agency is interconnected with and uses the IOU's transmission system, is not
exempted.
19
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
Treatment of New Publiclv Owned Utilities Under the MDL Decisions:
The Decision provides that "new MDL served by a new publicly-owned utility will
be subject to cost responsibility surcharges. The cut-off date will be determined by whether the
publicly-owned utility was established and providing electricity to retail end-use customers on or
before February 1, 200."
The MDL CRS includes all of the following elements:
a. DWR Bond Charge, applied on the same per-kWh basis as adopted for -.
bundled customers pursuant to D.02-12-082, which modified D.02-11-
074, applicable to MDL customers in the IOU service territory as it
existed on February 1,2001.
b. OWR Power Charge, applicable to MDL customers in the IOU service
territory as it existed on February 1,2001
c. Tail CTC covering the components specified in Ca!. Pub. Uti!. §367,
applicable to MDL customers in the IOU service territory as of December -
20,1995.
d. HPC component (for SCE service territory only) applicable to MDL -
customers that departed the IOU service territory after March 29, 2002.
In 0.03-08-076, the CPUC denied the applications for rehearing filed by several --
parties, and further pared back any possible exemption for the application of the CRS to new
Municipal Departing Load. Petitions for Writ of Review were filed with the California Supreme
Court in September 2003 by several parties, including Chula Vista. Since that time, respondent
CPUC and IOUs have filed their replies, but it is unknown when the Supreme Court will act on
the Petitions or if they will be granted.
Accordingly, under the current state of the law, as muddled as it is, Chula Vista
will be subject to the cost responsibility surcharges discussed above once it interconnects with
SDG&E, begins serving load and begins using the transmission system.
20
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
c. California Energy Commission and other State and Federal
Environmental Requirements
An MEU which owns and operates electric generation facilities in the State of
California may, under certain circumstances, be subject to regulation related to environmental
issues by both State and Federal regulatory agencies. In this section, we identify the State and
Federal agencies with jurisdiction over environmental issues associated with new or repowered
electric generation in the Chula Vista area and the threshold size/emissions that trigger their
jurisdiction. This analysis should be refined if and when a decision is made to go forward and
more specifics are provided for the project.
. If the Project involves a thennal power plant with over 50 MW net generating capacity or
modifications that result in a 50 MW or higher increase in generating capacity, the
California Energy Commission (CEC) has exclusive jurisdiction over certifying the site
and related facilities. The CEC is directed by statute to consult with other responsible
local, regional or state agencies and to make a finding regarding whether the project
complies with all applicable laws and ordinances. The most significant of these agencies
are identified below. The CEC, however, has the jurisdiction to override the decisions of
other local, state or regional agencies if certain conditions are met, namely that the
project is needed for public convenience and necessity and there is no more prudent and
feasible means of achieving such public convenience and necessity.
If a plant is below the 50 MW threshold for CEC jurisdiction, the City could undertake a
review of the environmental effects of the project consistent with the California
Environmental Quality Act (CEQA). However, unlike the CEC, the City does not have
exclusive jurisdiction and would have to obtain separate pennitting approvals /Tom the
other agencies involved, such as the San Diego Air Pollution Control District (SDAPCD).
. The SDAPCD would be the primary agency with responsibility over air emissions /Tom a
new plant in the Chula Vista area unless the CEC has jurisdiction. Most significantly, if
annual emissions /Tom a new project exceed 50 tons of NOx or VOCs the plant would
have to obtain offsets or purchase emission reduction credits CERCs); both of which are
in limited supply in the SDAPCD. In the South Bay Repowering option, the existing
(retired) plant may be able to provide offsets. Any ERCs or offsets would need to be
approved by the SDAPCD. Because the SDAPCD has recently submitted a request to
EP A for redesignation as attainment, these requirements may change in the future.
. EP A Region IX and the California Air Resources Board could also be involved in the
review. For example, EPA Region IX has recently revoked the SDAPCD's delegated
authority over Prevention of Significant Deterioration (PSD) requirements. To the extent
that any new plant, for example, exceeds the 100/250 ton PSD thresholds for carbon
monoxide or PMIO, EPA could issue this pennit. We have also heard infonnally /Tom the
21
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
SDAPCD Staff that EPA, despite the revocation of the SDAPCD's authority, has been
willing to infonnally delegate this authority back to the SDAPCD. Depending on the
plant's location, Federal Land Managers (e.g., National Park Service, Forest Service
and/or Fish and Wildlife Service) may be involved regarding the impacts of new
generation on Class I areas.
. A new plant could raise water pennit issues. For example, stonnwater pennits could be
required for the new construction or if the construction involves cooling towers, pennits -
could be required for them. Depending on the issue, the State Water Resources Control
Board, the San Diego Regional Water Quality Control Board and/or EPA Region IX may
be involved.
. Various other local approvals may be required, including approvals for ammonia storage
tanks (if SCR is used), noise or odor regulations, coastal zone compliance or zoning
changes. Many of these may be regulated by the City of Chula Vista. The MEU Study
Team recommends that these issues be addressed if and when a more specific plan is
developed.
2. Federal Regulatory Framework
a. Federal Energy Regulatory Commission
With certain exceptions not relevant to the scope of this feasibility analysis, the -
regulation of "Public Utilities" is vested in the FERC under the Federal Power Act (FPA) (16
USC § 824 et seq.). Section 201(f) of the FPA specifically exempts publicly owned and operated
utilities. That Section provides:
(f) United States, State, political subdivision of a State, or
agency or instrumentality thereof exempt
No provision in this subchapter shall apply to, or be deemed to
include, the United States, a State or any political subdivision of a
State, or any agency, authority, or instrumentality of anyone or
more of the foregoing, or any corporation which is wholly owned,
directly or indirectly, by anyone or more of the foregoing, or any
officer, agency, or employee of any of the foregoing acting as such
in the course of his official duty, unless such provision makes
specific reference thereto.
Thus, if Chula Vista fonns and operates an MEU, it will not be subject to the rate and service
jurisdiction of the FERC.
22
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
That said, the rate and service jurisdiction of the FERC will inevitably impact
Chula Vista and its operations inasmuch as the Chula Vista MEU will be transacting business
with utilities which are subject to the jurisdiction of the FERC (e.g. SDG&E, SCE, PG&E and
the CAISO). The rates for all utility services provided by regulated utilities (e.g, transmission
service, partial or full requirements wholesale electric service and the provision of ancillary
services) are all regulated by the FERC. Thus, to the extent that the Chula Vista MEU transacts
business with any regulated utility, it will be drawn into the Federal regulatory process to the
extent that it wishes to participate to protect its interests or challenge the justness and
reasonableness of any rate or service provided or offered by the regulated utility.
It is also relevant to point out that, under the FERC's Order No. 888, all regulated
utilities must provide access to their transmission facilities. The Chula Vista MEU will be able
to take advantage of the FERC's open access policy in gaining access to transmission facilities of
regulated utilities. Here again, however, the FERC will set the rate for such transmission
service.
To operate its distribution system, a Chula Vista MEU would be required to
establish an interconnection with SDG&E. The FP A, as amended by the Energy Policy Act of
1992, makes provision for establishing an interconnection with a regulated utility in the event
that the utility refuses to agree to an interconnection. (See FPA Sections 210-211, 16, USC §§
824 i and D.
Under these provisions, the Chula Vista MEU would be required to file a good
faith request with the FERC for an interconnection of their respective facilities with SDG&E.
SDG&E would be required to respond to the request within sixty (60) days by submitting a
proposed interconnection agreement. In the event that the parties cannot agree on the tenns and
conditions of the interconnection, Chula Vista would have the right to invoke the FERC's
jurisdiction to establish the tenns and conditions of the interconnection agreement and to
detennine what costs Chula Vista would be required to pay to SDG&E for the modification of
the SDG&E system to accommodate the Chula Vista interconnection. The FERC, as part of this
process, may also require the payment of SDG&E's stranded generation costs which result nom
the establishment of a Chula Vista MEU and the transfer of SDG&E's customers to Chula
Vista.9
In all likelihood, if Chula Vista takes over, by acquisition or condemnation of
SDG&E's electric distribution system, it will be required to establish more than one point of
interconnection with SDG&E and will be required to pay any costs of reconfiguring SDG&E's
system to allow it to continue to provide service to its own customers who are currently served
over the existing distribution system. The latter costs are known as "severance" damages which
9 The cost implications involved in establishing an interconnection with SDG&E under FERC rules and
regulations are discussed in Appendix B, Section 1l.c.3 at 33-35.
23
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES -
are nonnally awarded in the condemnation proceedings if the parties cannot agree on the
necessary system modifications and the related cost responsibility for those modifications.
b. Participating Transmission Owners under the CAISO Tariff
If a MEU acquires and operates transmission facilities or transmission rights, it
has the right to become a PTO under the CAISO Tariff,
There are distinct advantages and disadvantages to becoming a PTO under the
CAISO Tariff, and there is a myriad of potential costs and charges that may be imposed on the
MEU in transactions involving the use of the CAISO controlled transmission grid,
An entity choosing to become a PTO will be subject to numerous requirements
under the CAISO Tariff. It is beyond the scope of this feasibility analysis to identify and analyze -.
all potential obligations and costs associated with becoming a PTO. We have, nevertheless,
identified the principle costs associated with becoming a PTO under the CAISO's Tariff in
Appendix C hereto. See Appendix C, Section II.D. at 83-84.
Of the approximately 37 publicly owned utility systems and agencies in
California, only the Cities of Vernon, Azusa, Anaheim, Banning and Riverside have elected to
become PTOs.
In the event that Chula Vista elects to acquire and operate transmission facilities
or acquires transmission rights, this option should be considered, possibly in the implementation
phase of the Chula Vista feasibility analysis,
c. Pending Legislative and Regulatory Proposals
While still pending and in various stages of litigation or legislative consideration,
there are several legislative and regulatory proposals which could, in the near tenn, impact the
operation of a Chula Vista MEU or have a long-range effect on its cost of providing electric
service and operating its utility system.
The following regulatory and legislative proposals are worth noting in the context
of detennining the kind of utility structure Chula Vista should develop for its MEU:
24
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
(1) Federal Energy Regulatory Commission Standard
Market Design, Docket No. RMOI-12-000
On July 31, 2002, FERC issued a proposed rule to remedy undue discrimination
- and establish a "standard market design" (SMD) for wholesale energy markets under which the
FERC, among other things, would provide for:
. Public utility transmission facilities to be operated by "Independent Transmission
Providers;"
. Locational marginal pricing (LMP), a market-based rate method for congestion
management;
. Tradable Financial Transmission Rights (also called Congestion Revenue Rights or
CRRs) as a means to lock in a fixed price for transmission;
. Procedures to monitor and mitigate market power;
. Procedures to assure, on a long-tenn regional basis, that there are adequate transmission,
- generation and demand-side resources;
. Access charges to recover embedded transmission costs that would be a demand charge
billed on a customer's load ratio share of the transmission provider's cost, and would be
- paid by any entity taking power off the grid;
. Public utilities that operate day-ahead and real-time energy markets and transmission
systems must be independent of market participants;
. Standards for real-time and day-ahead energy markets;
. A new transmission pricing policy based in part on "participant funding;"
. A fonnal role for state representatives to participate in decision-making processes of
-- regional transmission organizations or other regional security and reliability entities; and
. Explicit obligations in the pro fonna tariff for transmission providers and customers to
comply with standards to ensure system security and reliability.
On April 28, 2003, FERC issued a SMD White Paper in which it attempted to
clarify its SMD proposal. The White Paper, while not compromising the core elements of the
SMD model, including some fonn of locational pricing, promises greater regional flexibility, a
fonnal role for the states, and a slower pace for SMD implementation.
Regardless of the fonn in which SMD is ultimately adopted or implemented, it
will likely continue to drive the FERC's decisions on issues such as energy market design,
market power, regional transmission organizations, rates and tenns of transmission service,
transparency, generation and transmission infrastructure, and state-federal relations.
25
_. ...-.. . -------------------.---.---..----
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
(2) Calüornia Legislation
--
Several California Senate and Assembly bills have been introduced in the past year that
may alter the findings and recommendations included in this Report and affect the operations of
a publicly owned utility. None of these bills has been adopted, but all remain active. --
. Senate Bill No. 888 (Dunn) (SB 888): Also known as the "Repeal of Electricity
Deregulation Act of 2003," SB 888 would make wholesale changes to the primary
restructuring legislation (AB 1890), including the provisions related to direct access.
The bill failed in the Assembly's Utilities and Commerce Committee on July 20,
2003, making it a two-year bill, and unless it is subject to a waiver of the Rules, it
cannot be heard again until January 2004.
. Senate Bill No. 119 (Morrow) (SB 119): Last amended in April 2003, SB 119 is
intended to permit the CAISO to more closely monitor the wholesale electric market.
The bill would require a local publicly owned electric utility that sells or purchases
wholesale electric energy or wholesale electric capacity in the state to provide certain
sales transaction information to the CAISO. The bill would require a local publicly
owned electric utility that owns transmission rights in the state to provide to the
CAISO certain information regarding those rights. The bill would authorize the
Attorney General to obtain /Tom the CAISO that transactional and transmission
information regarding the market activities of electrical corporations and any other
market participants. Additionally, subject to certain restrictions, the bill would
authorize the CAISO and the Attorney General to convey the information to another
state agency, and would authorize the Attorney General or other state agency in
possession of the information to convey the information to a federal govemment
agency or a federally regulated entity that does not sell or purchase electric energy or
capacity at wholesale. The new duties for local publicly owned electric utilities
included in this bill would impose a state-mandated local program.
. Senate Bill No. 697 (Soto) (SB 697): Existing law requires a community choice
aggregator to file an implementation plan with the CPUC in order for it to determine
a cost-recovery mechanism to be imposed on the community choice aggregator to
prevent a shifting of costs to an electrical corporation's bundled customers. SB 697
would require the CPUC, upon the filing of a petition or other appropriate procedure
determined by the CPUC, and upon meeting of certain conditions, to establish
separate distribution service rates and charges by an electrical corporation, for
electricity, /Tom an eligible renewable electricity generation source that is supplied to
end use customers by an electric service provider pursuant to an implementation plan
with a community choice aggregator, where the electricity is transported within a
single local distribution system. The separate distribution charge would, to the extent
permitted by federal law, avoid charges for transmission services and would specify
26
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
how any applicable transmission charges would be allocated. The separate
distribution charge would pass on any distribution system cost savings resulting /Tom
the development of distributed energy resources to the end use customer of the
community choice aggregator. The bill would further limit the imposition of fees and
charges by the CAISO.
. Assembly Bill 816 (Reyes) (AB 816): AB 816, as introduced, included specific
language confinning the applicability of a cost responsibility surcharge on Municipal
Departing Load, specifically new load located in previously undeveloped areas. The
bill also contained an unrelated provision resurrecting direct access. Due to
competing bills presented in the Senate, AB 816 was essentially rewritten several
times, with the last draft deferring to the CPUC on the issue of application of the CRS
to Municipal Departing Load, so long as the CPUC adopted a decision that did not
allow customers to escape their "fair share" of the Department of Water Resources
Charges. An apparent victim of politics, AB 816 is now a "two-year bill," meaning
that absent a rule waiver, it cannot be heard again until January 2004.
27
_. ...-..--.---.----............--. -'.-..'---'
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
II. EXERCISE OF THE POWER OF EMINENT DOMAIN
A. Eminent Domain Proceedings
The California Eminent Domain LawlO requires that the condemnation follow the
following basic steps in initiating and prosecuting a condemnation proceeding:
OtTer: The public entity or municipality must make an offer to the property
owners. This offer must reflect what the public entity or municipality believes is
just compensation for the property.
Notice and Hearing: Prior to issuing a resolution of necessity, the public entity
or municipality must provide, to the property owners, notice and opportunity to be
heard with regard to public interest, public good, and the necessity of the
property's acquisition.
Recommendation: After holding the necessary hearing, the governing body of
the public entity (nonnally the legislative body of the public entity) must issue a
written summary of the hearing and a written recommendation as to whether to
adopt the resolution of necessity.
Resolution of Necessity: The governing body may then issue a resolution of
necessity
Final OtTer: At least 30 days prior to trial, the public entity must file its final
. offer and the owner must file its final demand.
Commencement of Eminent Domain Proceeding: After issuance of a resolution
of necessity, the public entity must file a complaint with the superior court.
While Chula Vista would have the legal right to exercise its power of eminent
domain to acquire the utility assets ofSDG&E within the City, it is very important that cognizant
officials of the City are aware of significant provisions of the eminent domain laws which give
the property owner the right to challenge the City's Resolution of Necessity.
Under the Eminent Domain Law the City, in developing its proposed utility
project and its plan to condemn the property of SDG&E, must establish (a) the public interest
and necessity of the project, and (b) demonstrate that the proposed project is compatible with the
greatest public good and least private injury, The City must then attempt to negotiate the
10 Cal. Civ. Proc. Code § 1240.030.
28
APPENDIX B
- REGULATORY AND LEGISLATIVE ISSUES
purchase of the property /Tom the owner for an amount the City believes to be just
compensation," And finally, the City must give SDG&E a reasonable opportunity to appear and
be heard on these matters before Chula Vista initiates an eminent domain proceeding. '2
A City Resolution of Necessity to condemn the property of an electric utility
creates a rebuttable preswnption that the matters set forth in the Resolution of Necessity are
true.13 Significantly, if the City is unable to reach agreement with SDG&E on the acquisition
- and elects to proceed over SDG&E's objection, SDG&E has the right to initiate ajudicial review
of the validity of the matters addressed in the Resolution of Necessity either before or during the
eminent domain proceeding. '4 In that proceeding, SDG&E can object to the condemnation and
attempt to demonstrate that the City has failed to establish that the public interest and necessity
require the proposed project and the taking of the owner's property.'
.- Thus, if SDG&E elects to challenge Chula Vista's project, including the
commendation, Chula Vista must be prepared to demonstrate that the public interest standard has
been met. This can only be accomplished by a showing that the public benefits accruing /Tom the
project (i.e., both (I) measurable fmancial benefits including utility rate reductions to utility
customers in the City and revenue to the City to offset the loss of ftanchise fees and tax
revenues; and (2) additional benefits including local control of utility services, utility price
stability, enhanced utility reliability and increased opportunity for economic development in the
City) are sufficient to meet the public interest standard and to show that the public interest is best
served by allowing the project to proceed.
Chula Vista's success in any proceeding initiated to challenge the Resolution of
Necessity will depend heavily on the strength of the feasibility study upon which the City relies
in determining to proceed with condemnation. It is the opinion of the MEU Study Team that
Chula Vista's chances of meeting the public interest standard will be greatly enhanced if, before
electing to acquire the SDG&E distribution system, the City successfully initiates both
Greenfield and CCA programs and can show both a history of successful development and
management of these projects and positive financial benefits flowing /Tom the City's projects.
Asswning that Chula Vista is successful in overcoming any threshold challenge to
the Resolution of Necessity, it may proceed with the condemnation and, at the time of filing the
complaint or at any time thereafter but prior to entry of judgment, the City may apply ex parte to
the court for an order for possession pursuant to Cal. Civ. Proc. Code § 1255.410. The court will
II Cal. Govt. Code § 7267.2.
12 Cal. Civ. Proc. Code § 1245.235.
13 Cal. Civ. Proc. Code § 1245.250.
14 Cal. Civ. Proc. Code § 1245.255.
l' Cal. Civ. Proc. Code §§ 1250.550 and 1250.370.
29
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APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
authorize the public entity to take possession if it is entitled to take the property by eminent
domain and has deposited with the court the probable amount of compensation as required by
Cal. Civ. Proc. Code § 1255.010 - 1255.080. By taking such possession, the condemnor does
not waive the right to appeal the judgment.
-
The acquiring public entity or municipality may elect to file a petition with the
CPUC to request the CPUC to detennine just compensation and certify the award to the superior
court. Alternatively, the acquiring public entity or municipality may elect to allow the superior -
court to determine just compensation. Given the CPUC's recent decisions which exhibit
antipathy towards unregulated publicly-owned utilities, it is the opinion of the MEU Study Team
that Chula Vista should allow the superior court to detennine just compensation rather than filing
a petition to invoke the jurisdiction of the CPUC.
B. Valuation Methodologies
With respect to standards for detennining 'just compensation," California is a
"fair value" state and the condemnee must receive the "fair value" of the facilities taken in
eminent domain. There are numerous methodologies for detennining "fair value" or 'just
compensation" none of which can be mandated as a single standard under state law. The courts
have unifonnly ruled that all recognized methods of valuation must be considered if presented.
These range ITom depreciated net book value to replacement cost less depreciation methodology.
These two methodologies set the parameters of utility property valuation. The lowest possible
value will likely result /Tom the application of depreciated net book value methodology, while
use of a replacement cost new less depreciation methodology will likely produce the highest
award. While it is impossible to predict, condemnation awards generally reflect values which are
/Tom 1.5 to 2.0 times the net book value, but far less than a value reflecting replacement cost new
less depreciation.
The following are the most widely used methods of valuing utility assets for
purposes of condemnation and arriving at a conclusion as to what is "just compensation."
1. Original Cost
Original Cost is derived ITom the values indicated on a company's accounting
records and presented on its balance sheet. Such value, for regulatory purposes, is the cost of the
asset (plant) when first devoted to public service (original costs), less depreciation, This means
that the value of a company's physical plant, according to its accounting records, is based on the
actual costs incurred to initially install electric facilities (typically years earlier).
30
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
2. Capitalized Earnings Method
.-
The capitalized earnings method for detennining value involves estimating the
current value of future earnings derived /Tom the asset. This method is often used for placing
- value on an on-going business concern, and is based on the premise that the value of the business
is derived solely from its ability to sell its product or services at a profit in future years.
Corporations often buy other corporations or a division of those corporations for a purchase price
detennined on the basis of future earnings. In this case, the sale of electricity could be treated as
a distinct business enterprise resulting in a value based on capitalized earnings. This method
differs /Tom other methods in that it does not reference specific property or assets. Rather, there
is an implicit asswnption that in return for the purchase price, the acquiring entity will receive all
of the assets necessary to achieve the projected level of future earnings. In the case of an electric
distribution utility, these assets include land and land rights, and associated substation and
distribution facilities. The capitalized earnings approach to valuation is dependent on the full
complement of assets being acquired. Accordingly, calculation of a capitalized earnings value
does not include damages resulting from nwnerous factors such as loss of economies of scale.
3. Replacement Cost New
Replacement cost new (RCN), as its name implies, involves calculating the
current cost of replacing the plant in question with another identical plant. Replacement cost
new less depreciation (RCNLD) is RCN less applicable deductions for depreciation. The major
element that is considered in developing the RCNLD method is the cost of replacing the existing
facilities. The calculation involves the following:
. Detennination of original cost values as set forth above
. Adjustment of original cost value to current cost value (RCN)
. Adjustment of replacement costs new to account for depreciation (RCNLD)
RCNLD is a method that adjusts asset values solely by age and ignores existing
maintenance. When used alone, the approach does not explicitly consider the condition of the
existing plant, accounts receivable, or other factors that might increase or reduce the market
value. It is appropriate that some factor be applied to RCN to reflect the actual condition of the
facilities being acquired. This factor is referred to as "percent condition" and is analogous to the
factor a used automobile buyer may apply to the purchase price to reflect the condition and
maintenance perfonned on the automobile.
4. Percent Condition
Percent condition is an approach often used in appraisals. It is particularly
applicable to most electric utility assts. The percent condition of a circuit breaker, for example,
theoretically lies between 0 and 100 percent. A new circuit breaker would represent 100 percent
31
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
condition. A circuit breaker that is 15 years old, but has just undergone a complete overhaul in
which all existing major components were replaced with brand new components would also -
represent a 100 percent condition. Equipment that has failed or is in danger of eminent failure
would be represented as zero percent condition. Generally, equipment that is operating properly
would be rated between 50 and 100 percent condition depending on state of repair and where the
equipment lies in its maintenance cycle. Accordingly, percent condition, when applied to U.S.
electric utility property, results in a value less than RCN, Assuming nonnal maintenance,
RCNLD and percent condition would yield similar valuations.
C. Cost Exposure
In the event that Chula Vista elects to fonn and operate an MDU through the
acquisition or condemnation of SDG&E's electric and/or gas distribution system, it will be
exposed to several classes or types of costs which must be taken into consideration in _.
detennining whether or when to proceed with this undertaking.
1. Acquisition Costs
As discussed in Section IV.F.4.a, if Chula Vista elects to attempt to acquire
SDG&E's distribution system and related utility assets within the City, it must first make an
offer to SDG&E in an amount which Chula Vista believes is just compensation for the property
to be acquired.
In the event that the City and SDG&E cannot agree on the amount of
compensation, the City may initiate condemnation proceedings under the procedures described
above. As previously explained, once Chula Vista files its complaint with the superior court and
initiates the condemnation proceeding, it may elect to have either the superior court or the
California PUC detennine the just compensation for the facilities to be taken.
As discussed in Section IV.F.2.a(l) at 101 and Appendix C,Section ILE.2 at 84-
87, based upon a preliminary analysis of SDG&E's electric distribution system as reflected in
public records, the MEU Study Team has estimated that the acquisition costs for SDG&E's
utility distribution system in Chula Vista would amount to approximately $170,000,000 based on
an RCNLD analysis and national distribution utility standards.
2. Severance Costs
In addition to awarding just compensation for the facilities acquired by Chula
Vista, the superior court also has the jurisdiction to award severance damages to SDG&E for
those costs which are incidental to the taking, but are not attributable to the value of property
taken by the City. For example, if SDG&E maintains offices, or maintenance or other facilities
which are located in Chula Vista but which are not taken by the City, the Company would be
32
. _.._-_._--_.~~_..
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
entitled to severance damages for the unrecovered costs of removing, relocating or closing
facilities which are no longer of use to the Company. Severance damages may also include those
costs which must be incurred by SDG&E to reconfigure its electric system in a manner which
will allow the company to continue to serve its remaining customers who, prior to the
establishment of Chula Vista's new service territory, were served over the same distribution
facilities.16 At this juncture, no detailed separate analysis has been made of the potential
severance costs which may be awarded in the condemnation proceeding. The MEU Study Team
has modeled a preliminary estimate of $10 million for severance and interconnection costs. A
detailed estimate would be made during the Focused Feasibility and Implementation Plan, when
and if Chula Vista elects to proceed with the acquisition of the distribution system.
3. Interconnection Costs
Under Sections 202(b), 210-212 of the FPA, the FERC has the authority to order a
jurisdictional utility to interconnect with another electric system and, if necessary, to provide
transmission service to the requesting party.
Section 202(b) of the FP A provides, in relevant part, that, upon application of any
person engaged in the transmission or sale of electric energy, whenever the Commission:
finds such action necessary or appropriate in the public interest it
may by order direct a public utility (if the Commission finds that
no undue burden will be placed upon such public utility thereby) to
establish physical connection of its transmission facilities with the
facilities of one or more other persons engaged in the transmission
or sale of electric energy, to sell energy to or exchange energy with
such persons: Provided, that the Commission shall have no
authority to compel the enlargement of generating facilities for
such purposes, nor to compel such public utility to sell or exchange
energy when to do so would impair its ability to render adequate
service to its customers.
Section 202(b) also pennits the Commission to prescribe the apportionment of
costs, compensation, tenns and conditions of the parties' arrangements.17
Section 21O(a)(I) of the FPA provides, in relevant part, that upon application of
an electric utility:
16 As discussed in Section II.C.3, below, the FERC has the authority to establish the terms and conditions of
the interconnection between SDG&E and the new Chula Vista distribution system. Thus, much of the
system reconstruction costs will be included in the FERC award for interconnection costs.
17 See Illinois Municipal Electric Agency, 86 FERC 1[61,045, at 61,175 (1999).
33
..~..__..._._.
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
[T]he Commission may issue an order requiring-
(A) the physical connection of ... the transmission facilities of any electric utility,
with the facilities of such applicant.
(B) such action as may be necessary to make effective any physical connection
described in subparagraph (A), which physical connection is ineffective for any
reason, such as inadequate size, poor maintenance, or physical unreliability...
(C) such increase in transmission capacity as may be necessary to carry out the
purposes of any order under subparagraph (A) or (B).
Section 21O(c), however, limits the Commission's ability to order interconnection,
providing that:
No order may be issued by the Commission under Subsection (a) unless the Commission
determines that such order---
(I) is in the public interest,
(2) would-
(A) encourage overall conservation of energy or capital,
(B) optimize the efficiency of use of facilities and resources, or
(C) improve the reliability of any electric utility system or Federal power
marketing agency to which the order applies, and
(3) meets the requirements of Section 212.
Section 2l2(c)(I) provides that, before issuing a [mal order under Section 210, the
Commission shall issue a proposed order setting a reasonable time for the parties to agree to
terms and conditions for carrying out the order, including the apportionment of any
compensation for costs,l8
In addition to these statutory provisions, it is relevant to point out that, pursuant to
FERC Order No. 888, SDG&E has filed with the FERC an Open Access Transmission Tariff
(OATT)19 under which Chula Vista may request any necessary transmission service once it
18 ld at 61,176.
19 Filed July 1997 in FERC Docket No. OA97-664-000.
34
..-..--.-..-.""...-""--...--...-.... ..... .._..~_._.~...._~.
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
establishes its interconnection with SDG&E and compensates SDG&E for all just and reasonable
costs of establishing the interconnection. The cost of transmission service, unless otherwise
agreed to by the parties, will be governed by the terms ofSDG&E OATT. The OATT provides
that the transmission customer must agree to compensate SDG&E for any necessary transmission
facility additions as long as such costs are consistent with FERC policy. See SDG&E OATT,
Section 27.
In the event that SDG&E denies Chula Vista an interconnection and transmission
service under its OATT, Chula Vista can seek that FERC order interconnection pursuant to
Sections 210, 211 and 212 of the Federal Power Act. Chula Vista must demonstrate that the
interconnection is in the public interest, which is shown by demonstrating that the availability of
transmission service enhances competition in power markets by increasing power supply options
of buyers and power sales options of sellers, and ultimately leads to lower costs to consumers.
FERC has further determined that the public interest is served when the interconnecting utility is
fully and fairly compensated for the costs it incurs in connection with the requested
interconnection, and there is no unreasonable impairment of reliability. See Illinois Municipal
Electric Agency v. Illinois Power Co., 86 FERC '1[61,045 at 61,176 (1999) and Sierra Pacific
Power Company, 89 FERC '1[61, 234 at 61,693 (1999).
Section 212(c) establishes the following procedures in processing an application:
(I) upon a determination that the application meets the requirements to support interconnection
under section 210 or 211, FERC will issue a preliminary order directing the interconnecting
utility to interconnect the utility seeking an interconnection; (2) FERC then will set a reasonable
time for apportionment of an compensation of costs:
.If the parties to the proposed interconnection order are able to
agree, [FERC] will issue an order reflecting the agreed-upon terms
and conditions if [FERC] approves of them. If the parties to the
proposed interconnection order are unable to agree within the
allotted time, the Commission will prescribe the apportionment of
costs, compensation, terms, and conditions of interconnection.
Sierra Pacific at 61,694.
4. California Cost Responsibility Surcharge for Departing Load
The California Legislature and the CPUC have attempted to deal with the impact
of the electric industry restructuring in general and, specifically, the rate impact occasioned by
the enactment and implementation of Emergency Legislation20 on January 17, 2001, which
required that the California Department of Water Resources (DWR) assume responsibility for
20 See Senate Bill 7, First Extraordinary Session (SB 7X).
35
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
procuring electricity on behalf of customers of the California investor-owned utilities. On
February 1,2001, the Legislature enacted AB IX, which authorized DWR to continue to meet
the utilities' net short requirements through December 31, 2002.21 Pursuant to this legislation,
the CPUC initiated a proceeding (Rulemaking 02-01-011) to prevent or minimize cost shifting
for direct access customers. As discussed above, that proceeding has since expanded to also
address cost shifts that would occur if a newly fonned "publicly-owned utility" ceases to buy its
requirements /Tom the California investor-owned utilities and procured power by self-generation
or purchases /Tom other sources to provide electricity to customers within its service territory.
Pursuant to the Commission's MDL Decisions, on July 10, 2003, the CPUC
issued an "Order Adopting Cost Responsibility Surcharge Mechanisms for Municipal Departing
Load.,,22 If Chula Vista fonns an operating MEU and begins to generate power or purchase
power from an entity other than SDG&E it will be responsible for paying an apportioned share of
SDG&E's DWR-related costs as Municipal Departing Load.
Although the CPUC does not have general rate and service authority over publicly
owned utilities, in the MDL Decisions, the Commission found that it does have the authority
under AB IX and AB 117 to impose a "cost responsibility surcharge" (CRS) on Municipal
Departing Load to cover DWR-related costs (including both bond charges for past purchases and
the obligations oflong tenn contracts entered into by DWR) if the customers took bundled utility
service on and after February 1,2001 /Tom an IOU, of if the customer is located in an area that
was part of the IOUs' service territory on or after February 1,2001 and therefore likely included
in the load forecasts provided to DWR.
In the case ofSDG&E, the Municipal Departing Load CRS has three components:
(I) DWR Bond charges; (2) DWR Power Charge; and (3) a "Tail Competitive Transaction
Charge," which is applicable to all Municipal Departing Load Customers in the investor-owned
utility service territories as of December 20, 1995. These charges would continue to apply to
SDG&E Municipal Departing Load Customers until these costs are fully recovered by SDG&E
or until the charges are no longer assessed to the investor-owned utilities, including SDG&E.
As the law currently stands, load that falls within the meaning of "Municipal
Departing Load" is subject to the cost responsibility surcharges imposed by the MDL Decisions,
It is worth pointing out that the MDL Decisions have been the subject of petitions for writ of
review filed with the California Supreme Court. Moreover, the contracts and costs which give
rise to the CRS are the subject of a number of lawsuits in the state and federal courts and in
proceedings before the FERC. The outcome of any of these legal proceedings may change the
nature, amount, and applicability of the CRS.
21 SDG&E began purchasing power through DWR on February 7, 2001.
22 See CPUC Decision 03-07-028.
36
H_.___....-.-
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
The MEU Study Team analysis assumes that the CPUC will impose exit fees on
the City for costs associated with uneconomic utility retained generation and power purchase
contracts, DWR power purchase contracts, and bond charges /Tom DWR financing of past power
purchases. Exit fees are assumed to apply in all cases of CCA, Greenfield, and MDU
development, consistent with the CPUC's proposed and final decisions in rulemaking proceeding
R.02-01-011. Any changes to this assumption would impact the results of the analysis.
Based on these assumptions, the exit fees used in the analysis are derived from the
exit fees applicable to direct access customers. The MEU Study Team used the annual exit fee
projections /Tom the capping phase of direct access surcharge proceeding, R.02-01-011 using the
DWR modeling scenario identified by the Administrative Law Judge as the most reasonable
scenario in her May 20, 2003 Proposed Decision (Scenario 14). Exit fees for direct access
customers are capped at 2.7 cents per kWh. The cap was adopted by the CPUC to meet the
objective of maintaining the viability of existing direct access contracts. The cap is not assumed
to apply to CCA and future MEU activities, and the full, uncapped exit fees were included in the
feasibility analysis. For SDG&E, the full cost exit fees are expected to be below the cap.
a. Direct Access Cost Responsibility Surcharge
Decision 02-11-022, issued on November 7, 2002, established the methodology
for determining the Direct Access Cost Responsibility Surcharge (DA CRS) and related policy
issues. The DA CRS is currently being used as a benchmark for the determination of both the
MDL CRS and a CRS that would be applied to CCA customers. The actual calculations for
2003 are to be made following implementation workshops, once the final DWR historical costs
and 2003 revenue requirements are known. The DA CRS is determined separately for each
utility and will be updated annually as part of the DWR revenue requirement update. As of
January 1,2003 the DA CRS was set at the capped rate of2.7 cents per kWh. The components
of the DA CRS are:
. DWR bond charge. Applicable to all DA except for those who were continuously DA
both before and after DWR began its power purchase program.
. DWR power charge for procurement costs between 9/21/01 and 12/31/02. Applicable to
all incremental DA load that took bundled service on or after 2/1/01.
. DWR power charge for uneconomic portion of prospective (2003 and beyond) DWR
costs. Applicable to all incremental DA load that took bundled service on or after 2/1/01.
. URG costs for market portion of Utility Retained Generation. Applicable to all DA
customers.
37
- -..---.--. . -.--.----------.-.--. ----- .-.---.
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
b. Calculation ofthe DA CRS Components
(1) DWR Bond Costs
The DWR bond costs will be the same as charged to bundled service customers as
detennined in CPUC decision D.02-10-063.
(2) DWR Power Charges
DWR power charges (both historical and prospective) are calculated to keep
bundled customers' rates unaffected by the migration of customers to direct access between July
1,2001 - the suspension date for DA that was articulated in the Commission's proposed decision
- and September 20, 2001, when DA was actually suspended pursuant to the final CPUC
decision (D.OI-09-060).
The DWR power charges are detennined by production cost modeling using the
difference in the average cost of the utility's total portfolio with and without the loads of
incremental direct access customers, The DA CRS (excluding the DWR bond component) is set
so that CRS payments by incremental DA customers offset the increase in cost of the portfolio.
The DWR portion of the DA CRS is detennined by subtracting the uneconomic URG costs
component (i.e., CTC), described below, /Tom the total DA CRS.
The DWR power costs for the historical period, which were funded by bundled
service customers, will accrue interest on unpaid balances until repaid by DA customers. The
DWR power charge for prospective costs will be implemented concurrently with the 2003 DWR
power charge~ for bundled customers.
(3) Utility Retained Generation (URG) Costs
The uneconomic URG costs are to be calculated by comparing the URG revenue
requirement to a market value proxy based on the cost of a combined cycle gas turbine, using a
15-year depreciable life. For 2003, the market value proxy is 4.3 cents / kWh. The uneconomic
URG costs are divided by total bundled and direct access sales to derive the URG component of
the DA CRS. This implies stranded cost recovery for all utility generation and contracts, not just
the "tail CTC" (Competition Transition Charge) components itemized in AB 1890. To the extent
that the URG portfolio contains economic assets, inclusion of these assets will reduce the CTC.
DA customers will also pay a relatively small cost component for employee-related transition
costs as part of the ongoing CTC.
38
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
(4) DA CRS Cap
CPUC decision D.OI-II-022 established that payments related to the DA CRS for
DA customers are subject to an initial 2.7 cents per kWh cap through July 1,2003. The revenue
shortfall between the actual OA CRS and the cap will accrue interest at the rate applicable to
OWR bonds.
On January 9, 2003, the AU issued a Ruling Scheduling Further Proceedings
Regarding the DA CRS cap. As directed by 0.02-11-022, the AU conducted further
proceedings to determine whether, or to what extent, the cap should be revised after July I, 2003
to ensure that shortfalls (plus interest) are recovered /Tom DA customers over a reasonable time
period. Despite an alternative decision proposed by Commissioner Lynch that would have
increased the cap to 4.0 cents per kWh, in July 2003, the Commission issued Decision 03-07-030
retaining the 2.7 cent cap for another year.
(5) AB 265 Under-collection
AB 265 and CPUC implementing decisions required SDG&E to place a ceiling of
6.5 cents per kWh on the electric commodity rate for specified SDG&E customer classes,
primarily residential, small commercial, and lighting customers, retroactive to June I, 2000.
SDG&E was required to establish an account to record the difference between the 6.5 cents per
kWh rate ceiling and the actual commodity rate. The 6.5 cents per kWh rate ceiling expired on
December 31,2002. As of December 31,2002, the under-collected balance was $215 million.
The CPUC has allowed SDG&E to maintain its CTC at a level above cost-of-service to help
reduce the AB 265 undercollection. Consistent with this practice, the MEU Study Team
modeled SDG&E's CTC revenue requirement at the current $115 Million for 2003 and 2004,
and any excess CTC revenue collected above the actual CTC costs are used to reduce the under-
collections associated with the capping of customers' rates mandated by AB265. The CTC is
assumed to revert to cost-of-service in 2005.
6. Federal Stranded Costs
In addition to state imposed exit fees and other nonbypassable charges, the City
may be exposed to the payment of Federal stranded costs under the orders and procedures of the
Federal Energy Regulatory Commission.
In its orders Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities, the FERC established procedures for addressing the
uneconomic sunk costs that utilities have prudently incurred under an industry regime that rested
on a regulatory framework that was fundamentally altered. Under these procedures, FERC may
require the departing customer of the utility to pay the utility's stranded costs, either as an exIt
39
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
fee or as a surcharge on the transmission services. FERC has determined that a utility can only
seek recovery of stranded costs in those situations where a departing customer has obtained
access to a new generation supplier through the use of the former supplying utility's FERC-
required transmission tariff. FERC has established the following standards in determining
whether a retail requirements customer which has become a wholesale distribution customer of a
utility is responsible for the payment of stranded costs:
[t]o be eligible to recover stranded costs /Tom a departing
customer, the utility must demonstrate that it incurred costs to
provide service to the customer based on a reasonable expectation
of continuing service to that customer beyond the contract term. In
the case of stranded costs associated with wholesale requirements
contracts customers, if the contract contains a notice of termination
provision, that provision is strong evidence that the parties were
aware that at some point in the future the customer might seek to
find another supplier. Therefore, there is a rebuttable presumption
of no reasonable expectation, and therefore no opportunity for
stranded cost recovery unless the utility can overcome the
presumption.
Order No. 888-A at 30,348. The rebuttable presumption must be overcome by the utility. FERC
will consider "evergreen" or other automatic renewable provisions, whether state law awards
exclusive service territories and imposes a mandatory obligation to serve, in determining whether
the utility had a reasonable expectation to serve, Under the FERC's rates and its formula for
computing stranded costs, the amount of stranded costs obligation can be no more that the
average annual contribution to fixed power supply costs that would have been made by the
departing generation customer had it remained a customer of the utility.
The implementation procedures for determining the stranded cost obligation are
as follows: (I) the customer requests /Tom the utility an estimate of the customer's stranded cost
obligation, based upon the customer provided date that it is considering substituting alternative
generation with that of the utility; (2) the utility has thirty days upon receipt of the request to
respond to the customer with an estimate of the stranded cost obligation, including each
component of the calculation and supporting detail to justify the amounts; (3) the customer will
have thirty days to respond to the utility explaining which items, if any, it disagrees; and (4) if
the parties are unable to agree on the stranded cost obligation, the customer can file with the
Commission a petition for declaratory order or a Section 206 filing (the customer could also wait
until the utility makes a Section 205 filing for stranded cost), seeking a Commission
determination on the stranded cost obligation. The stranded cost obligation estimate does not
become binding until either party initiates a proceeding with the Commission.
40
APPENDIX B
REGULATORY AND LEGISLATIVE ISSUES
The stranded cost obligation of Chula Vista will be dependent upon the types of
generation contracts entered into by SDG&E on behalf of the load in Chula Vista, as well as any
remaining generation interest held by SDG&E that is used to service Chula Vista, Presumably,
restructuring under AB 1890, which required that SDG&E sell its generation assets, would have
resulted in the mitigation of most of the potential stranded costs associated with generation
owned by SDG&E. However, an actual stranded cost estimate would need to be obtained /Tom
SDG&E.
41
-
APPENDIX C
TECHNICAL APPENDIX
APPEND IX C
TECHNICAL APPENDIX
42
-
-
APPENDIX C
TECHNICAL APPENDIX
TABLE OF CONTENTS
1. ELECTRICITY SUPPLY...................................... ................... 51
-
A. Regional Electricity Infrastructure....................... ............ ... 51
- 1. LoadsILoad Forecast....................... ........ ...... ..... ... 51
2. Resources.................. ...............,........................ 52
-
a. Market Area Generation................................ 53
b. Transmission Import Capability......"............... 53
3. Proposed Generation...... ...... ...... ............,.............. 54
-
a. Load/Resource Balance................................. 54
b. SDG&E Load/Resource Balance....................... 55
B. In-Area Generation....................................... .................. 56
C. Regional Electric Energy Resource Balance Prospects to
Expand Transmission Capacities......................................... 58
D. Planned Generation Resources......................,..................... 59
1. Otay Mesa Generating Project.........................,........, 59
2. Palomar Energy (Escondido) ...................,................ 60
3. South Bay Power Plant Repower (SBPP).......................60
4. Significant Barriers to Power Plant Development... . . . . . ., .. 63
II. FINANCIAL ANALYSIS ASSUMPTIONS AND PRO FORMA.....".... 64
A. SDG&E Forecast Rates..................... ..................,............64
I. Utility Retained Generation...................,................ 65
43
APPENDIX C
TECHNICAL APPENDIX
2. DWR Contracts.......................................,............66
3. Non-Generation Rates.......................................... ...66
4. AB 265 Under-Collection...............................,....... 67 _.
B. Electric Supply Costs......... .................. ........................... 67
-
1. LoadProfiles...................................................... 67
2. Electric Supply Portfolio....................................... 68 -
a. Spot Market Prices....................................... 69
-
b. Power Purchase Contract Prices............... .........70
c. Renewable Energy Contract Prices.............,.... ...72 -
d. Generation Ownership... .....,.....................,.... 73
-
3. Portfolio Operations Costs... ..,......,........""'" ......... 77
C. Non-Bypassable Charges............ .................................... 78 -
1. CPUCExitFees.......................................,......,.......78
-.
2. Other Non-Bypassable Charges.........,........... .........,.. 81
Public Purpose Programs......................,....... 81 -
a.
b. Nuclear Decommissioning Charges.................. 82
c. Fixed Transition Amount (FTA) ...............".... 82
D, CAISO ..Charges.............................,.....,.....,..""""""" 83
1. Transmission.........................,............................ 83
2. Other CAISO Charges.............,............................ 83
E. Distribution System Capital Costs.........................,............. 84
44
-.... ...----------------..--------..-....-.-....-----..----- .
-
APPENDIX C
TECHNICAL APPENDIX
1. Valuation Methods....................................,........... 84
-
2. Analysis of Distribution System Capital Costs............... 84
- F. Distribution System Operations and Maintenance Costs............ 87
G. Utility Financing......... ...................................................88
-
H. Additional Cost Considerations............ ...... ...... ..,......... ...... 88
1. Franchise Fee Impacts...... ............ ...."......,..... .........88
2. In-Lieu Property Tax Payments................................. 89
-
1. Pro Forma Analyses........................................................ 89
1. Financial Pro Forma Analysis - CCA Option - Generation. 90
2. Financial Pro Forma Analysis - CCA Option - Contracts... 91
-
3. Financial Pro Forma Analysis - Greenfield Option -
Contracts..............................................,.............92
4. Financial Pro Forma Analysis - Combined CCAlGreenfield
Option, Greenfield Areas - Generation........................ 93
5. Financial Pro Forma Analysis - Combined CCAlGreenfieid
Option, CCA Areas - Generation.............................. 94
6. Financial Pro Forma Analysis - Combined CCAlGreenfield,
Greenfield Areas - Contracts................................... 95
7. Financial Pro Forma Analysis - Combined CCAlGreenfield,
CCA Areas - Contracts..... ......"....,.......................".96
8. Financial Pro Forma Analysis - MDU Option -
Generation..."...."....",..."....."....".........., 97
9. Financial Pro Forma Analysis - MDU Option -
..Contracts............................................... 98
45
APPENDIX C
TECHNICAL APPENDIX
10. Financial Pro Forma Analysis - Natural Gas Utility
Option................................................... 99
III. NATURAL GAS REGIONAL ISSUES AND SUPPLY
FOR POWER GENERATION................................................... 101 _.
A. Natural Gas Supply Outlook............................................. 101
-
1. California Gas Supply... ............... ............... ............101
2. Natural Gas Transportation InfTastructure.................... ..104 -
3. BasisDifferentials................................................108
-
4. California Intrastate Transportation...... ...... ...... ......... 109
B. SDG&E Gas Transmission System.................................... III -
C. SDG&E Rates, Regulation and the Comprehensive
Settlement Agreement..................................................... 114 -
D. Natural Gas Prices..........................................., ,............116
-
E. Price Forecast for SDG&E Service Area.............................. 118
F. Regional Issues.............................................................. 119 -
1. PG&E National Energy Group, Owner/Operator of
North Baja Pipeline...... .........,..... .......,................. 119 -
2. Baja LNG Projects... ....................,...........,.......... 120
-
G. Gas Procurement Strategy... ....,.......................................,.,124
IV. FINANCING OPTIONS............................................... ............ 126
A. Comparative Features of Alternative Financing Methods. . . . . ... . . .. 126 -
B. Purpose .of Financing,.................................................... 127
C. Tax-Exempt Financing Eligibility....................................... 128
46
.-. . ----.-.----------------.----------...
APPENDIX C
TECHNICAL APPENDIX
D. Certificates of Participation...... .......................,......... ...... 128
E. Commercial Paper...........................................................129
- V. IMPLEMENTATION SCHEDULES.......................................... 130
A. CCA- Implementation Schedule...............,....................... 130
B. Greenfield Implementation Schedule...."......... ............... ...... 131
C. MDU Implementation Schedule.......................................... 132
VI. OPERATING AND MAINTENANCE EXPENSE........................... 133
A. National Public Utility O&M Benchmarking... ..,.....................133
B. California Public Utility Statistics........................ .............. 134
C. Targeted O&M Expenses Benchmarking Pane!........................ 139
.-
D. Human Resources........................................................ 140
1. Portfolio Operations and Scheduling - CCA.......,........ 140
2. Portfolio Operations - Greenfield (In House
Stand Alone Labor)...... ...,.. ......................... 140
3. Municipal Distribution Utility Human Resources
Requirements.................................. .............. ..... 141
APPENDIX C
CHARTS/GRAPHS
Section I
Table 1 - Composition of Generation for the Southern California
Market Area...........,... ............".........................,....... 53
Table 2 - Non-Simultaneous Transmission Import Capability Into the
Southern California Market Area,..... ............ .........,........... 54
47
APPENDIX C
TECHNICAL APPENDIX -
Figure A - Southern California Load/Resource Balance.........,..... ...... 55
Projected Regional Loads and Transmission Import Limits............... ... 56
-
Electric Generation Plants in SDG&E's Area............ ......... ..,......... 57
SDG&E Electricity Resource Balance......... .....,...... ...............,..... 58
South Bay Power Plant - In-Service Dates and Capacity...... .,............. 61
-"
South Bay Power Plant Efficiency and Emission Output (Tons)...... ..... 61
Section II -
Chart 12: Projected SDG&E Retail Rates From 2006 Through 2023...... 65
-
Chart 13: Projected Monthly Load Requirements ofChula Vista in 2006.. 68
Chart 14: Projected Average Electricity Prices for Baseload -
Requirements....................................................,.......... 70
Power Purchase Contracts - CCAlMDU Options......... ......................71 -
Power Purchase Contracts - Greenfield Option............ .,,"..""'..'.'" 71
Renewable Energy Contracts- CCAlMDU Options......................... 72
Renewable Energy Contracts - Greenfield Option........................... 73 -
Chart 15: Electricity Production Costs for City-Owned
Combined Cycle Gas Turbine........................................... 74
Chart 16: Loads and Resources on a Monthly Basis for 2006 - -
Generation Supply Strategy............................................. 75
Chart 17: Average Supply Cost By Resource For 2006 -
Generation Supply Strategy......................,......,.....,.......... 76
48
_"__0'- .--
APPENDIX C
TECHNICAL APPENDIX
Chart 18: Loads and Resources on a Monthly Basis for 2006 -
~ Contracts Supply Strategy............... ...... ...... ..,................. 76
Chart 19: Average Supply Cost By Resource For 2006 -
- Contracts Supply Strategy........................... .................... 77
Chart 20: Total Portfolio Costs Compared to Estimated SDG&E
- Generation Credits......... ............ ...... ...... ..,.................... 78
Chart 21: Annual Exit Fee Projections - Base Case..,..................... 80
-
Chart 22: Annual Exit Fee Projections - High Case........................ 81
Section III
Table I - Supply Basin Characteristics.......................................... 102
-
Table 2 - Recorded California Gas Demand - Average Daily MMcfd...... 102
Table 3 - SDG&E Average Daily Demand - MMcfd..........,............. 103
Table 4 - Forecast Finn Service Demand....................................... 104
Figure 1- Western Natural Gas Pipelines....................................... 106
Table 5 - Pipeline Capacity Into California - bc£'day........................ 107
- Figure 2 - U.S. Major Supply Basin and Market Center Prices
January-June 2003...........................................,.........,... 109
Figure 3 - Southern California Backbone Transmission System............ 110
Table 6 - SoCai Gas Backbone Receipt Point Capacity........................111
Figure 4 - SDG&E and Area Pipeline Infrastructure.....................,...,. 113
Table 7 - Delivered Natural Gas Prices 2004-2013........................... 119
Table 8 - West Coast LNG Projects............................................. 121
Figure 5 - Baja California Pipeline In/Tastructure Showing
Proposed LNG Facilities............................................. .... 123
49
-------- .---
APPENDIX C
TECHNICAL APPENDIX ..-
Section IV -
Comparative Features of Alternative Financing Methods....,................. 126
_.
Section V - Gantt Charts
CCA Implementation Schedule.................................................... 130 -
Greenfield Implementation Schedule.........,................................,.. 131
-
MDU Implementation Schedule.............................................,.....132
Section VI -...
O&M Expense Benchmarking".......................................,...".... 133
CA Public Utility Statistics -
Anaheim, Burbank, Glendale, Pasadena............................... 134
Alameda, Azusa, Colton"..... .......................................... 135 -
Lassen, Lodi, LADWP................................................., 136
MID, Palo Alto, Redding, Riverside............... ...... ............. 137
Roseville, SMUD, Santa Clara......................................... 138
Targeted O&M Expenses Benchmarking PaneL............................. 139
Portfolio Operations & Scheduling - CCA......... ............ ................ 140
Portfolio Operations & Scheduling - Greenfield (In-House
Stand-Alone Labor),..... .........................,....",............... 140
MDU Human Resources Requirement............... ........................... 141
50
--..... ---......---..-- ...-..-.....---..-...--..
,-
APPENDIX C
TECHNICAL APPENDIX
I. ELECTRICITY SUPPLY
A. Regional Electricity Infrastructure
-
As discussed in other sections of this Report, the energy market in
California and the country have undergone dramatic changes in the past several years.
- This section examines the electricity supply and demand for the southern California
region and more specifically for the SDG&E service territory. Southern California is part
of the Western Electricity Coordinating Council (WECC). The WECC is the
interconnected electrical grid consisting of all or part of the twelve western states, two
Canadian providences and a portion of Mexico. Actions in a portion of the WECC can
- and do impact the rest of the WECC.
The City and the service territory of SDG&E are part of the larger
Southern California Market Area. The Southern California Market Area stretches /Tom
the border of the PG&E/SCE service territory in the north to Mexico in the south. SCE is
the dominate utility in the region serving almost 60 percent of the approximately 33,000
MW load. However, the SDG&E and the Los Angeles Department of Water and Power
(LADWP) are also large utilities within the Southern California Market Area.
The Southern California Market Area has a significant amount of existing
inftastructure, both generation and transmission; however, the Southern California
Market Area is very dependent on imports /Tom other regions to meet its load
requirements. Many of the existing generation units in southern California are over 30
years old and a significant portion of the transmission into the region is either committed
to long-term agreements or is utilized to import Southern California Market Area
utilities' resources located out-of-state. Due to the large load and age of the plants, there
are numerous projects proposed for the Southern California Market Area. However, over
the course of the last twenty-four months, several of these have been cancelled or at least
put on hold. This has occurred for several reasons including regulatory uncertainty,
financial problems of potential developers, renegotiation of contracts by the State of
California, continued financial uncertainty of California investor-owned utilities, and the
overall economic conditions.
1. LoadslLoad Forecast
In 2002, the seventeen electric utilities in the Southern California Market
Area had an estimated non-coincidental summer peak load of 33,500 MW. The Southern
California Market Area peak load considered by this analysis represents the sum of the
individual utility peak loads, not necessarily the coincidental peak load,
To estimate the demand for energy, the MEU Study Team developed a
ten-year summer peak demand forecast for each of the utilities within the Southern
California Market Area. The forecast was based in part on historical information
51
APPENDIX C
TECHNICAL APPENDIX
regarding the peak demand of each utility, as well as information available from the CEC
and the CAISO. For SDG&E the estimate is /Tom the direct testimony of David M.
Korinek in CPUC Rulemaking 01-10-024.23 Overall, these sources indicate that the
expected load growth for the Southern California Market Area is projected to increase at
an average annual rate of 2.1 percent for the forecast period.
The two IOUs (SCE and SDG&E) that provide electric services within the
Southern California Market Area serve approximately 69 percent of load with SCE -.
meeting 57 percent and SDG&E 12 percent. SCE's load is estimated at 18,000 MW for
2002 and is projected to grow to 21,900 MW by 2011. SDG&E's load is estimated at
3,660 MW for 2002 and is projected to grow to 5,125 MW by 2011. -
The publicly-owned utilities in the Southern California Market Area --
include municipal utilities, irrigation districts, water districts, and government agencies
(e.g., California Department of Water Resources). In total, the publicly-owned utilities
have a combined peak demand of approximately 9,950MW, or 31 percent of the Southern
California Market Area for 2002. This load is estimated to grow to 11,000 MW by 2011.
The largest municipal utility, LADWP, accounts for 55 percent of the non-IOU load and
16.5 percent of the total Southern California Market Area load.
For the purposes of this analysis, and consistent with the WECC standard
reserve requirements, this analysis assumes a seven percent reserve margin requiremenr4 -
for Southern California Market Area throughout the ten-year forecast period.
2. Resources
Resources available to meet demand requirements in the Southern
California Market Area include (I) market area generation, and (2) transmission import
capability. Existing market area generation is estimated to be approximately 29,000 MW
in 2003. This includes the addition of over 2,300 MW that have been added to the
system since 2001. The simultaneous transmission import capability is estimated to be
approximately 13,000 MW throughout the lO-year forecast period.
23 Direct Testimony of David M. Korinek, April 15, 2003, CPUC Rulemaking No. R.Ol-lO-024,
Presenting information On Elecnical Grid Reliability Criteria And Long- Tenn Planning Additions
in SDG&E's Long-Tenn Resource Plan to Establish Policies and Cost Recovery Mechanisms for
Generation Procurement and Renewable Resource De'. elopment.
24 For SDG&E the reserve margin is 15 percent, which is in conformance with the testimony by Mr.
Korinek.
52
APPENDIX C
TECHNICAL APPENDIX
- a. Market Area Generation
- Natural gas-fired units dominate existing Southern California Market Area
generation. These units account for approximately 21,800 MW or approximately 71
percent of the existing generation in the Southern California Market Area. Table I
- summarizes the composition of the generation in the Southern California Market Area.
Table I
- Composition of Generation for
The Sonthern California Market Area
Capacity Percent
- Fuel Tvne (MW) of Total
Hydro 4,273 14%
Natural Gas/Oil 19,994 71%
-
Geothermal 36 0%
Nuclear 2,150 7%
Other 2,379 8%
Total 28,832 100%
- b. Transmission Import Capability
Transmission imports into the Southern California Market Area play an
extremely crucial role in meeting the needs of the region. Southern California Market
Area utilities import a large amount of generation located in Nevada, Arizona, New
Mexico, and Utah through the area's transmission system. Imports are necessary to
"keep the lights on" in the Southern California Market Area.
Transmission imports to the Southern California Market Area are
governed by the Southern California Import Transmission (SCIT) nomogram. The
maximum non-simultaneous import capability into the Market Area is 18,564 MW.
However, the SCIT nomogram currently limits simultaneous imports to approximately
13,000 MW, depending on multiple system conditions (including all units at Palo Verde
being online and all transmission facilities being in-service and the amount of
transmission flowing on the East of River (EOR) transmission system).
There are several different transmission paths that feed southern
California, including transmission lines /Tom northern California (Path 26), the Pacific
Northwest (PDCI), the Desert Southwest (WOR), Utah region (Intennountain), and
Mexico. Table 2 below identifies all of the major transmission paths into the Southern
California Market Area.
53
APPENDIX C
TECHNICAL APPENDIX
Table 2
Non-Simultaneous Transmission Import Capability
Into the Southern California Market Area
Capacity
Transmission Path (MW)
West of River 10,118 -
Path 26 3,000
Pacific DC Intertie 3,100
Intermountain DC 1,920 --
Mexico Intertie 408
3. Proposed Generation -
Over 4,100 MW of new generation (II projects) are currently proposed
for the Southern California Market Area, according to the CEC. The proposed projects
are almost exclusively natural gas-fired generation. In addition, several thousand
megawatts of proposed projects have either been terminated or put on-hold. It is
anticipated that approximately half of the proposed new generation will ultimately be
built in the Southern California Market Area.
Further complicating the analysis of the Southern California Market Area
is the need to take into account the amount of generating capacity that would be out-of-
service, whether for scheduled maintenance work, forced outages, or the lack of emission
credits. To accommodate such an adjustment for the Southern California Market Area,
the MEU Study Team reviewed power plant outage information provided by the CAISO
to derive an outage adjustment factor for this analysis. Although it is important to note
that plant outages vary throughout the year, especially during winter and spring periods
as a result of planned maintenance activities, the outage factor of 10 percent used for this
study is aimed to provide a conservative estimate of readily available generation
resources.
a. LoadlResource Balance
Figure A below provides an illustration of the projected load/resource
balance for the next ten-year period.
54
-
APPENDIX C
TECHNICAL APPENDIX
-
Figure A
Southern California Load/Resource Balance
-
50,000
- 45,000
40,000
35,000
- 30,000
25,000
20,000
-
15,000
10,000
- 5,000
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
- b, SDG&E LoadIResource Balance
SDG&E meets the electric demand of its service territory through
generation projects located within its service territory and by importing energy from
outside its service territory using its transmission system and the CAISO Controlled Grid.
Limited new generation or transmission projects have been added to SDG&E's system
over the past several years; however, there are currently several projects (both generation
and transmission) that are being considered to meet the needs of SDG&E's customers.
In 2003, the estimated peak load and reserve requirement for SDG&E's
service territory is estimated to be 4,370 MW. This is expected to grow to over 5,000
MW by 2006-07. The SDG&E service territory is facing a resource shortfall by 2006-07
unless new resources are brought on-line.
Existing Transmission Capacity
The SDG&E transmission system has a simultaneous import capability
limitation (SIL) of 2,850 MW. Pursuant to the CAISO statewide standards, SDG&E
transmission planning additions will increase SIL by 750 MW in 2008 and 1000 MW in
2012. If SDG&E's customer load exceeds these import limits, it must be supplied by
local generation?5 Existing and projected electric demand significantly exceeds existing
and planned transmission import limits. The maps on the following pages highlight the
25 See Korinek Testimony, April 15. 2003, CPUC Rulemaking No. R.Ol-IO-024.
55
APPENDIX C
TECHNICAL APPENDIX
existing SDG&E transmission system, the SDG&E proposed transmission projects, and
finally the "cut planes" or limitations to imports into the SDG&E service territory.
Projected Regional Loads and Transmission Import Limits"
-
5000
L004"'"""I(8oo""'."""""'1
4500 '-..... .' -
4000 .'
3500 ,..... .........
3000 ..'.'_"""""odJDo""""""." -
2500 "~m"."S"temSi-ru',"oous """,rt",""
2000 -
,~~" -5"" -5'~' -5'¿} -5'<!? -5'<!' -5'<? -5'<J' -5'~~ -5'«/' -5'<5' -5"~ -5'" l"
--
B. In-Area Generation
In addition to generation imports, SDG&E relies upon in-area generation -
to meet the electricity demands of its customers. In-area generation relies almost solely
on the Encina and South Bay Power Plants.
-
The following table summarizes existing local area (on-system) generation
capacity?? Resource planning portfolios are designed to meet peak loads plus a planning
reserve margin of 15 percent each year. On-system generation capacity is currently -
approximately 2,000 MW short of meeting the region's 2002 load and reserve
reqUIrements.
-
-
-
-
26 California Energy Commission (CEC) 2002 - 2012 California Energy Commission Staffs Outlook
for the State - Tables E-l, E-2, E-3. -
27 Direct Testimony of Robert B. Anderson, April 15 2003, CPUC Rulemaking No. R.OI-IO-024
Presenting SDG&E's Long-Term Resource Plan to Establish Policies and Cost Recovery
Mechanisms for Generation Procurement and Renewable Resource Development.
56
-
APPENDIX C
TECHNICAL APPENDIX
Electric Generation Plants in SDG&E's Area MW
-
Encina and South Bay 1,635
Combustion Turbines 525
- Renewable Power Plants 30
Cogeneration 170
- Total Capacity 2,360
2002 Peak Load and Reserw Requirement 4,370
-
Local Generation Deficiency 2,010
-
Existing base-load generation resources in San Diego were placed in
service in the mid-1950s to mid-1960s and are approaching retirement. As existing
- resources are retired and as regional load continues to grow, the capacity of indigenous
generation to meet the region's needs is estimated at 55 percent in 2002, and ma~ dip to
44 percent by 2010, 36 percent by 2020 and as low as 29 percent by 2030. 8 The
- following chart shows how regional resources, both transmission and on-system
generation, will fall short of serving regional load as early as 2006,
-
28 The San Diego Regional Energy Inftastructure Study (RElS) was commissioned by a multi-
agency team consisting of the City of San Diego, the County of San Diego, the San Diego County
Water Authority, the San Diego Association of Governments, the San Diego Regional Energy
Office, the Utility Consumers Action Network and the Port of San Diego. The goal of the study
was to develop a fact-based foundation for assessing the San Diego regions electricity and natural
gas needs through 2030. The Study was completed by San Diego-based Science Applications
International Corporation and can be found at http://www.sdenergy.orgi
57
APPENDIX C
TECHNICAL APPENDIX
-
SDG&E Electricity Resource Balance
-
7,000
Rejected Valley Rainbow
6,000 rmnsmi"ion Project ---
-
5,000
-
4,000
3,000 -
2,000 / Cogeneration
-
1,000 Encina Power Plant
South Bay Power Plant -
"," ",'> "'~ "," "," "," "," "," ," "
,,'" ,,'" ,,'" ",'" ",'" ",'" ,,'" ,,'" ,," ","
-
C, Regional Electric Energy Resource Balance Prospects to Expand
Transmission Capacities -
Existing and planned electric transmission system import capacities fall
significantly below projected load growth in the SDG&E load area. This best-case
scenario anticipates in-service dates for planned transmission upgrades assuming --
regulatory approval and construction lead times. In the past, as with the planned
transmission upgrade of its new Northern Interconnection (subsequently named the
Valley Rainbow Interconnect), the CPUC has demonstrated that its approval cannot be
assumed.
The CAISO Tariff requires SDG&E to conduct an annual grid assessment -
and expansion study. The study covers a ten-year planning horizon and is conducted
using a CAISO stakeholder process that allows for third party review and input. During
the 1999 grid assessment study, SDG&E identified the need for a new Northern --
Interconnect, which was approved by the CAISO Board of Governors in May 2000.
SDG&E subsequently filed a Certificate for Public Convenience and Necessity (CPCN)
application for the project with the CPUC in March 2001.
After a 21-month proceeding, ending in December 2002, the Commission
rejected SDG&E's application for a CPCN to build the Valley Rainbow transmission
58
APPENDIX C
TECHNICAL APPENDIX
project.29 SDG&E filed a petition for a rehearing which the CPUC denied in May 2003.
SDG&E then asked that the case be reopened based on new evidence. The CPUC denied
SDG&E's bid to reopen the ease on June 5, 2003.
As illustrated above, resource planners can neither assume nor rely upon
regulatory approvals of projects, notwithstanding demonstrated necessity by cognizant
authorities. Given SDG&E's inability to successfully overcome the complex, lengthy
and costly process of seeking approvals by the CAISO and the CPUC in pursuit of such
projects, the MEU Study Team has a low level of confidence in similar transmission
alternatives for the City. The sole remaining alternative lies in increasing local
generation to meet the area's, and the City's, growing needs.
D. Planned Generation Resources
-
1. Otay Mesa Generating Project
- The Otay Mesa Generating Project (Otay Mesa) will be a 510 MW,
natural gas-fired combined cycle power plant located in the Otay Mesa area in western
- San Diego County. The 15-acre site is about 15 miles southeast of San Diego, California,
and about 1.5 miles north of the United States/Mexico border.
- A new 230-kV switchyard at the site is proposed. There are plans to build
a O.l-mile connection to SDG&E's existing 230-kV Miguel-Tijuana transmission line
that passes near the eastern boundary of the Otay Mesa site. A new two-mile natural gas
pipeline will be built by SDG&E to provide fuel for the project. Originally scheduled for
completion in the summer of 2002, the construction schedule now calls for its completion
by summer 2005. Currently the project is reported to be five percent complete.
A Master Power Purchase and Sale Agreement (MPPSA) was entered into
on May 1,2002 between the project owner, Calpine Energy Services, LP, and DWR
setting forth the tenns for the sale of Otay Mesa power output to DWR.3o Under the
agreement, Calpine must provide monthly reports to DWR setting forth any pre-
construction activities (including pennitting, licensing, financing, equipment acquisition
and similar preconstruction activities), construction activities, progress toward
compliance and any milestone dates established by the CEC or other applicable siting
pennit and expected commercial operation dates, Furthennote, under the agreement,3! if
Calpine elects not to proceed with development of the project or fails to achieve any
major milestones, all rights, title and interests in Otay Mesa will transfer to DWR.
On May 9, 2003, Calpine filed a motion in CPUC Rulemaking 01-10-024,
Order Instituting Rulemaking to Establish Policies and Cost Recovery Mechanisms for
29 See the CPUC Decision (D 02-12-066) rejecting SDG&E's CPCN application for the Valley
Rainbow transmission project.
30 The MPPSA can be found on DWR's website www.cers.water.ca.gov/newContracts.html
31 MPPSA Special Conditions (4)(a) (i) and (ii).
59
APPENDIX C
TECHNICAL APPENDIX
Generation Procurement, requesting the Commission provide expedited "guidance and
authority" to SDG&E to immediately address its resource needs for 2005, including
expediting discussions to secure an executed and approved long-tenn power purchase
agreement. Comments supporting the request have been filed by the CAISO, the
California Consumer Power and Conservation Financing Authority (Power Authority),
and Save Southwest Riverside County. Comments opposing Calpine's motion have been
filed by SDG&E, Sempra Energy Resources and Dynergy Marketing and Trading in
addition to motions to intervene which were granted to InterGen and Peabody Western
Coal Company, all of which have competing generation interests.
SDG&E has recently announced plans to purchase most or all of the
capacity /Tom Otay Mesa.
2. Palomar Energy (Escondido)
The proposed project consists of a natural gas-fired combined cycle power --
plant with a nominal electrical output rating of 546 MW and commercial operation
planned for the summer of 2004. The project location is a 20-acre site within a planned
186-acre industrial park in the City of Escondido. The project includes a new 230-kV
switchyard connecting with an existing SDG&E electric transmission line located
immediately adjacent to the project site.
The project does not require construction of any new transmission lines
and will be fueled with natural gas delivered via an existing SDG&E gas pipeline.
The project is being developed by Palomar Energy LLC (Sempra
Energy32) under Certification Application (01-AFC-24), submitted on November 28,
2001. A CEC Staff Assessment dated January 24, 2003 concludes that all environmental
and engineering impacts have been addressed to a level of insignificance. However, the
CEC Staff has proposed mitigation of Air Quality and Visual Resources that has not been
agreed to by the applicant. The project's estimated on-line date is April I, 2005.33
3. South Bay Power Plant Repower (SBPP)
The California State Lands Commission approved the San Diego Unified
Port District's (Port District or Port) expenditure of $110 rnillion in public trust funds to
acquire the SBPP /Tom SDG&E on January 29,1999. The existing SBPP consists of four
natural gas-fired conventional boiler units and one 14-megawatt combustion turbine. The
main generation units were placed into service between 1960 and 1971 as reflected
below:
32 See California Energy Commission posting of Western Electricity Coordinating Council Area
Proposed Generation sites.
33 Id
60
APPENDIX C
TECHNICAL APPENDIX
South Bay Power Plant - In-Service Dates and Capacity
- Design-Life
In-8ervice Capacity Retirement Projections
Date (MW) Low High
Unit 1 1960 145 2000 2010
Unit 2 1962 149 2002 2012
Unit 3 1964 174 2004 2014
- Unit4 1971 222 2011 2021 (retired)
Total 690
-
Replacing the aging plant would increase regional natural gas efficiency,
delay the need for natural gas pipeline capacity expansions, and improve air quality. The
following chart shows the relative efficiency and emissions output of the SBPP compared
with that of a modern power plant,34 assuming SBPP's 2002 energy delivery. 35
South Bay Power Plant Efficiency and Emission Output (Tons)
Reference Volatile
- Heat Rate Nitrogen Carbon Organic
SIIIlIsWb Q¡¡i!IJ ~ Comoounds
South Bay Power Plant 10,300 87 518 35
Modem Power Plant 7,000 41 64 12
Modernization Reductions 32% 53% 88% 67%
Duke Energy North America's (Duke) lO-year lease with the Port District
to operate the SBPP went into effect in April 1999. As part of its $110 million ten-year
lease agrèement with the Port District, Duke must dismantle and relocate the existing
plant by 2009, According to the lease agreement, Duke must identify a specific
relocation site no later than June 2006 and publicize its site selection as part of an
application to the CEC for pennits to site the new plant.
The City derives revenue 36 /Tom having the SBPP on its bayfront and has
requested that a replacement plant be built near the current one, The City Council voted
in November 2001 to support relocating the plant just south of its current location at the
adjacent (35+ acre) LNG site, anticipating that the new plant could provide a substantial
revenue stream to help provide the infrastructure necessary to build out the Bayfront
34 Prototypical combine cycle generating turbine plant consisting of a 2-on-l (500 MW) and l-on-I
(250 MW) power trains, using three GE 7FA combustion turbines, three Nooter Eriksen triple
pressure reheat HRSGs and two GE steam turbines; includes five GE generator step-up (GSU)
transfonners.
35 CAISO 2002 Reliability Must Run (RMR) energy delivery 1,163,501 MWH.
36 San Diego County Tax Assessor's Office reflects 2002 depreciate plant value at $92.5 million and
property taxes paid $989,650.
61
APPENDIX C
TECHNICAL APPENDIX
development area. The City's request is being considered as part of the Port Authority's
master planning process. To date, Duke has screened about two-dozen sites, but has yet
to disclose prospective sites claiming that such disclosure would alert real estate
speculators, who would drive up property costs.37
Under Section ILC at 21-22, the MEV Study Team described in more
detail why power plant ownership and/or entitlement to energy output is tied to the cost-
effective operation of MEU structures examined in this report. However, potential -.
operational benefits are inextricably linked to the underlying value to the City of having
new power generation facilities located inside the Chula Vista tax rate area. Energy
supply arrangements that promote and ensure such facilities will be located within the
City's jurisdiction create value that must be captured in any cost-benefit equation.
Assembly Bill 81 (Migden) amended Property Tax Rule 905 on June 20, -
2002, effective January I, 2003, ensuring that cites hosting electric generation facilities
will receive property tax revenue therefrom.38 The effect of these actions is that the State
of California Board of Equalization will value and assess forty-two electric generation
facilities beginning with lien date 2003 including twenty older facilities divested by
CPUC regulated utilities (such as SDG&E) and twenty-two new facilities. The property
tax assessed value of an electric generation facility will be allocated entirely to that "tax
rate area" in which the facility is located. In this case the Chula Vista tax rate area
number is 0100.
Under this new rule, the value of the older divested as well as new plants
is currently in the process of being assessed. The older plants are more difficult to value
due to the weakness of using either the replacement cost new less depreciation
(weakness: quantifYing functional and economic obsolescence) or the discounted cash
flow income approach value indicator (weakness: reliance on highly subjective future
income estimates). The Board of Equalization will hold hearings between September and
December 2003 to finalize power plant assessed values. However, for reference, in 2002
the assessed, depreciated, value of the SBPP was $92.5 million and property taxes paid
by Duke were $989,650. New plants, such as the planned replacement for SBPP, will be
valued based on their replacement cost new less depreciation.
The MEU Study Team estimates the capital cost for contemporary power
plants (500-700 MW, with heat rates estimated at 7,000 BTU/kWh) to be $500 million.
If such a power plant were built within the Chula Vista tax rate area, City tax revenue
could be estimated at $3.23 million, annually. Depending upon whether the SBPP
relocates inside or outside the City will determine whether the City loses approximately
$0,745 million in tax revenue or gains $2.3 million in annual property tax revenue?9
Accordingly, energy supply arrangements that ensure such facilities will be located
37 Duke spokesman Patrick Mullen April 2003.
38 California Revenue and Taxation Code § 100.9 (a).
39 Based on analysis perfonned by Harrell & Company, provided by the City Community
Development Department.
62
.-._."__H. .....-.....------...--........--...---.....
APPENDIX C
TECHNICAL APPENDIX
within the City's jurisdiction create value and this value must be captured in any cost-
benefit equation, and considered when the City decides upon an ultimate course of action.
4. Significant Barriers to Power Plant Development
San Diego County is a non-attainment zone and new major emission
sources must be met with offsets /Tom other sources within the county. The San Diego
- Air Pollution Control District (APCD) Rule 20.3(d)(8) requires new stationary sources
that will emit more than 50 tons per year of NO x and volatile organic compounds (VOC)
to offset these emissions4O. The availability of NO x emission reduction credits (ERCs) is
limited in San Diego, which is a significant barrier to the building of new power plants.
Banked ERCs can be purchased or an interpollutant trade of VOC ERCs is allowed by
Rule 20.3(d)(5)(vi).41
-
-
40 This requirement may soon be changed to a threshold of 100 tons per year.
41 Sempra Energy has acquired emission credits for its proposed Palomar Plant in Escondido through
this mechanism.
63
APPENDIX C
TECHNICAL APPENDIX
II. FINANCIAL ANALYSIS ASSUMPTIONS AND PRO FORMA
This section of the Technical Appendix describes the methodology and
assumptions used to derive the financial pro forma results.
A. SDG&E Rates Forecast
SDG&E rates represent the reference point for cost savings created by
implementation of an MEU. Generation rates are sensitive to changes in natural gas
prices and changes in the composition of SDG&E's supply portfolio over time. It is not
sufficient to simply escalate current generation rates at an assumed inflation rate, Rather,
the MEU Study Team has developed a cost-of-service model to forecast the various costs
that make up SDG&E's generation rates. These costs include: (1) Utility Retained
Generation (URG) (including Qualifying Facility (QF) and Bilateral power purchase
contracts); (2) DWR power purchase contracts; (3) CAISO charges for ancillary services
and other charges; and (4) residual spot market purchases or sales.
The cost of service model enables consistency in assumptions regarding
natural gas prices and other factor input costs between forecasted SDG&E rates and the
costs of supplying a municipal portfolio, and facilitates a robust assessment of scenarios
incorporating varying natural gas prices.
The following chart shows SDG&E's projected rates for generation and
non-generation (delivery) services:
64
-
APPENDIX C
TECHNICAL APPENDIX
Chart 12: Projected SDG&E Retail Rates From 2006 Through 2023
SDGO. Rot. P"j.";D.'
,"D.OO
'6000
"'.00
,"000
~ '00.00
~ I I::~::~:=~""I
. 00.00
;¡
6000
".00
,"00
-----~,-----~._-~-=-
SDG&E rates are projected to remain relatively flat or slightly decrease
from 2006 through 2011 as a result of the gradual expiration of relatively high cost DWR
- contracts. Rates are projected to rise modestly from 2011 through 2023.
The components of SDG&E's revenue requirement are described below.
In developing the rate forecast, any excess or shortfall between the resources available to
SDG&E and SDG&E's load requirements (i.e., the residual net short) are assumed to be
sold to or purchased from the market at prevailing wholesale market prices.
1. Utility Retained Generation
As a result of implementing the state's generation divestiture policy in the
late 1990s, SDG&E has retained an ownership interest in only one generation project,
i.e., its 20% share of the San Onofre Nuclear Generation Station (SONGS) units 2 and 3.
Other resources in the utility retained generation portfolio are QF contracts and bilateral
contracts that SDG&E signed with generators and power marketers.
SONGS capital and operating and maintenance costs were obtained from
SDG&E's 2003 Cost-of-Service Filing with the CPUC (A.02-12-028). Annual SONGS
capital additions were projected based on the projections presented by SCE in its 2003
General Rate Case (A.02-05-oo4) and were recovered over the remaining life of the plant
65
APPENDIX C
TECHNICAL APPENDIX
based on current CPUC policy.42 Nuclear O&M expenses and decommissioning costs
were escalated according to the nuclear escalation factors contained in SCE's General
Rate Case. These escalation factors vary by year and range /Tom 2.06% to 2,95%.
Data for SDG&E's QF and bilateral power purchase contracts were -
obtained /Tom the Company's 2002 FERC Form I filing. Approximately 67% of
SDG&E's QF contracts are indexed to the price of natural gas, and these costs were
adjusted on an annual basis for projected natural gas price changes. Contract quantities --
were projected to decline over time based on data previously reported by SDG&E and
published in the consultant's report supporting the DWR bond financing issuance of
October 23, 2002. 43
URG costs were explicitly modeled through 2012, From 2013 through
2023, URG costs were escalated at a constant annual rate of 2.5%. -
2. DWR Contracts
-
The MEU Study Team modeled the DWR contract quantities; operating
dispatch parameters, and costs that were allocated to SDG&E in the CPUC's DWR
Contract Allocation Decision (D.02-09-053). Each individual contract was analyzed to -
determine pricing terms for energy and capacity, MW quantities, and operating
parameters or limitations. Operating hours for dispatchable contracts were modeled on a
monthly basis, based on the individual unit's heat rate, natural gas prices, and other -
operating parameters specified in the contracts. DWR contract quantities allocated to
SDG&E reach a peak in 2004 and decline to zero by 2013. The declining DWR contract
volumes are assumed to be replaced with purchases at the prevailing market prices.
3. Non-Generation Rates
--
Non-generation rates include charges for transmission, distribution, and
public purpose programs. These charges are assumed to escalate at an annual rate of
1.3% per year, starting with SDG&E's current non-generation rates as of June 2003 as -
the base. The Fixed Transition Amounts, which are the payments for the 1997 rate
reduction bonds that financed the 10% rate reduction provided to residential and small
commercial customers, are assumed to continue at the current levels until 2007, when
these charges are removed /Tom residential and small commercial customer rates.
-
42 SCE is the majority owner and operator of SONGS. Current CPUC practice is to determine the
costs of SONGS in SCE's General Rate Cases and then assign a portion of SONGS costs to
SDG&E's based on its ownership share of the plant.
43 See Official Statement, State of California Department of Water Resources, Power Supply
Revenue Bond, dated October 23, 2003, at Appendix A.
66
-
APPENDIX C
TECHNICAL APPENDIX
4. AB 265 Under-Collection
- AB 265 and related CPUC implementing decisions required SDG&E to
place a ceiling of 6.5 cents per kWh on the electric commodity rate for specified SDG&E
.- customer classes, primarily residential, small commercial, and lighting customers,
retroactive to June I, 2000. SDG&E was required to establish an account to record the
difference between the 6.5 cents per kWh rate ceiling and the actual commodity rate.
- The 6,5 cents per kWh rate ceiling expired on December 31, 2002, As of December 31,
2002, the under-collected balance was $215 million. The CPUC has allowed SDG&E to
maintain its rates above cost-of-service to help reduce the AB 265 under-collection.
.- Consistent with this practice, the MEU Study Team modeled SDG&E's Competition
Transition Charge (CTC) revenue requirement at the current $115 M for 2003 and 2004,
and any excess CTC revenue collected above the actual CTC costs are used to reduce the
- under-collections associated with the capping of customers' rates mandated by AB 265.
The CTC is assumed to revert to cost-of-service status in 2005.
- B. Electric Supply Costs
Under any MEU scenario, the City would need to produce or procure
- electricity to serve the load requirements of some or all of the electric customers within
the City. The primary cost drivers of electric supply costs are (1) the load profiles of the
MEU customers, and (2) the resources used to form the City's electric supply portfolio.
1. Load Profiles
The MEU Study Team constructed a composite load shape for Chula Vista
reflective of the City's customer mix and load profiles. The major customer classes
within the City comprise residential (SDG&E Class Load Profile DR), small commercial
(SDG&E Class Load Profile A), medium commercial (SDG&E Class Load Profile AL-
TOU, <500 KW), large commercial/industrial (SDG&E Class Load Profile AL-TOU, >
500 KW), and Street Lighting. The model assigns the annual projected kWh usage for
each customer class to each hour in the year using SDG&E's hourly load profiles for the
appropriate customer class. The class profiles are combined to form a composite load
shape for the City, and the composite load shape is summarized into monthly peak and
off-peak periods to conform to the supply products available in the wholesale market.
Load requirements are adjusted by distribution loss factors of 7% to represent
transmission grid level load requirements. Total monthly peak and off-peak energy
requirements projected for the City's first year of operations are shown in the following
chart:
67
APPENDIX C
TECHNICAL APPENDIX
Chart 13: Projected Monthly Load Requirements Of Chula Vista In 2006
C;ty 01 Chul. V;oto Mo"'hl, En..gy Requl"""...
- -
50,000
,",000
50,000
<
~ soooo
; -
¡¡¡ ,",000
. ,",000
- -
,",000
~ ~ ~ - ~ ~ ~ - ~ = - ~ -
2. Electric Supply Portfolio -
A variety of supply options can be utilized to meet the load requirements
of the City. The City can hedge its exposure to energy cost price risk through standard -
risk management techniques and instruments such as forward and futures contracts,
capacity contracts or other financial derivatives.
The City could assemble a supply portfolio comprising varying amounts
and types of resources including:
. Power purchase contracts (1 to 5 years) for peak and base load;
. Short-term contracts (quarterly up to 1 year in duration) for peak and base load;
. Renewable energy contracts for peak and base load. to comply with the -
Renewable Portfolio Standards mandated by AB 1078;
. Assignment of DWR contracts;
. Generation ownership; and -
. Spot market purchases.
The MEV Study Team evaluated a number of supply portfolios to
optimally serve the load requirements of the City. A typical supply portfolio would
utilize generation owned by the City or long-term contracts for the majority of projected
base load requirements. These long-term resources would be supplemented with short-
68
-
APPENDIX C
TECHNICAL APPENDIX
term contracts covering the additional seasonal load requirements of the portfolio,
- typically in the third quarter of each year. Spot market purchases and sales are used to
fill the residual net short load requirements.
- Common criteria among the supply alternatives is to manage risk by
limiting spot market purchases to 15% of the portfolio and ensure that the portfolio
meets, at a minimum, the Renewable Portfolio Standards (RPS) mandated by AB 1078.
- The RPS requires that renewable energy resources make up at least 20% of the portfolio
by 2017.
- The two primary supply scenarios evaluated for the CCA and MDU
options are (1) Generation Supply Strategy, and (2) Contracts Supply Strategy, Only the
Contracts Supply Strategy was evaluated for the Greenfield option because it would not
- likely be feasible to obtain an ownership interest in a generation project to match the
small and rapidly changing load requirements of the Greenfield development. The MEU
Study Team also evaluated a portfolio containing a pro-rata allocation ofDWR contracts,
but found that the cost of such a portfolio would exceed the costs of the Generation or
Power Purchase Contracts portfolios, including the exit fees related to bypassing the
DWR contracts.
a. Spot Market Prices
- The electric supply cost projections are based on a forward energy curve
modeled using the costs of an existing gas-fired resource as a proxy for the hourly
market-clearing price. The MEU Study Team's natural gas price projections used in
- creation of the forward energy curve are detailed in Appendix C in Sections m.D and E
at 116-119. Peak and off-peak prices are derivatives of the projected baseload prices.
Peak prices are modeled as 20% higher than average baseload prices, and off-peak prices
are modeled as 20% lower than average baseload prices.
The projected average electricity prices for baseload energy are shown in
the following chart:
69
-
APPENDIX C
TECHNICAL APPENDIX
Chart 14: Projected Average Electricity Prices For Baseload Requirements -.
-
PROJECT" AVERAGE ENERGV PRICE
moo
-
$5000
~ -
~ ""00
~
~ -
" "".00
,
:J
g -
moo
"'00 -
"""""" """""','oos"""""""'" """"0 """"""'00 "",""""""""202< 2022"'23
-
Current natural gas prices are at historically high levels and are projected
to remain so. If natural gas prices revert to lower levels, the City's cost savings would
increase. Reductions in natural gas prices will have a greater mitigating effect on the
City's electric supply cost of service relative to SDG&E's generation rates due to the -
existence of nuclear and fixed price contracts in SDG&E's supply portfolio whose costs
are insensitive to the price of natural gas. -
b, Power Purchase Contract Prices
Power purchase contract costs were modeled by developing a statistical -
relationship between published prices for forward peak contracts for energy in the South
of Path 15 Congestion Zone applicable to Southern California and the modeled forward
curve in 2005. The result is a 5% premium for fixed priced contracts relative to expected -
peak period spot market prices. This premium was extended along the forward curve to
yield estimated contract costs for the entire study period. The modeled contract prices
were independently validated against quotes obtained from the broker market for peak
and off-peak annual contracts for 2004 and 2005, and found to calibrate to within 2% of
these market quotes.
-
The Contracts Supply Strategy evaluated for the CCA and MOO options
includes the following fixed priced contracts:
70
-
APPENDIX C
TECHNICAL APPENDIX
Power Purchase Contracts - CCA/MDU Options
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 50 49 5 Years
2006 Peak (6 x 16) 75 59 5 Years
2011 Base (7 x 24) 50 51 5 Years
2011 Peak(6x 16) 75 61 5 Years
2016 Base (7 x 24) 75 51 5 Years
2016 Peak (6 x 16) 100 61 5 Years
2021 Base (7 x 24) 75 55 3 Years
2021 Peak (6 x 16) 125 66 3 Years
The electric supply portfolio evaluated for Greenfield includes the
following fixed priced contracts:
Power Purchase Contracts - Greenfield Option
Year Product Quantitv (MW) Price ($/MWh) Term
2006 Base (7 x 24) 5 49 4 Years
2006 Peak (6 x 16) 10 59 4 Years
2010 Base (7 x 24) 12 50 5 Years
2010 Peak (6 x 16) 15 60 5 Years
2015 Base (7 x 24) 15 51 5 Years
2015 Peak (6 x 16) 25 61 5 Years
2020 Base (7 x 24) 20 54 4 Years
2020 Peak (6 x 16) 25 65 4 Years
71
-------- ~
APPENDIX C
TECHNICAL APPENDIX
c. Renewable Energy Contract Prices --
Contracts for renewable power were modeled with a $3 per MWh
premium to the contract price of non-renewable power. The MEV Study Team derived
this premium from a historical analysis of "green ticket" 44 prices in California, as
reported by the Automated Power Exchange, Inc. (APX). APX published prices for
certificates for renewable power through December 2002, at which time the market was
suspended pending CPVC implementation plan for SB 1078 (Renewable Portfolio -
Standard). The prices of the certificates represent the premiums paid to sellers of
renewable power over and above the prices received by sellers of non-renewable power.
The RPS requires that the portion of the portfolio supplied by renewable resources
increase by I % per year.
The CPVC has yet to detennine how the standard would apply to a CCA, -
and it is not clear that a MDV would be required to meet the RPS. The MEV Study
Team has assumed that the City's portfolio would match the minimum standards
applicable to SDG&E in all of the MEV options. Accordingly, the portion of the -
portfolio comprised of renewable energy is established at 7% in 2006 and gradually
increases to 20% in 2017, consistent with RPS requirements.
-
The following renewable energy contracts were assumed in the
CCAlMVD and Greenfield portfolios for both the Generation and Contracts Supply
Strategy:
Renewable Energy Contracts - CCA/MDU Options
Year Product Quantity (MW) Price ($/MWh) Tenn
2006 Base (7 x 24) 7 52 1 Year
2007 Base (7 x 24) 8 51 I Year
2008 Base (7 x 24) 10 52 I Year
2009 Base (7 x 24) II 52 1 Year
2010 Base (7 x 24) 13 52 I Year
2011 Base (7 x 24) 15 53 I Year
2012 Base (7 x 24) 17 54 I Year
2013 Base (7 x 24) 18 54 1 Year
2014 Base (7 x 24) 20 54 I Year
2015 Base (7 x 24) 23 54 I Year
2016 Base (7 x 24) 25 53 I Year
2017 Base (7 x 24) 28 53 I Year
2018 Base (7 x 24) 29 55 3 Years
2021 Base (7 x 24) 30 58 3 Years
.. Green tickets are negotiated traded instruments that satisfy the requirements associated with
procuring renewable energy.
72
-
APPENDIX C
TECHNICAL APPENDIX
- Renewable Energy Contracts - Greenfield Option
Year Product Quantitv (MW) Price ($IMWh) Term
2006 Base (7 x 24) 1 52 I Year
2007 Base (7 x 24) I 51 I Year
2008 Base (7 x 24) 1 52 I Year
- 2009 Base (7 x 24) I 52 I Year
2010 Base (7 x 24) 2 52 I Year
2011 Base (7 x 24) 2 53 1 Year
- 2012 Base (7 x 24) 2 54 1 Year
2013 Base (7 x 24) 3 54 I Year
2014 Base (7 x 24) 3 54 I Year
- 2015 Base (7 x 24) 5 54 I Year
2016 Base (7 x 24) 5 53 1 Year
2017 Base (7 x 24) 5 53 1 Year
2018 Base (7 x 24) 7 55 3 Years
2021 Base (7 x 24) 8 58 3 Years
d. Generation Ownership
Generation options were modeled for the City using operating and cost
- parameters of a new combined cycle gas turbine operating as a base load plant. These
parameters include the unit's heat rate, capacity cost, variable O&M costs, availability
factor, hours of planned operation, and the year the resource becomes operational. Any
excess production beyond what is needed to serve the City's load would be sold into the
market. The price for excess capacity sales reflects a 25% discount relative to the
prevailing peak or off-peak price to reflect the probability that excess sales will occur in
the lowest priced hours of the on or off peak periods.
The following assumptions were used in the calculation of generation
costs:
Capacity: 130 MW
Technology: Combined Cycle Natural Gas Turbine
Year Online: 2006
Heat Rate: 7,000 BTU/KWh
Capacity Factor: 90%
Variable O&M: $2 Per MWh
Excess Sales: 75% of Market Price
73
-~
APPENDIX C
TECHNICAL APPENDIX
The electric production costs of City-owned generation are shown in the -
following chart:
Chart 15: Electricity Production Costs For City-Owned Combined Cycle Gas Turbine -~
Pow., P'oduction Coo"
,,~ 00
".00
".00
- -
~: -
.i
~ ".00
- -
06.00
'00
2006200'2<""200'200°"" 20022<"3200""""""""""'20202020 20222023
74
-
APPENDIX C
TECHNICAL APPENDIX
The following charts show the composition of the two primary supply
portfolios (Charts 16 and 18) and their respective average costs (Charts 17 and 19).
Chart 16: Loads and Resources On a Monthly Basis for 2006 - Generation Supply
Strategy
Lood. And R....".. By Mm'h
-
"".000
100.000
-
"'.000
-
-
-
"'.OOOj "C
JAN >0, MAR AeR MAY JUN Jue AUG SEe OCT NOV
-
-
-
-
-
75
APPENDIX C
TECHNICAL APPENDIX
Chart 17: Average Supply Cost By Resource For 2006 - Generation Supply Strategy
Gene,.';on supply PontoHo Ave..ge Cos' -
7Q.OO
60.00 -
5000
-
~ 4000
l
~ 3000 -
2000
-
10.00
POWER PAOOUCTION AENEWABLE ENERGY SPOT MARKET PUACHASES TOTAL PORTFOLIO (LOSS -
CONTRACTS ADJUSTEO)
Chart 18: Loads And Resources On A Monthly Basis For 2006 - Contracts Supply
Strategy -
Loeds And Resou,css By Month
-
"'.000
"'.000
-
70,000
60,000
.50,000
.!
¡ 40000
I
I 30.000
20.000
10,000
(10,000)
JAN FEe MAA APA MAY JUN JUL AUG SEP OCT NOV DEC
76
-
_._---
-
APPENDIX C
TECHNICAL APPENDIX
-
Chart 19: Average Supply Cost By Resource For 2006 - Contracts Supply Strategy
-
Contracts Supply Portfol;o Avera.s Cost
- 70.00
00.00
-
00.00
- ~ 40.00
.
~ 30.00
-
20.00
- 1000
LONG.TEAM CONTRACTS AENEWABLE ENERGY SPOT MARKET PUACHASES TOTALPOATFOLOO(LOSS
CONTRACTS ADJUSTED)
3, Portfolio Operations Costs
Portfolio operations costs are the costs associated with various activities
related to procuring electricity for retail customers. Portfolio operations activities include
load forecasting, procurement of electricity from wholesale electricity sellers, risk
management and controls. Activities related to retail pricing (load research, cost of
service, rate design) are also included in this cost category for purposes of the pro fonna
analysis.
Scheduling coordination costs are the costs associated with scheduling and
settling electric supply transactions with the CAISO. The analysis assumes the City
would become a CAISO certified Scheduling Coordinator, which would require
acquisition of scheduling and settlements software and operation of a 24 x 7 scheduling
desk.
Total costs of portfolio operations and scheduling coordination are
modeled as a combination of fixed and variable costs. Fixed costs, largely associated
with the minimum required personnel and computer systems, are estimated at $2,000,000
per year. Variable costs are estimated at $2.50 per MWh to account for increases in the
size and sophistication of the portfolio operations corresponding with increases in the
overall size of the utility.
77
-
APPENDIX C
TECHNICAL APPENDIX
Chart 20 below compares the total portfolio cost to the portion of the -
generation rate that would be credited by SDG&E for the initial year of operations in
2006. Total portfolio costs include the cost of the supply portfolio, ancillary services and -
portfolio operations and scheduling coordination costs. The total generation rate, net of
the CPUC imposed exit fees, represents the avoidable portion of the generation rate. To
achieve savings on the electric supply component of operations, the City must be able to
acquire generation resources that are below these SDG&E costs. Both portfolios -
modeled for the City would be below SDG&E's generation costs.
Chart 20: Total Portfolio Costs Compared To Estimated SDG&E Generation Credit -
-
Total Portfolio Cost Comp.,'" ro SDG&E Gon.,st;on c"'.
80.00 -
70.00
80.00 -
~ 50.00
~
~ 40.00 -
,g 30.00
20.00 -
10.00
--
Gene'.t;on Cont'.'ts SaG&E Gana,."on C",d;t
C, Non-Bypassable Charges -
1. CPUC Exit Fees
An important, but uncertain, element of MEU cost-of-service is the exit
fees that the CPUC will impose on Municipal Departing Load or load served by a
community choice aggregator. AB 117 and recent CPUC decisions require that exit fees,
also known as cost responsibility surcharges, be imposed on existing and new customer
load served by a community choice aggregator or new load served by a municipal utility
in a Greenfield area, or existing load served by a newly formed municipal utility that has
taken over the distribution system of the incumbent IOU. The categories of costs to be
included in exit fees and the methodological approach to their calculation have largely
been determined for direct access and Municipal Departing Load Customers. However,
78
-
APPENDIX C
TECHNICAL APPENDIX
the actual per kWh charges have yet to be detennined. On October 2, 2003, the CPUC
- initiated Rulemaking 03-10-003, which will, among other things, detennine the exit fees
that will be applicable to loads served by a CCA. Pursuant to a November 26, 2003
Administrative Law Judge Ruling in that proceeding, the issues regarding Community
- Choice Aggregation will be bifurcated into two phases, with the first phase addressing the
cost elements, including the amount of a CRS and any other applicable charges,
- The MEU Study Team has estimated the CPUC imposed exit fees based
on the record in the direct access cost responsibility surcharge proceeding (R02-01-011)
- using the DWR modeling scenario identified in CPUC Decision No. 03-07-030 as the
most reasonable scenario (Scenario 14).
- Exit fees for direct access customers are capped at $27 per MWh (2.7
cents per kWh). The cap was adopted by the CPUC to meet the objective of maintaining
the viability of existing direct access contracts. The cap is not assumed to apply to CCA
- and future MEU activities, and the full, uncapped exit fees were included in the
feasibility analysis. For SDG&E, the full cost exit fees are expected to be below the cap.
- Exit fees have been incorporated into the analysis in each of the scenarios
the MEU Study Team evaluated for the City. Exit fees are assumed to apply in all cases
of CCA, MDU, and Greenfield development, consistent with the CPUC's proposed and
- final decisions in rulemaking proceeding R02-01-011. Any changes to this assumption
would impact the results of the analysis.
The MEU Study Team analysis assumes that the CPUC will impose exit
fees on the City associated with the following costs:
. Uneconomic utility retained generation and power purchase contracts;
. DWR power purchase contracts; and
. DWR bond charges /Tom DWR financing of past power purchases.
Chart 21 below depicts the annual exit fee projections on a Base Case
basis:
79
APPENDIX C
TECHNICAL APPENDIX
Chart 21: Annual Exit Fee Projections - Base Case
";1 F.. .,o;o"h"'. - B... C...
".00
".00
".00
- -
i
.
l 8.00
,
.
~ 8.00 -
'.00
'.00
'00' """ ""'8 """ '008 "" "" "" "" "" "" "" "" "" "" "" "'" "" "" "" -
Consistent with the CPVC's exit fee methodology, the MEV Study Team -
independently calculated SDG&E's ongoing CTC and subtracted this component from
the exit fees adopted in R02-0l-01l to allocate the total exit fees between DWR Power
Charges and SDG&E's uneconomic VRG. The MEV Study Team adjusted the $43 per
MWh benchmark adopted by the CPVC for calculating the CTC to calibrate with
projected wholesale electric market prices in future years.
Due to the uncertainty regarding the magnitude of exit fees, a high exit fee
scenario should be considered. A reasonable basis for the high exit fee scenario is the
original base case DWR modeling run (Scenario 24) in the capping phase of ROI-Ol-
011. This scenario is based on gas price projections that are significantly lower than
current and projected natural gas prices, which tends to reduce the electricity price
assumed when the DWR contracts are sold into the market. In addition, this scenario
included the assumption that the DWR contracts are sold into the market at a discount of
50% relative to prevailing market prices. The resulting annual exit fees for the high case
scenario are shown in the following chart.
W -
---------
-
APPENDIX C
TECHNICAL APPENDIX
- Chart 22: Annual Exit Fee Projections - High Case
- Ex;tFeeP,ojoctions-H;9hCaee
35.00
30.00
35.00
,
< I
~ 2Q00 I
l
- , I
. ".00
~
".00
'00
--------,-----_._-~---
2. Other Non-Bypassable Charges
Three additional non-bypassable charges must be accounted for in the
MDU scenario. These are existing charges that were instituted at the time rates were
unbundled to facilitate direct access in the late 1990's. Because these charges are not
-- included in SDG&E's generation rates, it is not necessary to account for them in the
comparison of CCA costs to SDG&E generation charges. The CCA customers would
continue to pay these charges to SDG&E as part of the delivery services provided by the
utility. These charges include the following:
. Public Purpose Programs
. Nuclear Decommissioning
. Fixed Transition Amount
a. Public Purpose Programs
Public Utilities Code 385 authorizes and requires local publicly owned
electric utilities to collect through rates for local distribution service, revenue allocated to
public benefits programs.
Public benefit programs referred to include the following:
81
APPENDIX C
TECHNICAL APPENDIX
i. Cost-effective demand-side management services to promote energy -
efficiency and energy conservation.
ii. New investment in renewable energy resources and technologies (subject
to applicable statutes) -
iii. Research, development and demonstration programs for public interest to
advance science and technology that is not adequately provided by
competitive and regulated markets, -
iv. Service for low-income electricity customers, including, but not limited to,
energy efficiency services, education, weatherization, and rate discounts.
-
The amount of the public benefits charge (on a percent of revenue basis) is
the result of a complex formula set out in § 385, but must be "not less than the lowest
expenditure level of the three largest electrical corporations in California." Currently, the -
public benefits charge percentage for local publicly owned utilities is 2.85%. The
selection of public benefit programs to be funded by the charge is at the discretion of the
local publicly owned utility, but must conform to the statutory requirements of § 385. -
Other legislation applicable to local publicly owned utilities involves consumer
protection programs, and addresses such issues as low-income ratepayer assistance
programs, weatherization programs, public reporting of revenues transferred to a city's -
general fund, and development of renewable resources. Limited only by the categories of
"public benefits" set forth in the Code, municipal utilities have complete control over the
funds collected, and can use 100% of those funds within the community. Public Goods -
Funds collected from local ratepayers by the investor owned utilities can be used on any
number of programs approved the utility, and may never be expended within the
community in which they are collected. -
b. Nuclear Decommissioning Charges
-
These charges include costs related to the decommissioning of a nuclear
power plant. These costs will be non-bypassable until such a time as the costs are fully -
recovered.
c. Fixed Transition Amount (FTA) -
Sometimes referred to as Trust Transfer Amount (IT A), Residential and
Small Commercial customers benefit from reduced rates through the issuance of the Rate -
Reduction Bonds. The Rate Reduction Bonds were issued to enable these customers to
receive a discount on their bills of no less than 10% for the years 1998 through 2002. The
proceeds of the Rate Reduction Bonds are used to provide, recover, finance, or refinance -
transition costs and to acquire transition property. Residential and small commercial
customers would continue to pay fixed transition amounts after December 31 200 I, until
the bonds are paid in full by the financing entity.
82 --
APPENDIX C
TECHNICAL APPENDIX
D. CAISO Charges
1. Transmission
- Under the MDU and Greenfield options, the City would take wholesale
transmission service at the 115 KV voltage level and would be assessed CAISO charges
for high and low voltage transmission service. Transmission costs are based on the
currently effective CAISO transmission access charges applicable to the SDG&E area for
high voltage and low voltage transmission service. The transmission charges were
assumed to escalate at 1.3% per year. The first year transmission rates are shown below:
-
Charge Type Rate
High Voltage (Regional) Transmission Charge $2.33 Per MWh
Low Voltage (Local) Transmission Charge $3,05 Per MWh
Internal generation would enable the MDU or Greenfield operation to
avoid paying a portion of transmission access charges because the charges would be
applied on the net load delivered over the transmission grid. In a CCA scenario,
customers would continue to pay the retail transmission rates of SDG&E, which would
not be impacted by the supply strategy pursued by the CCA.
2. Other CAISO Charges
Charges for Ancillary Services (spinning reserves, non-spinning reserves,
regulation up, regulation down, and replacement reserves) imposed by the CAISO were
modeled as a constant percentage of the prevailing wholesale market prices and applied
to the CAISO's ancillary services requirements applicable to the City's load. City
generation can be used to self-provide certain ancillary services, and any self-provided
ancillary services are netted nom the ancillary services purchased /Tom the CAISO
markets. Grid Management Charges, and other CAISO charges were modeled at current
rate levels and escalated at 3% per year, These CAISO charges include:
Charge Type Rate
GMC - Control Area Services $0.62 Per MWh
GMC - Interzonal Scheduling $0.39 Per MWh
GMC - Ancillary Services and Real Time Energy $1.02 Per MWh
Reliability Services Costs $2.34 Per MWh
Congestion Costs $2.33 Per MWh
Grid Operations $0.05 Per MWh
Unaccounted for energy $0.76 Per MWh
Neutrality adjustments $0.34 Per MWh
Deviations charges Based on market prices
Internal generation would enable the MDU or Greenfield operation to
avoid paying a portion of these charges through netting of the internal generation /Tom
83
---------
APPENDIX C
TECHNICAL APPENDIX
gross loads. With the exception of Reliability Services Costs - which are not applicable
to CCA - internal generation may also enable the CCA to avoid a portion of these CAISO
charges through netting.
E. Distribution System Capital Costs -~.
Acquisition or construction of distribution assets represents the main
capital expenditures, outside the cost of generation development, associated with the
MDU option or Greenfield development. If the City decides to operate a utility
distribution system, it would be required to purchase SDG&E's distribution assets
including land, property and rights. Included in the cost of the acquisition would be the
expenses necessary to physically separate SDG&E /Tom the distribution facilities
purchased by the City (severance costs). An inventory and detailed assessment of the
distribution facilities within the City was outside the scope of this study, and the MEU
Study Team used average per customer distribution investment benchmarks to estimate
the value of SDG&E facilities within the City.
1. Valuation Methods
In the MDU scenario, an acquisition price must be detennined for the
existing SDG&E distribution assets. In perfonning distribution system valuation there
are several methodologies that may be applicable for the sale or purchase of facilities.
These valuation methods are fully described and discussed in Appendix B, Regulatory
and Legislative Issues, Section ILB at 30-33.
2. Analysis of Distribution System Capital Costs
The reasonable range of acquisition prices for SDG&E's distribution
facilities would be bounded by original cost or book value on the lower end and RCN on
the upper end. RCNLD would be within this range, and the MEU Study Team has used
RCNLD to estimate distribution acquisition costs in the MDU scenario. New distribution
facilities installed by SDG&E between 2003 and the 2006 MDU operation startup are
valued at replacement cost, with no adjustment for depreciation. This figure was also
used to calculate incremental distribution costs associated with customer growth of the
MDU.
The MEU Study Team has estimated these costs on a per customer basis
for the SDG&E system and applied the per customer figures to the number of customers
in the city to estimate total book value and RCNLD of the distribution assets in the
City.'s Estimated regulatory and litigation costs are also included in the MDU and
Greenfield scenarios.
" For street lighting customers, the projected customer numbers represent total numbers of lamps.
In reality, each service account represents several lamps. To convert lamps to service accounts,
the total projected annual kWh consumption for street lights was divided by 1,759 kWh, which is
the typical annual consumption per street light service account.
84
-_...._--~-_. .'-"..----.'------'-'----
APPENDIX C
TECHNICAL APPENDIX
Distribution system acquisition costs are estimated at approximately $170
million and total acquisition costs are estimated at $185 million as shown below.
-
Preexisting Facilities Amount
RCNLD Per Customer $2,021
- Existing Customers 78,462
Existing Distribution Cost $158,571,702
- New Facilities46 Amount
RCN Per Customer $3,000
New Customers 4,017
- New Distribution Cost $12,051,000
Total Distribution Cost $170,622,702
-
Other costs related to the acquisition are estimated at $15 million as shown
below:
-
Categorv Amount
- Regulatory/Litigation $3 million
Inventory $2 million
Severance $10 million
Total Other Acquisition Costs $15 million
Total Distribution Cost $170 million
Other Acquisition Costs $15 million
Total Acquisition Costs $185 million
- Annual debt service to support this investment would be approximately
$20.2 million at an assumed taxable debt interest rate of 6.5%.
Greenfield Facilities
For Greenfield development, the $3,000 per customer replacement cost
new figure was used to estimate construction costs. This figure was also used to calculate
incremental distribution costs associated with customer growth of the Greenfield utility,
Distribution facilities costs are estimated at $12.1 million and total
distribution infrastructure costs are estimated at $13.8 million as shown below.
46 The cost for the acquisition of new facilities assumes that the City does not elect to pursue the
Greenfield development option. If that option is pursued, these costs of$12.1 million would be
subtracted from the distribution system acquisition costs to yield an acquisition cost of
approximately $158.5 million.
85
APPENDIX C
TECHNICAL APPENDIX
New Facilities Amount
RCN Per Customer $3,000
Customers 4,017
Distribution Facilities Cost $12,051,000
Distribution Facilities Cost $12.1 million
InterconnectionlWDA T $0.7 million --
Regulatory/Litigation $0.5 million
Inventory $0.5 million
Total Distribution Cost $13.8 million -
To detennine the book value of the existing distribution system, it is only
necessary to subtract its accumulated depreciation /Tom its original cost. To further -
detennine distribution system asset value requires consideration of the cost today to
replace the system referred to as replacement cost new or RCN. Once the RCN is
detennined, it is then possible to detennine the Replacement Cost New Less
Depreciation.
The first step that the MEU Study Team took to detennining the potential --
value of the distribution system within the City was to look at SDG&E's latest FERC
Fonn I (2002) to detennine the original cost of all ofSDG&E's distribution system. This -
cost is then compared to the total number of SDG&E's customers to arrive at a cost per
customer.
SDG&E's Original Cost of the Distribution Plant - $2,700,975,584
SDG&E total customers 1,255,268
SDG&E Original Cost per Customer $2,151.71
The next step was to arrive at the current or booked value of SDG&E's
distribution system that is the original cost less accumulated depreciation. Again
SDG&E's 2002 FERC Fonn I was the reference point.
SDG&E Net Book Value for Distribution Plant $1,542,105,376
SDG&E Total Customers 1,255,268
SDG&E Book Value per Customer - $1,228.51
With these two reference points it is possible to use the Handy-Whitman
Index to detennine the Replacement Cost New Less Depreciation (RCNLD) for
SDG&E's distribution system. The Handy Whitman Index of Public Utility Costs is a
widely used publication used to trend original cost valuations to present day
reconstruction costs. Utilizing the Handy Whitman Index requires knowledge of the
original cost and the time of the original cost investment. Typical depreciation for
distribution plant is 30 to 40 years. The original cost of SDG&E's distribution system
and its current book value indicates the system is approximately 43 percent depreciated.
86
------------------- ...-.----.-------------------.--.
APPENDIX C
TECHNICAL APPENDIX
If the average depreciation period is 30 years the average age of the system is
approximately 13 years. If the average depreciation period is 40 years, the average a~e of
the SDG&E distribution system is 17 years. Hence, the Handy Whitman Index4 for
1989 and 1985 (13 and 17 years ago) were utilized to detennine the potential replacement
cost of the SDG&E distribution system.
Original Cost per Customer $2,151.71
2002 Handy Whitman Index 366
1989 HWI 277
1985 HWI - 250
Cost of Replacement per Customer (1989 HWI) $2,843.06
Cost of Replacement per Customer (1985 HWI) $3,150.11
Based upon these two ranges of potential replacement costs, the MEU Study team used a
replacement cost of $3,000 per customer. Therefore, the RCNLD for the total SDG&E
system is as follows:
-
Replacement Cost New per Customer $3,000
Number of Customers 1,255,268
- Total Replacement Cost $3,765,804,000
Accumulated Depreciation $1,228,828,000
RCNLD $2,536,975,505
RCNLD Per Customer - $2,021
F. Distribution System Operations and Maintenance Costs
The MEU Study Team used the results of a nationwide benchmarking
study of municipal electric utilities to estimate distribution O&M costs for the City. The
study groups municipal electric utilities by size into five strata and reports average per
customer O&M costs within each strata for distribution O&M, customer service
expenses, and administrative and general expenses. The average total annual distribution
O&M costs reported by participants in the study range from $246 to $594 per customer,
reflecting a wide range of urban and rura1 municipal utilities of various sizes and
population densities.
The MEU Study Team has also used a targeted set of case studies of
California municipal electric utilities to obtain O&M estimates that would be more
reflective of the costs expected for the City municipal electric utility. Data are available
for years 1998-2001, and the average total annual distribution O&M costs range from
$231 to $380 per customer. For this analysis, the four-year average per customer O&M
costs of California municipal utilities of similar size as Chula Vista was used to predict
the cost for distribution operations. Four municipal utilities with between 50,000 and
90,000 customers were selected. These were Burbank, Glendale, Pasadena, and the
Turlock Irrigation District.
47 The MEV Study Team used the Handy WIlltman Index for the Pacific Region in this analysis.
87
~~--~~- -~----------~._-_._._~.__.~ .~-----
APPENDIX C
TECHNICAL APPENDIX
Based on this analysis, the average annual O&M cost estimated for the
City is $270 per customer.
By comparison, the MEU Study Team has calculated the average
distribution O&M costs for SDG&E, using 2002 FERC Fonn I data, of $198 per
customer.
Categorv Amount
Distribution O&M $76,310,456
Customer Service O&M $78,025,205
Allocation of A&G $94,739,319
Total Distribution O&M $249,074,980
Total Customers 1,255,268
Distribution O&M Per Customer $198
The lower figure for SDG&E reflects economies of scale in distribution
operations that are not available to smaller distribution systems. The higher per capita
O&M costs typical of smaller utilities are offset to a degree by the capital financing and
tax advantages of municipal electric utilities.
G. Utility Financing
The City would have strong financing advantages relative to SDG&E due
to its lower cost of capital arising /Tom access to low cost debt and exemption /Tom
federal and state income taxes. The MEU Study Team's analytical model enables a
variety of financing assumptions for the capital requirements associated with distribution
or generation investments. Configurable assumptions include the cost of debt, the length
of the debt tenn, the capital structure or debt ratio, and the debt coverage ratio.
Tax-exempt financing is not applicable to the acquisition of existing
distribution assets and was not used in the analysis. Tax-exempt financing was only
assumed to be used for all new distribution and generation facility development. The
following financing assumptions were used in the analysis:
Capital Expenditure Tax Status Annual Rate Tenn
Generation Development Exempt 5.5% 30 Years
Distribution Acquisition Taxable 6.5% 30 Years
Capital Additions Exempt 5.5% 30 Years
H. Additional Cost Considerations
1. Franchise Fee Impacts
Acquisition of SDG&E's distribution facilities negatively impacts the
88
--------------....-.------- ------------------------.
APPENDIX C
TECHNICAL APPENDIX
City's /Tanchise fees revenues and is assumed to trigger a requirement for in lieu
payments of lost county property taxes. Lost /Tanchise fee payments are included in the
financial analysis as a cost of the municipal electric utility operations. The $881,077 in
ITanchise fees paid by SDG&E to the City in 2002 was escalated at an annual rate of
2.5% throughout the study period,
2. In-Lieu Property Tax Payments
-
In-lieu payments to San Diego County for lost property tax revenues were
estimated using the County of San Diego's tax rate applicable to Chula Vista (1.0732%),
.- and then applied to the estimated value of SDG&E's distribution assets in the City.
Foregone property taxes are estimated at $1.8 million per year.
- Foregone property taxes and in-lieu payments are accounted for as
additional costs of operating the municipal electric utility in the financial pro-fonna
analysis. The economics of the MDU must overcome these additional costs in order to be
viable, and the savings shown in the pro fonna results have already accounted for these
opportunity costs.
- I. Pro Forma Analyses
The following attachments (pp. 90-98) are the financial pro fonna
analyses developed by the MEU Study Team for the evaluated MEU options:48
Pro Fonna Su I Strate
I CCA Generation
2 CCA Contracts
:3 Greenfield Contracts
4 CCA and Greenfield Generation
5 CCA and Greenfield Generation
6 CCA and Greenfield Contracts
7 CCA and Greenfield Contracts
8 Munici al Distribution Utili Generation
9 Munici al Distribution Utili Contracts
The financial pro fonna of the Natural Gas Utility option discussed in
Section IV.H of the Report is also attached at 99.
48 These pro Connas are in a separate Excel file in the electronic version ofthe Report.
89
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APPENDIX C
TECHNICAL APPENDIX
III. NATURAL GAS SUPPLY FOR POWER GENERATION
A. Natural Gas Supply Outlook
The United States Geological Survey (USGS) estimates a resource base in
the United States of approximately 1,000 Trillion Cubic Feet (Tct), which, when
combined with a Canadian resource base of approximately 500 Tcf, yields enough natural
gas in the ground to meet demand for 50 years, The Energy Information Administration
(EIA) in "u. S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2001 Annual
Report" (November 2002) reported a level of proved and probable reserves of 1,431 Tcf
for the Lower-48 states. A December 1999 report of the National Petroleum Council
(NPC) reported a resource base of 1,466 Tcfin the Lower-48, 333 Tcfin Alaska, and 667
Tcfin Canada, for a total of 2,289 Tcf. The EIA estimated reserves would be sufficient to
sustain current production levels of approximately 20 Tcf per year for the next 65 to 70
years. The NPC estimated reserves would be sufficient for more than 100 years.
By either count, the total reserve base, combined with an understanding of
reserve appreciation and the role of technology in recovering these reserves, leads to a
conclusion that a large natural gas resource base exists and supports the corollary
conclusion that reserves are adequate to meet market demand in the United States.
1. California Gas Supply
Five different supply basins produce natural gas available for consumers
in California as well as to other markets.49 These supply basins include: the San Juan
basin, located in the Four Comers region (New Mexico, Arizona, Utah, and Colorado);
the Permian Basin of eastern New Mexico and West Texas; the Rocky Mountain
producing areas in Wyoming, Utah and western Colorado; the Sacramento basin in
California; and the Western Canadian Sedimentary Basin (WCSB) that covers most of
Alberta and extends into northeastern British Columbia and southwestern Saskatchewan,
These basins contain proved reserves totaling some 135 Tcf. Proven reserves and general ~
production levels from these supply basins are shown in Table 1. .,
l"
:;¡
5
~
~
'I'
49 A map showing the location of these supply basins and the pipelines that deliver their production I
to California are shown in Figure 1. ¡
j
"I
101 i
I
APPENDIX C I I
TECHNICAL APPENDIX
Table 1 -
Supply Basin Characteristics ...
-
Proved Production
Basin Reserves (Tcflyr,) I'
(Tct)
WCSB 68,0 5.9
San Juan 13,9 1.1 I
Permian 13.1 1.5 I
Rockies 36.8 1.1 Ii
California 3.2 0,3
TOTAL 135 8,9 I
While production /Tom the indicated basins can flow to markets other than
California markets, those other markets tend to be fully served with supply /Tom other I
basins that can reach them more economically than can supply /Tom these western
production areas. Production from the supply basins tabulated above at least historically
has been delivered primarily to California. I
According to the EIA, California is the nation's second largest consumer
of natural gas. In 2001, California averaged approximately 6.6 Bcf daily use, Table 2 I
below contains recorded and forecasted natural gas consumption in California by sector,
with 2001 reflecting the latest recorded data. Residential and commercial demand was
fairly constant over the period, generally reflecting the variations in weather, while I
industrial usage was more variable over the same period. The electric generation (EG)
sector grew more than 1,000 MMcfd over the five-year period, This increase occurred as
merchant power plants and cogeneration facilities came on line and California's economy I
grew,
Table 2
Recorded California Gas Demand I
Average Daily MMcfd
Electric I
Year Residential Commercial Industrial Generation Total
1997 1,312 696 1,970 1,633 5,611 I
1998 1,507 773 2.044 1,788 6,101
1999 1,556 671 1,989 1,981 6,197 I
2000 1,414 674 2,126 2.449 6,663
2001 1,405 674 1,825 2,677 6,581
Recorded Data Source: Energy Infonnation Administration I
I
102 I
APPENDIX C
TECHNICAL APPENDIX
California gas utilities are required to provide to the California Energy
Commission compiled operational data and forecasts annually in The California Gas
Report (CGR). Recorded and forecast data contained in Table 3 below was provided by
SDG&E in the 2002 CGR. The forecast years assumes average temperature years. The
demand projection SDG&E submitted for the CGR assumes that virtua1ly all new electric
generation will be built outside their service area and that existing EG demand will be
displaced by power imported /Tom Mexican generation projects.
Table 3
SDG&E Average Daily Demand
MMcfd
Year Core Noncore EG Total
Recorded Years 1997-2001
1997 120 29 178 329
1998 134 26 204 364
1999 144 22 179 349
2000 132 21 228 388
2001 139 12 276 424
Forecast Years 2002-2022
2002 140 9 179 331
2003 147 6 88 243
2004 146 6 86 241
2005 147 6 116 271
2006 148 6 117 274
2007 151 6 119 278
2010 158 6 126 293
2015 168 6 199 376
2020 178 7 215 402
2022 182 7 221 413
SDG&E also forecasts Finn Service Demand (FSD), which corresponds to
the l-in-l0 cold-year reliability standard for flnn noncore service. FSD has a 10%
probability of occurring in any given year; all else equal, it should be expected to occur
once in every ten years. The firm noncore demand represented in the Table 4 below is
forecast average daily demand for all noncore customers. Thus, noncore peak demand is
not included.
--
103
...~-
APPENDIX C
TECHNICAL APPENDIX
Table 4.
Forecast Firm Service Demand
Firm
Year Core Noncore Firm EG Total
2003 385 64 70 519
2004 388 64 67 519
2005 392 64 65 521
2006 398 64 100 562
2007 404 64 136 604
2008 409 64 170 643
2009 413 64 174 651
2010 419 64 177 660
2011 424 65 181 670
2012 429 65 184 678
2013 435 65 188 688
2014 439 65 192 696
2015 444 65 196 705
2016 449 65 199 713
2017 454 65 203 722
The current import limitation into SDG&E's service territory is 640
MMcfd; hence the possibility of curtailment arises as early as 2008 according to
SDG&E's FSD.
2. Natural Gas Transportation Infrastructure
Five interstate pipelines bring natural gas /Tom the western supply basins
to serve consumers in California. These pipelines can deliver nearly 8 Bcf (see Table 5
below) of natural gas per day into California. Figure I below illustrates the location of
natural gas production basins and the pipelines that connect these supply areas to
California.
The pipelines into California are the following:
(I) PG&E Gas Transmission - Northwest (PG&E GT-NW), still commonly
known as PGT), a unit of PG&E Corporation's National Energy Group,
delivers Canadian gas to California. PGT is currently fully subscribed, the
primary shippers are PG&E, natural gas marketers, and producers.
(2) Two interstate pipeline companies, EI Paso Natural Gas and Transwestern,
transport supplies produced in the Permian basin of West Texas and
Southeastern New Mexico into California. Transwestern follows a
northern route to pick up San Juan basin supplies from its San Juan
104
APPENDIX C
TECHNICAL APPENDIX
Lateral, and then proceeds to California terminating at Topock, and
Needles, California, EI Paso's southern system follows a route roughly
paralleling the Mexican border to California, while its Line 1300 parallels
Transwestern ftom Permian to San Juan where it connects to EI Paso's
northern system (San Juan basin to Topock),
(3) Rocky Mountain supply is delivered to California primarily via Williams
- affiliate Kern River Gas Transmission (Kern River), Kern River has a
delivery capacity of approximately 1.8 Bcf per day to the California
border, with the 2003 Expansion adding 0,9 Bcfper day. Much of this gas
- is delivered to directly connected end-users in Kern County, and large
cogeneration projects near Bakersfield, or is delivered into the SoCai Gas
system, or is utilized in growing markets in Utah and Nevada, Kern River
- is fully subscribed, primarily by shippers who own production in the
Rockies and market their own production. Kern River has access to
Canadian supplies by means of a connection with Northwest Pipeline at
- Muddy Creek in the vicinity of the Opal Hub. Northwest moves Çanadian
supplies south /Tom Sumas, Washington and Rocky Mountain supplies
-- north ftom Opal for delivery to PGT at Stanfield, Oregon.
-
--
-
-
-
-
-
- 105
APPENDIX C
TECHNICAL APPENDIX
Figure 1
Western Natural Gas Pipelines
WESTERN NORTH
AMERICAN
NATURAL GAS PIPELINES
(Nollo Scale)
CD TCPL BC System (ANG)
@ EI Paso
ø Kern River
0 Mojave
(j) Northwest
(j) TCPLAlberta System (NOVA)
ø Paiute
(j) PG&E
(j) PG&E GT-NW
@ SoCalGas
@ SDG&E
@ Transwestern
@ Tuscarora
e Alliance
@ Northern Border
@ Foothills
@ Trailblazer
@ Williams
@ KN
@ GIG
@ TCPL Mainline
Source: CEC
(4) Mojave is an extension of EI Paso and Transwestern that cross into
California at Topock. It proceeds to Daggett, California, paralleling lines
owned by PG&E and SoCal Gas, where it connects to Kern River. Kern
River and Mojave then continue as a single pipeline, operating jointly, to
Bakersfield.5O Mojave allows another 400 MMcf per day to enter
California, but receives its supply /Tom either El Paso or Transwestern. El
Paso has border capacity totaling 3.29 Bcf per day, sufficient to
accommodate Mojave.
(5) Questar Corporation purchased what was known as Line 90 (an oil
pipeline) /Tom ARCO, renamed it the Southern Trails Pipeline and
converted it to transport natural gas in 2002. The converted line is
50 Because of the "pipe within a pipe" structure and joint operations beginning at Daggett, the two
pipelines are ftequently referred to as the "KernlMojave system."
106
APPENDIX C
TECHNICAL APPENDIX
currently capable of transporting 90MMcfper day nom the San Juan basin
and Rockies and terminates near the California border at Kingman,
Arizona and into the SoCai Gas system, This pipeline is not shown in
Figure I.
The capacity of all pipelines to California is tabulated in Table 5,
Table 5
Pipeline Capacity into CaliforniaSt
Bcf/day
Pipeline Capacity
(R"f n..r ti~v)
PG&E-GT Northwest 1.940
Transwestem 0.800
EI Paso Natural Gas 2.890
Kern River Gas Transmission 1.724
Mojave 0.400
Questar Southern Trails
0,090
Total 7,844
At the current time, significant natural gas demand is forecast to increase
particularly in the Desert Southwest area. The Desert Southwest is located directly east
and adjacent to some of the same major interstate pipeline capacity listed above which
serves the southern Califomia and San Diego areas. Over the last several years, the
Desert Southwest has attracted a proliferation of gas fired cogeneration capacity, some of
which is already on-line and more of which is scheduled to come on-line over the course
- of the next few years, Other gas load growth in the area has occurred as a result of the
double-digit annual growth rate percentages in the population base over the last half
decade or more, especially in the Las Vegas and Phoenix metropolitan areas. While
- certainly the strengthening demand growth in the Southwest could be seen as competition
for Southern California requirements, natura1 gas market forces have responded to this
market dynamic.
-
New pipeline capacity has been built accessing new supply from the
- Rockies with the Kern River pipeline expansion of 900 MMcf/d of capacity coming on-
stream in April of 2003 delivering to meet load growth in the southwest and Southern
California. Several other natural gas pipeline projects are proposed for the Desert
- Southwest including the 750 MMcf/d Silver Canyon Pipeline /Tom the Rockies,
" Pipeline capacity is adjusted for iniraState take-away capacity at the California border.
-
- 107
- I I T^~^~ I - ~- '------/ I "'" A
APPENDIX C
TECHNICAL APPENDIX
Transwestern's 1 Bcf/d Sun Devil pipeline proposal, the 750 MMcf/d Coronado Pipeline
proposed by several San Juan producers, the 1 Bcf/d Pichacho oil pipeline conversion
project across the southwest into SoCai Gas and the expansion of the Baja North pipeline
to access new LNG gas supply from projects planned in the Baja California peninsula of
Mexico, The composite of all this is that (1) the natural gas resource base exists currently
and likely for the useful life of new generation to be built over the next few years and, (2)
that adequate gas pipeline infrastructure has been proposed with some built and more
likely to be built to serve the growing needs of both the Desert Southwest and Southern
California market areas,
3. Basis Differentials
Relevant to the construction of new pipeline capacity is the role of basis
differentials, Basis differentials are a function of supply available /Tom a given basin, the
cost of the transportation to move it to market, and which basin provides the marginal
supply, They reflect the relative balance of supply versus demand in a given market and
the cost of alternative supplies available to that market. In general, the marginal supply
sets price; the infra-marginal suppliers sell at that same price, netting out their cost of
transportation and other expenses fTom the revenues they receive. The price differentials
between supply basins and markets or between one supply hub and another are known as
"basis differentials." These differentials capture the differences in the value of supply
between locations, A high basis differential occurs when demand in a given market is
high relative to the supply available to serve it. Conversely, low differentials suggest
over-supply relative to demand between a supply basin and its market,
Figure 2 below compares the average gas cost at major supply basins and
market centers to the cost of pipeline transportation for various North American
transportation links over the first six months of 2003. Supply basins are denoted with
circles; market centers denoted by squares. The lines connecting supply basins to
markets show the maximum tariffed cost of transporting gas /Tom supply basins to
market centers, New transportation is not likely to be built between that supply basin and
market center until the basis differential reverses and grows to be larger than the current
cost of transportation, The ability to earn such economic rents would attract the new
entry needed to add transportation infTastructure. For example, the basis /Tom the San
Juan and Rockies basins and the Southern California in Figure 2, In both cases the basis
are substantially above the existing transportation rates to the Southern California border.
These basis differentials are what attracted pipeline projects to be proposed to allow
shippers on the pipelines the opportunity to capture some of the margin from holding
capacity on these pipelines.
108
---,,---,----- - --""-'-""'-'-"--------' _m._."_..- .. ---~---~- -,.-..
APPENDIX C
-- TECHNICAL APPENDIX
Figure 2
- U. S. Major Supply Basin and Market Center Prices
January - June 2003
-
-
-
-
-
-
-
-
-
4. California Intrastate Transportation
- Transportation within the state of California, with the major exception
created by Kern River and Mojave as interstate pipelines subject to federal jurisdiction, is
currently the domain of the state's two large gas distribution companies, PG&E and
- SoCai Gas, and a handful of other gas distribution utilities or municipal utilities -- such as
SDG&E, Southwest Gas, and the City of Long Beach. SoCai Gas and PG&E both take
gas from the interstate pipelines that terminate at the state line and move it to the state's
- major load centers, serving additional communities along the way.
- SoCai Gas' backbone pipeline system covers southern California from the
San Joaquin Valley south to the Mexican border. SoCai Gas' system delivers gas to its
own local transmission system (for delivery to core and noncore end-users), SDG&E, the
- City of Long Beach, some large industrial generators and customers, and to storage.
Figure 3 shows the SoCai Gas backbone transmission system.
-
109
APPENDIX C ---
TECHNICAL APPENDIX
Figure 3 ---
Southern California Backbone Transmission System
---
"'.. ---
---
w+, \<::.. ,"..... ---
'::;::;~~,;:""::~:' /"'------- -' ."...
......
"GEND ,
0"""""""""'000"""" ---
ð. """"'H""'"......"" !
.&. """H""'..,."",.
lID "'H""'"
- """""""""H ---
.."
"'" .""
---
Source: SoCai Gas
With recent additions of capaciry52 from expansion projects totaling 375 ---
MMcfd, California SoCai Gas' transmission system gas available firm backbone capacity
of 3,875 MMcfd is divided among the receipt points tabulated in Table 6 below.
---
---
---
" The expansion projects include: Kramer Junction, 200MMcfd; Wheeler Ridge, 85 MMcfd; North
---
Needles, 50 MMcfd; and Line 85, 40 MMcfd.
110 ---
---
------------~------------- ------------
APPENDIX C
TECHNICAL APPENDIX
Table 6
SoCal Gas Backbone Receipt Point Capacity
SoCal Gas Receipt Point Capacity, MMcfd
Blythe (Ehrenberg) 1,210
Topock 540
North Needles 750
North Needles Expansion 50
Hector Road 50
Wheeler Ridge (North) 520
Wheeler Ridge (South) 245
Line 85 190
North Coastal 120
Kramer Junction 200
Total 3,875
B. SDG&E Gas Transmission System
The SDG&E natural gas delivery system is capable of delivering 640
MMcf/d of gas on a firm basis to core and non-core customers, With one major
exception, SDG&E customers have experienced few curtailments of gas service. 53 In the
past SDG&E's interruptible customers have enjoyed a high level of service in spite of
their interruptible service due to SDG&E's Abnormal Peak Day (APD) planning criteria.
This l-in-35-year criterion provides for a design that meets CPUC standards of least cost
planning, and serves the interests of core customers. Non-core and EG customers
however who suffered the curtailments in 2000/2001 were not as satisfied with the old
standard and demanded a new planning and curtailment system. The Comprehensive
Settlement Agreement (CSA) (OIl 00-11-002) directed SDG&E to adopt a I-in-IO (one
curtailment in ten years), cold year conditions, reliability standard for SDG&E, for the
core and non-core customers.
This change in curtailment standards alone was a step in the wrong
direction in adding additional reliability assurances for the non-core. However these
changes, combined with other safeguards that were included in the CSA (e.g., allowing
SDG&E to only offer firm non-core service when it has the capacity and authorizing
curtailments to EG's on a pro-rata basis and curtailment of firm service for non-core
customers on a rotating block basis in the event curtailments /Tom the EG's is
insufficient), should serve to help EG and non-core customers. Prior to the adoption of
pro-rata curtailments for EG's, SDG&E's Gas Tariff Rule 14 provided for curtailments,
53 SDG&E curtailed service to firm noncore customers on 17 days between November 2000 and
March 2001 during the height of the California energy crisis.
111
APPENDIX C
TECHNICAL APPENDIX
including non-core commercial and industrial customers and EG's on a rotating block
basis. Other provisions in the CSA directed SDG&E to file reports with the CPUC twice
per year on its capacity planning, demand forecast and status of expansion projects. This
provision is directed at improving the system planning process by SDG&E to further
improve service reliability.
The primary pipeline facilities on the SDG&E system consist of a 3~-inch
diameter pipeline and a 16-inch diameter pipeline that extent south /Tom the Rainbow
meter station at the Riverside-San Diego county line, The 30-inch line heads west fÌom
Rainbow and the 16-inch line leaves Rainbow and heads directly south. The two local
transmission lines are interconnected in two locations as they head south.
SDG&E also owns and operates a major compressor station at Moreno
Valley, situated 33 miles north of the San Diego county line. SDG&E installed this
compressor station in SoCal Gas service territory to boost the pressure coming off of their
major transmission line bringing gas in from the Southwestern gas basins, The Moreno
station provides pressure to the SoCal Gas lines 1027, 1028, and 6900 that comprise the
Moreno-to-Rainbow transmission corridor. Line 6900 was expanded by 70 MMcf/d in
2001, which increased the SDG&E system capacity to 640 MMcf/d from 570 MMcf/d.
Figure 4 below shows local pipeline infTastructure and existing and
proposed power plant locations on the SDG&E system, In addition to the South Bay,
Encina and Otay Mesa locations, we show existing and proposed power plants in the
vicinity of Mexicali, Mexico, and the proposed Rosarito Power Plant inTijuana.
112
APPENDIX C
TECHNICAL APPENDIX
Figure 4
SDG&E and Area Pipeline Infrastructure
~o"',,'
M.."'"
Foci",
~
-"
E. Gosod- ..-.
Baja California
--
Source: PG&E NEG; additional detail by NCI
While not strictly part of the SDG&E intrastate system, but increasingly
important and integral to the SDG&E system (not unlike the SoCal Gas system is some
respects), is the Mexican North Baja Pipeline (NBP) immediately to the south of the
SDG&E service territory and shown in Figure 4.
This pipeline is owned by PG&E National Energy Group (PG&E NEG)
and its 50% partner Sempra Energy. The NBP was completed in March 2003 and has
capacity to transport up to 510,000 MMBtu per day of natural gas from an interconnect
with El Paso Natural Gas at Ehrenberg, AZ into California at Blythe. The pipeline
crosses into Mexico east of Mexicali, and continues westerly across northern Baja
- California, and terminates at an interconnection with TGN Pipeline between Rosarito,
Mexico and San Diego, some 8-9 miles south of the U.S. - Mexico international border.
The pipeline serves power projects at Mexicali and Rosarito, Mexico. The 77-mile U.S.
segment of the pipeline is operated by PG&E National Energy Group, and is regulated by
the FERc. The 135-mile Mexican portion of North Baja Project is the responsibility of
Sempra Energy International and Proxima Gas, and is regulated by Mexico's Energy
Regulatory Commission (CRE). Indirectly interconnected to the NBP, SDG&E's
Pipeline 2000 and associated export facility was placed in service in April 2000 with
capacity of up to 300,000 MMBtu per day. The Mexican portion of the line, commonly
referred to as either Rosarito Pipeline or Transportadora de Gas Natural de Baja
-
113
----~----------~--- --- ---~~----------~-
APPENDIX C
TECHNICAL APPENDIX
California (TGN), is owned by Sempra Energy International (a partner in NBP). The
TGN line extends into Mexico some 23 miles to Rosarito, where it serves an existing
power plant, the Presidente Juarez. Prior to completion of the North Baja Pipeline,
SDG&E delivered approximately 90,000 MMBtu per day into TGN for use at Rosarito.
Upon completion of the North Baja Pipeline, SDG&E no longer supplies gas to the
Rosarito generation facilities. At some time in the future (not currently planned) SDG&E
may choose to import gas /Tom TGN, This would be accomplished by modifying the
existing facility to pennit reversing the direction of flow, and by obtaining the requisite
approvals.
Also of note regarding the NBP are the actions taken by Calpine at the
Otay Mesa power project which is being developed by Calpine. Calpine has taken steps
to become the sole importer of natural gas /Tom North Baja Pipeline into the U.S. through
its planned import facilities and service lateral. Calpine has plans for building, from its
project site, a 1.5-mile long, 16-inch diameter service lateral capable of delivering 100
percent of the project's natural gas requirements, This lateral would connect Otay Mesa
to SDG&E's Pipeline 2000, as well as to a natural gas import facility connected to the
TGN Pipeline in Mexico. The import facility will consist of 340 feet of 16" pipe
connecting to the Mexico side with a meter on the U,S. side. The import facility is
licensed to provide natural gas only to Otay Mesa. Upon completion of the facilities, the
Otay Mesa plant would be dually connected to both SDG&E and NBP and further would
possess the ability to take its full load exclusively /Tom either source.
Storage
Underground storage is important in California and for SDG&E customers
in meeting winter loads of core customers as well as managing load swings /Tom power
generators, Between the LDC's and two independent storage providers, some 160 Bcf of
storage inventory is available in the state.s SDG&E, however, has no physical gas
storage capability within its service region. SDG&E has access to underground storage
facilities located on SoCai Gas. SDG&E may contract for storage service /Tom SoCal
Gas, with special provisions to allow noncore customers located behind its Citygate
access to that storage.
C. SDG&E Rates, Regulation and the Comprehensive Settlement
Agreement
The delivered cost of natural gas to an end-user in southern California is
the cost of gas at the California border plus the cost of intrastate transportation. Electric
generation customers in the SoCai Gas and SDG&E currently pay the same rate,
54 SoCal Gas owns and operates 110 Bcf of working storage capability (70 Bcf is reserved for core
customers); PG&E owns 36 Bcf (virtually all of which is reserved for core customers or for
system balancing). Private providers Wild Goose Storage Incorporated (WGSI) and Lodi Gas
Storage (Lodi) add an additional 26 Bcf, and are located in northern California.
114
APPENDIX C
- TECHNICAL APPENDIX
regardless of where a power project was actually located, SDG&E Rate Schedule EG
,.-- currently provides for transportaûon of gas across both the SoCal Gas and SDG&E
pipeline systems to the customer's end-use meter. The current blended rate for customers
of both SoCal Gas and SDG&E is $0,2747 per MMBtu, SDG&E's Rate Schedule EG-
,.-- SD, in contrast, provides for receipt of gas at the Rainbow receipt point into the SDG&E
system. Customers who receive service under Schedule EG-SD must choose either firm
or interruptible services, Firm service customers must pay full tariff rates, while
,.-- interruptible customers may negotiate lower rates with SDG&E. The current full tariff
rate for Schedule EG-SD is $0.0976.
,.-- In December 2001, the CPUC adopted most provisions of a
"Comprehensive Gas OIl Settlement Agreement (CSA)" that had been submitted to the
,.-- CPUC in April 2000. Under these new rules, SoCal Gas will auction access to backbone
transmission facilities and provide transportation service on those facilities at rates
unbundled /Tom the cost of local transmission or distribution, much as PG&E has done
since 1998.
,.--
SDG&E has never focused on providing unbundled transportation in the
,.-- same way as SoCal Gas or PG&E, and no provision to do so was contained in the
settlement. Owing to its much smaller size and the fact that there is in fact little industrial
or electric generation gas usage in its service area, the CPUC never forced SDG&E to
,.-- stop providing natural gas procurement services to non-core customers. Thus,
transportation of customer-owned gas on the SDG&E system is uncommon, although it is
currently permitted under Rate Schedules EG for non-utility electric generators and rate
,.-- Schedule NT for other non-core customers,
Under the CSA, sora! Gas will reserve a total of 1,044 MMcfd (313 at
,.-- North Needles, 303 at Topock, 355 at Blythe (Ehrenberg), and 73 at North Coastal) for
core customers and will assign to SDG&E, 50 MMcf/d at Hector Road and 10 MMcf/d at
Blythe (Ehrenberg), The remaining rum backbone rights will be offered to the market in
,.-- an open season, No SoCal Gas capacity is reserved for serving SDG&E's non-core
(including EG) customers, implying that they must participate in the open season to
obtain their own SoCal Gas backbone transmission capacity or purchase at the SDG&E
,.-- "Citygate".ss SDG&E's interconnect with SoCal Gas at the Rainbow compressor station
is a firm delivery point on the SoCal Gas system.
,.-- The aucûon of backbone transmission capacity will be a three-stage open
season process. In the first two stages of the open season, existing end-use and wholesale
customers, based on their historical requirements, will have the opportunity to obtain up
,.-- to 50 percent of receipt point capacity not reserved by SoCal Gas for core customer gas
acquisition and service, In the third stage of the open season, SoCal Gas will offer at
least 20 percent of the remaining capacity to any creditworthy enûty for a term of one
,.--
" Rainbow will become the SDG&E "Citygate," - especially as gas from North Baja (at this time)
will not be able to reach SDG&E customers other than Otay Mesa.
,.--
,.-- 115
-
APPENDIX C
TECHNICAL APPENDIX
year only (to be offered again in subsequent open seasons), and will release all remaining
capacity for the tenn of the settlement agreement, In the open season, prospective
shippers will be allowed to bid either a rate design with a 100 percent reservation charge
or a rate design with 50 percent of the total rate in the reservation charge and 50 percent
in a volumetric charge, The rates proposed in the settlement agreement are $,07191 for
the 100 percent reservation option, and $0,07591 for the 50/50 option. The 100 percent
reservation rate design and the 50/50 rate design will be given equal weight for
consideration in the open season. The Comprehensive Settlement "pools" together
deliveries across the individual SoCai Gas delivery points to create a virtual "SoCal Gas
Citygate" much as was done by PG&E in its Gas Accord structure.
Additional operational provisions of the CSA include definition of receipt
point capacity on the SoCai Gas backbone system, splitting the current transportation rate
into backbone and local transmission/distribution components, creation of pooling rights
on SoCai Gas backbone system, creation of a secondary market for trading finn receipt
point capacity, and tighter balancing provisions to implement OFO's.
SoCai Gas and SDG&E filed proposed tariff revisions required to
implement the CSA in a series of Advice Letters submitted between January and May -
2002, CPUC denied SoCai Gas' nine Advice Letters without prejudice, and ordered
SoCai Gas to file by June 30, 2003, an application proposing how to implement the CSA,
and to describe any new issues arising from developments in the southern California gas -
market that would impact provisions of the CSA since its signing in April 2000. Advice
Letters submitted by SDG&E, dealing with pass-through costs of transportation and
storage pursuant to implementation of the CSA by SoCai Gas, were suspended by the
CPUC dependent on the outcome of the SoCai Gas case,
D. Natural Gas Prices
The MEU Study Team looks to the volatility in natural gas prices over the
last 2 - 3 years and the reaction by the industry to gain confidence in our theory that the
general availability of natural gas supply will remain adequate to serve the region,
including new power projects.
U,S, natural gas prices demonstrated a relatively stable pattern from 1996
through mid-2000, fluctuating between $2.00 and $3.00 per MMBtu. Gas prices began a
significant run-up in mid-2000, grabbing headlines amid claims that supply was
inadequate, Additionally, a general industry-wide expectation that gas prices would drop
led many in the industry to delay their purchases of natural gas for injection into
underground storage. By August and September 2000, prices had not dropped, the
storage re-fill was behind schedule, and those needing to purchase gas for storage found
themselves in an already-tight market where their need to acquire gas served to exert -
even more pressure on gas supplies and price levels.
By the start of the winter injection season, storage inventories were at their
116
---- n -.-----------.-..-.. ------------ ---
APPENDIX C
TECHNICAL APPENDIX
lowest in several years and traders pushed the NYMEX gas futures market closing price
at Henry Hub for January 2001 to $9.98 per MMBtu - the highest level ever experienced.
Importantly, it is at this point that demand began to decline. Colder winter weather failed
to materialize, Non-weather-related demand also began to diminish as industries such as
fertilizer and chemicals reduced production or moved to lower-cost production areas out
of the U,S, Demand further declined as the economy began to slow down. Lower
demand, combined with an increase in production brought about by significantly
increased drilling activity and record active rig counts, created a net change in natural gas
available of about 1.3 Tcf. So lower demand and increased production made more gas
available, Prices declined steadily over 2001 as a result. From an economic perspective,
the market worked exactly as it should: market-clearing prices rose until demand
declined.
Prices in Califomia reflected these same market dynamics. From 1997
through 1999, prices at Topock generally paralleled prices at Henry Hub, albeit with a
small basis differential that varied month-to-month. Prior to that, Topock fTequently
traded at a discount to Henry Hub.
In late August 2000, an explosion on the EI Paso's southern mainline at
Carlsbad, New Mexico reduced EI Paso's ability to deliver natural gas to California by
approximately one-third. While other pipelines were able to increase deliveries and
replace some of the EI Paso capacity, the reduced deliveries left less gas available to
inject into storage in southern California. When the storage withdrawal season began on
November 1,2000, industry sources reported that SoCai Gas' storage was at 50 percent
of the normal November 1 inventory level. The November 1, 2000 monthly contract
price for gas delivered into southern California closed at $5.19 per MMBtu, compared to
$4,50 at Henry Hub. Less than two weeks later, an early season storm created
temperatures very close to the January abnormal peak day levels estimated to occur once
in 100 years, This cold spell caused SDG&E to curtail service to its electric generation
customers, Daily spot prices for gas delivered to southern California rose on virtually
each subsequent day to reach $18.90 by December 1,2000.
In late 2001 and 2002 prices significantly moderated from the
unprecedented levels of late 2000 and the first quarter of 2001. The market, however,
remained unsettled and volatile, In October 2001, gas prices had dropped below $2 at the
California border with very little premium at PG&E Citygate relative to border prices.
Prices shot up to around $3 in the next month, but trended downward throughout the
winter, and by February were back down to $2 or slightly less in California, as well as at
Henry Hub, This behavior largely reflected the fact that winter 2001-2002 was among
the wannest on record, leaving ample gas in underground storage across the country.
Market center prices had recovered to well over $3 by April 2002 and
have remained strong for the remainder of the year, exceeding $4 by November 2002,
Supply basin prices did not keep up with market center prices, with Canadian supplies
dipping to the $1,90 range in July and August, before bouncing back over $3 in
117
- ----.------.---------
APPENDIX C
TECHNICAL APPENDIX
September, Rocky Mountain prices remained well under $2 all summer, and fell to a
breathtaking low of $1.20 in September 2002 - even while hurricanes in the Gulf of
Mexico and the resultant off-shore well shut-ins pushed Henry Hub prices to $4 per
MMBtu.
During the past winter, driven mostly by extremely cold weather in the
consuming Northeast area of the country, day prices again skyrocketed to levels
approaching those in 2000-2001. Hand-in-hand with rapidly depleting storage levels to
meet abnormal seasonal temperatures, natural gas prices moved to new levels. In March
2003 prices were at their peak approaching $IO.OO/MMBtu at Henry Hub for the month,
Driven by heavy draws on storage to inventory levels well below "normal," and charges
that productive capacities were reaching their limits, prices have remained elevated in the
$5,00 to $(i,OO/MMBtu level since. Most recently, driven by all time record storage
injection rates, storage is taking on appearances of approaching normal inventories going
into the winter of 2003-04 and prices have come down. If this trend continues to develop
over the course of the next few months, as we believe it will, prices for 2003 should
average somewhere over $5.00. In general, however, what we see in the natural gas
market which is disconcerting to end-users and others that are dependent upon short-term
gas prices, is much increased price volatility. For the longer-term the MEU Study Team
projects that current price levels will moderate significantly from recent levels although
not to levels seen before 2000 - 200 I.
E. Price Forecast for SDG&E Service Area
The price forecast below presented is derived /Tom NCI's 2003 Gas Price
Forecast as updated in June 2003. The June 2003 Update reflects the strong impact of
extraordinarily high recent aggregate price levels experienced in the first half of this year.
The purpose of this Forecast is to establish reasonable estimates for generator fuel
expense for existing needs and future requirements delivered into the Chula Vista service
area, this supports conclusions in other portions of this Report,
Table 7 presents a 20-year gas price projection at the southern California
Border with three options for pricing delivered gas to the border, These are:
~ Option 1 is the delivered price within the SDG&E service area for gas purchased
at the southern California border and transported to site under the currently
effective blended EG rate for SoCal Gas and SDG&E of 27.47 cents.
~ Option 2 is the delivered price within the SDG&E service area for gas purchased
at the southern California border and transported to site using SoCal Gas and
SDG&E rates that have been proposed for implementation under the CSA, but not
yet approved by the Commission, of23.94 cents.
~ Option 3 is the delivered price to Otay Mesa for gas purchased at the border and
transported on North Baja Pipeline to the plant at the full firm published rate of 35
cents with a 1.3% fuel retention cost included. Local pipeline costs are not
included.
118
APPENDIX C
TECHNICAL APPENDIX
Table 7
. Delivered Natural Gas Prices
2004-2013
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Border 5.19 4.81 4,73 4.57 4,70 4,71 4.73 4.81 4,88 4,86
Option
1. EG 5.47 5,08 5,01 4.85 4.98 4.98 5,01 5.08 5.16 5.13
Option
2,
CSA 5.43 5,05 4,97 4,81 4.94 4,95 4,97 5.04 5.12 5.10
Option
3,
NBP 5.55 5.16 5.09 4.93 5.06 5.06 5.09 5.16 5.24 5.21
2014-2023
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Border 4.87 4.87 4.79 4.74 4.90 5.00 5,07 5,21 5.39 5.34
Option
1. EG 5.15 5.15 5.07 5.02 5.17 5,27 5.34 5.48 5.67 5.62
Option
2.
CSA 5.11 5.11 5.03 4.98 5.14 5,23 5,31 5.45 5.63 5.58
Option
3.
NBP 5.23 5.23 5,15 5.10 5.25 5.35 5.43 5,57 5.75 5.70
F. Regional Issues
1. PG&E National Energy Group, Owner/Operator of North
Baja Pipeline
Since the time of its default on a revolving' credit facility in November
2002, PG&E NEG has negotiated with lenders to restructure the company's debts, and
continues efforts to abandon, sell, and transfer assets in an effort to raise cash and reduce
debt, in order to stay out of bankruptcy, Under amended agreements with the lenders,
PG&E NEG must transfer its equity interest to the lenders or their designees in the
Athens, Covert, Harquahala, and Millenium projects by June 30, 2003 or a default will
occur.
An additional looming concern is the requirement to transfer the Lake
Road and La Paloma projects to their respective lenders. PG&E NEG has secured an
119
- --------_._------~~-------------------------
APPENDIX C
TECHNICAL APPENDIX
agreement with the lenders to extend a June 2003 deadline for transfer of these assets to
September 30, 2003 or face default under the agreement, Referring to the September
deadline, PG&E NEG states that it "does not currently expect to have the funds needed to
fulfill its obligation to guarantee the equity commitments for these projects in the
aggregate amount of $604.5 million."
Should PG&E NEG be compelled to seek protection under Chapter 11, the
impact upon its pipeline operations, may possibly include:
Þ> Sale of NBP or PGT to a fmancially sound institution, which if were to proceed
along the lines of recent similar transactions, such as the sale of Kern River by
Williams to a subsidiary of Warren Buffet's Berkshire Hathaway Group, would
allow either pipeline to continue on with little or no effect upon day-to-day
operations.
Þ> PG&E NEG continues to operate its pipeline assets while in Chapter II
proceedings,
Þ> PG&E relinquishes the NBP operator duties to joint owner Sempra, who would be
competent to assume the task.
2. Baja LNG Projects
Five LNG import and regasification projects are proposed for construction
in Baja California. Sponsors include Royal/Dutch Shell in combination with Bechtel,
ChevronTexaco, EI Paso and Conoco/Phillips Petroleum, Sempra, Marathon Oil
Company, and Mitsubishi. Completion of any of these projects would likely bring close
to I Bcfper day in very close vicinity of the California market. The MEU Study Team
understands that there is general policy support at the CPUC and CEC for addition of
some new source of supply to California that does not depend on an existing interstate
pipeline corridor, In addition, LNG tanks offer the benefit of providing additional gas
storage, Thus, we find considerable pressure for at least one LNG project to achieve
commercial operation right at about the time that our conservative projections show
California may begin to need additional interstate pipeline capacity, i.e., 2006/2007.56
LNG can serve as the equivalent of interstate pipeline capacity insofar as a project
located in Baja or along the California coast essentially creates a new border delivery
point into the state. More importantly for market participants is the concept that LNG
will not set the marginal price of gas into California. Rather, as gas prices rise as a result
of near term pipeline capacity constraints and prevailing supply/production economics,
LNG will be sold into the market as additional pipeline supply at the existing market-
clearing price and take a netback /Tom that. Most market participants and analysts such
as the U,S, Department of Energy's Energy Information Administration cite a price of
,. The details of the MEV Study Team's demand projections are beyond the scope of this report. In
broad tenDS, we grow residential demand at 1.3%, commercial at 0.3%, and industrial at I % after
economic recovery. Electric generation grows modestly at 2% per year. We disagree with
projections that EG demand will decline as new, more efficient projects come on-line and in order
to remain appropriately conservative with respect to gas system delivery capability, assume that
economic recovery will require additional gas-fired electric generation to be added.
120
APPENDIX C
TECHNICAL APPENDIX
$3.50 or so per MMBtu as needed to provide an adequate producer netback to make LNG
profitable, In short, construction of one LNG project is likely, Its presence may not
affect prevailing market prices, It is likely to become available in the same general time
frame as we would expect pipeline constraints to take hold. Table 8 below summarizes
West Coast LNG project proposals and their current status and Figure 5 below indicates
their proposed locations,
Table 8.
West Coast LNG Projects
Project Cost Capacity Online Cost Status
MMcf/d Date (Millions)
Baja California, - CRE permit necessary to develop/operate
Mexico facilities
- Environmental permits granted by
Semarnat
- Local governments issue land-use permits
El 680 2007 $500 - Denied environmental permit due to siting
Paso/Conoco-
Phillips, problems (10/02)
Playa de
Rosarito - Developing an "energy bridge" technology
to regasify on tankers and pump gas to
shore
Marathon 750 2006 $550/$15 - First application accepted (filed 8/02)
Oil/Golar LNG/ 00 - First to receive CRE permit (5/8)
Grupo GGS, La
Joya
Shell Group, 1300 2007 $500-700 - Received environmental permit /Tom Baja
Costa Azul, CA
Ensenada - Received Semamat permission for $600
mm regasification project in (4/8)
- Contracted for LNG feedstock for
regasification plant
- Letters of intent signed with potential
customers for gas
- Still needs license /Tom CRE (June),
approval /Tom Costa Azul (July), Semamat
approval (soon after) ofEIS for 64 Ian gas
pipe to Tijuana
-..
121
.- _. - - -.--------.-.--.------ -----~-_.
APPENDIX C
TECHNICAL APPENDIX
Sempra, Costa 1000 2006 $700 - Second application accepted (filed 8/02)
Azul, Ensenada - Semamat issued environmental permit
(4/25)
- Still needs operating permit from CRE and
land use permit from Ensenada
ChevronlTexac 1000 2007 ? - Gravity-based structure, near Coronado
0, Rosarito Islands
Beach
California - 4 agencies have portions of approval
authority
Bechtel/Shell, 685 2006 ? - Efforts suspended (February)
Mare Island - 8-month feasibility study disclosed
unexpected problems
Sound Energy 685 2007 $400 - Signed letter of intent with Port of Long
Solutions million Beach; location determined
(Mitsubishi), terminal - Sakhalin Energy (unit of Mitsubishi,
Long Beach Mitsui, Royal Dutch/Shell) to ship gas
- FERC approval needed
Crystal Energy - Plans to use old oil-producing platform
550 Grace (Chevron) off coast of Oxnard, CA as
LNG receiving terminal
Calpine, N. - 250 - 300 mile gas pipeline required to
California connect to PG&E.
(Humboldt - Environmentally sensitive area
Bay)
APPENDIX C
TECHNICAL APPENDIX
Figure 5
Baja California Pipeline Infrastructure showing Proposed LNG Facilities
BAJA CALIFORNIA NATURAL GAS INFRASTRUcrURE
-
-
--
-
- ~~._-
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_..... 0...
111110'0_-
-- þ===-:":'~~
-."'..... -"'"
--"....- .....,""',.
'. 0-'_'-
. . "_..œO-
-
-
-
-
123
_n--
APPENDIX C
TECHNICAL APPENDIX
G. Gas Procurement Strategy
Projecting forward to the eventual adoption of the CSA, Chula Vista
appears to have perhaps three distinct options for purchasing gas for delivery in the
SDG&E service area, Chula Vista may either elect to purchase some percentage, if not
all, of its gas requirements /Tom supplies available at the California border. In this case
Chula Vista will need to obtain transportation rights to move gas destined for Chula Vista
across the SoCai Gas and SDG&E systems. Were Chula Vista to obtain rights on the
SoCai Gas system, it would then necessarily select between the 100 percent reservation
rate design and the 50 percent reservation/50 percent volumetric rate design at a cost of
either 7.191 cents or 7.591 cents per MMBtu, respectively, In addition, Chula Vista
would also need to contract for service on SDG&E's system. Although SDG&E
Schedule EG currently provides for transportation of gas across both the SoCai Gas and
SDG&E pipeline systems to the customer's end-use meter, the MEU Study Team's read
of the CSA is that this schedule will be eliminated upon implementation of the CSA.
The proposed new EG rate for SDG&E customers, that is subject to CPUC approval, is
12.53 cents per MMBtu plus 3.82 cents per MMBtu for the Interstate Transition Cost
Surcharge (ITCS). This would create a total cost, for an EG customer Wishing to
transport gas from the California border over the SoCai Gas system and the SDG&E
system to an end-user within the SDG&E service area (Chula Vista), of23,94 cents at the
50/50 rate design or 23.54 cents at the 100 percent reservation rate.
Alternatively, with the implementation of the CSA, Chula Vista may elect
to purchase gas at the SDG&E Citygate (the Rainbow compressor and meter station)
/Tom a third-party who controls access rights over SoCai Gas's system. For this option,
Chula Vista would utilize Rate Schedule EG-SD (or its successor rate schedule under
implementation of CSA) and would pay a transport rate of 12.53 cents plus 3.82 cents
ICTS, totaling 16.35 cents, Although this transport rate is lower, Chula Vista should
expect to pay a commensurately higher price for gas purchased at Rainbow rather than
purchased at the border. In a related matter affecting potential delivered transport costs
and regarding Calpine's Otay Mesa project, SDG&E has proposed, in its 2001 Biennial
Cost Allocation Proceeding (BCAP Application, proceeding A.OI-00-005, September 21,
200 I), that, because of their potential to bypass the SDG&E system, Otay Mesa should
be subject to a peaking service tariff much like the RLS tariff SoCai Gas uses to preclude
competition, SDG&E claims its tariff is designed to "level the playing field between
non-CPUC jurisdictional pipelines that offer capacity-based rates and the all-volumetric
rate design charged by SDG&E. This matter is unresolved at present, the BCAP filing
having been ordered dismissed in April 2003. The re-filing of the BCAP, now ordered
for September 17, 2003, has potential implications for Chula Vista depending upon what
SDG&E files and what the CPUC subsequently detennines.
A third option for supplying the Otay Mesa location would entail
purchasing gas for delivery into the Otay Mesa Import Facility off of the North Baja
Pipeline. NBP currently has 123,000 MMBtu per day of unsubscribed capacity, including
64,000 MMBtu per day relinquished by PGE NEG, previously a partner with Calpine in
124
APPENDIX C
TECHNICAL APPENDIX
the Otay Mesa project. Finn capacity on NBP was originally offered and fully
subscribed at published rates of$O,35 per MMBtu and 1.3% fuel retention,
--
-
--
-
-
-
-
-
-
-
-
125
APPENDIX C
TECHNICAL APPENDIX
IV. FINANCING OPTIONS
This Technical Appendix section provides an overview of the various
types of financing mechanisms that are available to the City as a municipal issuer and
provides a comparison of the differences and similarities between alternative long-term
financing techniques, The following subsections are included:
--
A, Comparative Features of Alternative Financing Methòds
B, Purpose of Financing
C, Tax-Exempt Financing Eligibility -
D. Certificates of Participation
E. Commercial Paper
A. Comparative Features of Alternative Financing Methods
-
Financing General Limited Certificates
Method Obligation Obligations Special of Revenue
Characteristics Bonds Bonds Assessment Participation Bonds -
Acquisition & Acquisition & Facilities of Revenue
Project improvements improvements local benefit Unrestricted producing
Financeable ofland and ofland and to property facilities
buildings buildings
Issuer's Resolution of Resolution of Resolution of Resolution
governing issue issuer, issuer of issuer
Authorization board & public governing petition of governing governing
election (2/3 board and 2/3 beneficiaries board board
vote) vote
Area of Boundary of Boundary of
Authorization issuer facilities issuer facilities Flexible N/A Service area
district district of issuer
Jurisdiction (flexible) (flexible)
Hearing Majority Maybe
None None protest ordinance None
Procedure hearing adoption
Validation None None None None None
Annual
assessments
Portion of based on Rental or Service
Nature of debt Unlimited ad current benefits installment charges and
service payments valorem tax received; fees /Tom
revenues payments
property users
taxes may not
be used
126
-- ----------------------- --- ----
APPENDIX C
TECHNICAL APPENDIX
Property General Annual General &/or Service
Source of debt owners in revenues of enterprise charge and
service payment issuer property revenues of fee
jurisdiction issuer assessments issuer collections
Full faith and Revenue Tax Lease or Coverage
Security credit collections and collections! installment test and
coverage test Foreclosure sale contract contracts
Lessor/Lessee No No No Yes No
Required
Refundable Yes Yes Yes Yes Yes
Debt Service
Funds subject to No No No Yes Yes
Gann Limit
Structural
Features
Reserve Fund No Yes Yes Yes Yes
Capitalized New
Interest No No Yes Yes enterprise
only
Debt Service No Yes Valuellien No Yes
Covera2e ratio 3:1
Competitive or Competitive or Competitive Competitive Competitive
Method of Sale Negotiated Negotiated or Negotiated or Negotiated or
Negotiated
Advantages Lower interest No pledge of Isolates No voter Higher
rate General Fund projects approval interest rate
Limited Highly Debt
Disadvantages Voter approval Voter approval security structured Service
required Higher Limited Reserve
interest rates flexibility Fund
The overview above provides a broad perspective on the various fmancing
techniques that will be available to the City. However, the ultimate method that the City
chooses will be based on a number of factors.
B. Purposes of Financing
The MEU Study Team assumes that the City would use the proceeds of
the financing for a number of different uses, including but not limited to: acquisition of
distribution assets, construction of new plant and equipment, initial capital for power
purchases, and operations and maintenance expenses among others. As outlined above,
-- the purpose of the financing can and will affect the type of bond issue that the City can
utilize to finance its various costs. In the end, the City may execute a series of different
products to meet each of its various purposes.
127
.. ----.--.----..
APPENDIX C
TECHNICAL APPENDIX
C. Tax Exempt Eligibility
An important consideration in determining the appropriate technique is the
tax-exempt eligibility of the potential financing. As all the objectives (e.g. purposes and
uses of the proceeds) of the fmancing become clearer, the City's professional staff or
advisors will have a better sense regarding the City's eligibility to issue tax-exempt
bonds,
There are specific limitations on the use of traditional public agency, tax-
exempt, revenue or obligation bonds. If a City wants to issue revenue bonds to fmance
the acquisition, construction or improvement of any enterprise, after submitting the
question to its electors and receivinf a favorable majority vote, the City may proceed to
undertake and finance the project.5 However, revenue bond law does not authorize a
local agency to borrow money and issue bonds for systems, plants works, or undertakings
for the distribution of electric energy for lighting, heating, and power for public or private
uses, 58 Further, Internal Revenue Code Section 141 (d) treats bonds issued to finance the
acquisition by a governmental unit of "nongovernmental output property" (includes
electric distribution facilities) as taxable, private activity bonds. No other exemptions
/Tom this stipulation (Sections 141.d.3 and 142.f) provide for tax-exempt bonds to be
issued for this purpose. Section 141 (d) was aimed at preventing use of tax-exempt
financing for public takeovers of private utilities.
D. Certificates of Participation
Certificates of Participation (COPs) are a financing mechanism widely
used by municipalities to fmance property and equipment. Municipalities generally
choose this type of fmancing because they are not strictly considered debt obligations.
The certificates are typically a type of government lease-backed fmancing,
Lease-backed fmancing takes the form, but generally not the substance, of
a lease between a lessor and a lessee. In reality, it is much like an installment purchase
agreement. The lessee (the ultimate buyer, often a government agency) purchases
specified property from the lessor in installments over an established period by making
lease payments. Once all lease payments are made, the lessee obtains full ownership
rights to the property for a nominal sum,
The financing adopts the formal aspects of a lease agreement primarily for
reasons relating to state debt limitations. Normally voter approval is required in most
states before a municipality can incur new debt. Lease-backed financing, however, is not
classified as "debt" under most debt limitation laws, providing certain conditions are met.
Therefore, this type of lease financing enables an issuer to issue debt without the
restrictions of voter approval or limitations set under debt capacity rules,
57 Cal. Gov!. Code § 50798.4.
"Cal. Gov. Code §§ 54301 and 54310.
128
APPENDIX C
TECHNICAL APPENDIX
-
COPs add to lease-backed fmancing some of the desirable features of
bonds, especially liquidity, In a COP arrangement, investors buy certificates that entitle
them to receive participation or share in the lease payments /Tom a particular project.
The lease payments are passed through the lessor to the certificate holder with the tax
advantages intact.
- There are a number of threshold requirements that must be met in this type
of financing to qualify. Once the City has a better perspective of how the fmancing
should be structured, it would be appropriate to determine eligibility to execute a COP or
- in broad terms a lease-revenue financing.
E. Commercial Paper
-
Another financing tool used by issuers as a short-tenn financing
mechanism is commercial paper, which combines financial management techniques used
-- by corporations with the borrowing authority granted to public entities. Due to the nature
of this type of financing, voter approval is not typically required.
- Commercial paper may be used in place of, or combined with, short-tenn
notes to provide short-tenn borrowing to cover cash-flow deficits. Commercial paper is
- secured by pledged revenues and a revolving credit agreement with a commercial bank.
Commercial paper must mature between one and 270 days; however, it can be rolled over
for continuous time periods of no more than 270 days.
Advantages of issuing Commercial Paper:
- ;¡. Excellent short-term interest rates
;¡. Flexibility to repay principal on Issuer's schedule
;¡. No bond election is required (i,e" no voter approval)
- ;¡. Interest earned on the investment of the proceeds may be used for any
designated purpose
-
-
-
-
-
129
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-
APPENDIX C
TECHNICAL APPENDIX
-
VI. OPERATING AND MAINTENANCE EXPENSE
-
This Technical Appendix contains analyses supporting operating and maintenance
expense (O&M) assumptions applied in the cost-benefit financial analyses. The section contains
the following:
A. National Public Utility O&M Benchmarking
- B. California Public Utility Statistics Used to Select a Targeted
Benchmarking Panel of Four Municipal Utilities
C. Targeted O&M Expenses Benchmarking Panel
-- D, Human Resources
A. National Public Utility O&M Benchmarking
- Oper8llon and Malntenonce Expon..llenchma,tdng ("""""" 2ODO EIA Fann 4121
Totel ....-. -- "Ihe ...~. -....... Con_'-'", """"","" to c_......, - .."". T- o"'""ng -".'_ed
in EIA Fann 412 """",ot...__of_"""""..fo<I.._uti'.... H"""",Ihe","",""",'..,.",,...'(d'ot.. """""'""". e&cl"""'"
- """""iOtent........ - - ,.,...." oon\rlþ",o", to..... toI8I DOM he.. been """,,",ized (.- .0..'" -I. T...",., Moot pu~'o"", _.,
exem'ned do not.......... a""'. -. """- end... _.. pert..1he """""""""_' c"".......eooounting, - _ioeand
..,.. coots.. oom~ned """' eu- SeM"'. O&M (D'otIC"" SNdA&GI""""" a ,... (........ -blel "", (does not.." -......, ""'"no)
and " aJlooatad on . ... WI""" boo"
- llanclvnark Panal SaIectIon "-no and Malntanacne Coet .... """""'* IS)
Total D'ot C"" Sovo A&G
- Pane' C"""......, - ~ IIIomJ... O IIIomJ... O """"-"-
1 Anaheim 109.223
- Colorado Spring, 179,592
Cia" County PUD 151.555 235 110 45 80
C""ofTaooma 147.B'9
M'D 94,472
- 2 Slue ...... Eleo -- B'.863
Blue""" Beo Coop 54.576
Brun""",,ElaoIrio_ber 60.212 301 '41 57 102
RuthartonIElaoIrioMember 58,417
T""'" 66,642
- 3 AJameda 32,595
Lo..land 23.932
PatoAito 27,760 309 145 59 105
Redding 38,982
- 4 Col,,""'a _. PUD 11,982
E....,d PUD 17,'67
Ga""" 10,51B 312 147 59 106
Meea 15,966
Fran"'" C....,. PUD 1B,466
- 6 Lo, AJamoa B,114
N. Wa"", Co. PUD 9,235
0..- B,40'
Pend 0""'. C....,. PUD 7,590 366 172 70 124
Spring",l. 7,564
-
6 Clatakanie PUD 3,854
Pi..., County EI"""o 2,803
AnmEleotoioCoop 3,622 565.59 265.83 107.46 192.30
WaoooEleotoioCoop 4,381
-
- 133
APPENDIX C
TECHNICAL APPENDIX
B. California Public Utility Statistics
Page - 1
Data Item Chula Vista Year Anaheim I Burbank Glendale Pasadena
Est. 2004
Utility Data Source: EIA Form 861, Schedule IV, Line 1b, Column g
MWhs 738,978 2000 2,605,405 1,055,881 1,094,322 1,171,759
1999 2,416,302 1,029,003 1,071,277 1,129,383
1998 2,374,594 1,011,533 1,054,015 1,126,441
1997 2,469,012 1,036,915 1,058,469 1,147,194
1996 2,285,932 984,919 1,037,911 1,103,376
1995 2,245,057 950,544 1,021,426 1,149,749
Customers 78,998 2000 109,223 51,701 86,534 58,390
1999 105,755 51,488 83,100 58,378
1998 107,161 50.600 82,979 58,358
1997 106,046 50,664 82,775 57,965
1996 105,363 50,535 82,634 57,975
1995 104,299 50,398 82,496 57,807
Distribution $170,000,000 2000 $238,099,000 $108,255,000 $130,678,000 $172,066,431
Plant $ 1999 $232,027,000 $130,270,000 $165,688,291
1998 $222,089,000 $93,087,000 $121,278,000 $160,002,509
1997 $208,223.000 $90,347,000 $116,762,000 $155,862,488
1996 $188,818,000 $86,656,000 $116,105,000 $146,435.329
1995 $170,334,000 $83,083.000 $113,506,000 $141,419,233
Operating 131,879,553 2000 $279,457.000 $110,274,000 $128,998,000 $170,825,966
Revenue 1999 $254,521,000 $135,166,000 $136,500,546
1998 $244,239,000 $98,446,000 $125,399,000 $125,477,726
1997 $244,195,000 $97,847,000 $122,098,000 $114,079,866
1996 $246,479,000 $90,731,000 $98,020,000 $106,712,184
1995 $240,175,000 $93,766,000 $96,192,000 $109,865,726
FTE 239 215 266 305 201
FTE/1000
Customers 3.02 1.97 5.14 3.52 3.44
134
--
APPENDIX C
- TECHNICAL APPENDIX
B. California Public Utility Statistics
-
Page-2
-
Data Item Chula Vista Year I TID Alameda I Azusa Colton
- Est. 2004
Utility Data Source: EIA Form 861, Schedule IV, Line 1 b, Column g
MWhs 738,978 2000 1,451,488 374,217 237,852 297,536
1999 1,415,162 371,326 233,213 266,108
1998 1,347,431 359,667 214,593 249,907
1997 1,364,344 362,556 210,760 212,391
1996 1,310,843 405,275 205,918 224,529
1995 1,221,610 461,698 201,871 213,041
-
Customers 78,998 2000 66,642 32,595 14,781 17,608
1999 66,456 32,569 14,549 16,893
- 1998 65,380 32,385 14,656 16,574
1997 64,877 32,482 14,492 15,932
1996 64,543 31,704 14,492 15,932
1995 63,736 31,445 14,350 16,480
--
Distribution $170,000,000 2000 $115,269,874 $44,975,731 $18,704,738
- Plant $ 1999 $106,585,935 $43,549,314 $19,436,422
1998 $102,891,310 $42,342,106 $18,950,666
1997 $98,260,623 $41,683,944 $18,904,851
1996 $95,226,472 $39,819,173 $18,038,111
- 1995 $90,007,941 $37,817,722 $16,889,408
- Operating 131,879,553 2000 $189,995,162 $39,329,340 $31,632,053 $29,109,961
Revenue 1999 $109,807,674 $39,185,527 $30,117,994 $29,045,608
1998 $106,559,977 $37,643,234 $25,318,749 $26,095,969
1997 $106,713,200 $39,571,638 $23,342,520 $26,186,184
- 1996 $105,114,514 $43,835,353 $22,692,637 $24,669,075
1995 $101,266,868 $46,935,386 $22,329,186 $24,239,747
- FTE 239 417 87 18 52
FTE/1000
Customers 3.02 6.26 2.67 1.22 2.95
-
135
-
APPENDIX C
TECHNICAL APPENDIX
B. California Public Utility Statistics
Page-3
Data Item Chula Vista Year liD I Lassen Lodi LADWP
Est, 2004
Utility Data Source: EIA Form 861, Schedule IV, Line 1 b, Column g
MWhs 738,978 2000 2,556,914 141,199 406,185 21,124,510
1999 2,384,949 136,909 391,276 20,056,691
1998 2,353,858 135,243 376,183 21,696,008
1997 2,412,333 133,952 367,931 24,341,684
1996 2,382,446 131,751 364,062 21,341,953
1995 2,301,113 126,233 348,210 21,063,474
Customers 78,998 2000 101,574 11,006 24,764 1,459,153
1999 93,486 10,162 23,776 1,385,396
1998 90,652 10,053 23,105 1.374,424
1997 88,457 9,963 22,723 1,455,098
1996 86,685 9,797 22,586 1,347,557
1995 84,869 9,670 22,352 1,343,482
Distribution $170,000,000 2000 $377,129,433 $27,671,059 $3,469,366,891
Plant $ 1999 $338,550,477 $23,081,159 $3,351,080,932
1998 $313,510,753 $3,219,452,080
1997 $288,589,277 $18,306,326 $3,111,690,450
1996 $265,790,743 $17,107,382 $15,648,314 $3,020,680,000
1995 $250,758,924 $16,904,037 $15,090,653 $2,893,653,785
Operating 131,879,553 2000 $240,283,203 $38,268,000 $2,396,136,690
Revenue 1999 $213,014,046 $37,222,762 $2,203,363,903
1998 $209,894,855 $2,162,916,635
1997 $208,157,993 $12,802,890 $2,017,065,508
1996 $202,299,793 $14,050,111 $34,925,892 $1.946,851,000
1995 $192,067,438 $14,509,706 $34,047,610 $1,972,786,346
FTE 239 376 17 44 4,993
FTE/1000
Customers 3.02 3.70 1.54 1.78 3.42
136
-
APPENDIX C
- TECHNICAL APPENDIX
B. California Public Utility Statistics
-
Page-4
.- Data Item Chula Vista Year I MID I Palo Alto Reddina Riverside
Est. 2004
Utility Data Source: EIA Form 861, Schedule IV, Line 1 b, Column g
-
MWhs 738,978 2000 2,257,435 1,125,717 674,571 1.795,914
1999 2,164,620 1,124,025 683,493 1,647,509
- 1998 2,126,758 1,121,450 676,061 1,631,951
1997 1,998,256 1,077,181 699,722 1,652,950
1996 1,937,605 1,066,125 713,451 1,637,156
1995 1,847,637 1,051,633 680,225 1,562,088
-
Customers 78,998 2000 94,472 27,750 38,982 93,940
-- 1999 92,229 27,723 38,295 92,644
1998 91,351 27,638 37,852 91,343
1997 90,201 27,575 37,501 89,943
1996 89,934 27,527 36,982 89,588
-- 1995 89,111 27,461 36,700 88,286
Distribution $170,000,000 2000 $150,221,262 $154,628,000 $135,687,603 $201,338,954
Plant $ 1999 $143,371,838 $149,735,000 $195,255,548
1998 $137,393,835 $145,727,000 $186,913,213
1997 $128,485,051 $140,751,000 $179,214,906
1996 $126,142,937 $79,703,000 $151,302,958
1995 $116,542,420 $127,378,000 $145,781,418
-- Operating 131,879,553 2000 $218,147,944 $66,591,000 $116,932,774 $188,639,011
Revenue 1999 $150,897,979 $78,970,000 $105,358,913 $172,133,726
1998 $145,903,555 $81,142,000 $102,952,139 $176,452,787
- 1997 $139,820,064 $70,171,000 $89,551,981 $175,650,568
1996 $137,348,625 $62,988,000 $72,620,280 $164,821,455
1995 $130,272,297 $64,974,000 $64,627,172 $155,897,535
-- FTE 239 281 104 102 241
FTE/1000
Customers 3.02 2.97 3.75 2.62 2.57
-
137
-
-------------- --------
APPENDIX C
TECHNICAL APPENDIX
B. California Public Utility Statistics
Page-5
Data Item Chula Vista Year Roseville SMUD I Santa Clara Averaae
Est. 2004
Utility Data Source: EIA Form 861, Schedule IV, Line 1 b, Column g
MWhs 738,978 2000 880,535 9,764,870 2,630,930
1999 819,570 9,429,523 2,491,714
1998 802,873 9,138,407 2,506,452
1997 749,781 8,975,951 2,458,081
1996 693,468 8,889,261 2,340,285
1995 626,179 8,458,888 2,196,020
Customers 78,998 2000 36,962 512,216 48,108
1999 36,243 503,684 47,524
1998 34,095 495,167 46,483
1997 32,386 488,812 45,980
1996 29,855 483,661 45,703
1995 28,066 478,119 45,718
Distribution $170,000,000 2000 $150,049,710 $821,983,382
Plant $ 1999 $131,768,603 $797,520,587
1998 $122,021,574 $787,292,174
1997 $107,333,896 $772,748,999
1996 $97,591,619 $736,398,158
1995 $89,005,659 $714,414,106
Operating 131,879,553 2000 $68,976,482 $967,615,579 $187,359,438
Revenue 1999 $63,133,281 $775,496,370 $193,285,316
1998 $57,313,353 $765,680,805 $184,374,153
1997 $56,807,530 $714,158,755
1996 $51,582,265 $670,284,045 $183,901,001
1995 $47,464,581 $613,896,059 $157,989,707
FTE 239 66 1,920 116
FTE/1 000
Customers 3.02 1.79 3.75 2.41 3.02
u~
APPENDIX C
TECHNICAL APPENDIX
C. Targeted O&M Expenses Benchmarking Panel
The following table benchmarks costs for providing operation, maintenance, and
administrative services for similar sized utilities. The table illustrates, for four local
governmental-owned utilities in California, the number of full-time employees (FTE),
distribution operation and maintenance costs, customer service and administrative costs, total
number of customers, total retail sales, annual O&M costs per customer, and annual O&M costs
per kWh. These utilities where selected because they have near the same number of customers
that the City would likely have if it were to serve all City loads.
"'.rbank 2001 2000 1999 1998 Average
!FTE 27 26 oJ 251 26
Distribution O&M 1I,823,oo( 11,249,00 oJ 6,584,00 9,885,33
ustomer Service O&M ( oJ ( ~
ustomer Account Exnenses ( 2,017,00( oJ 2,819,00 1,612,000
IAdministrative and General O&M 8,521,OOC 6,368,025 oJ 5,254.0OC 6,714,34
ota!O&M 20:344JiiK 1963402 oJ 14657,001 18,211 67
ota! Customers 51,335 51,701 51,48! 50,60( 5P81
ota! MWH Sold 1,064,983 1,055,881 1,029,003 1,011,533 I 040.3S11
&M ~r Customer 396.3( 379.7 oJ 289.61 355.2
r'I&M ner kWh 0.0191 0.018 oJ 0.0145 0.017
"Iendale 2001 2000 1999 1998 Averaoe
FTE 35 305 25\ 25~ 29
Distribution O&M 1I,549,oOi 8,63S:OO< 6,528,00( 5,534,00< 8 062.2s(
ustomer Service O&M 1,533,00( oJ oJ oJ I 533JNW
ustomer Account Exnenses ( 4,147,001 3,6O2,OOC 2,796,OO( 2,636,25/
dministrative and General O&M 1,634,()()( 1,634,()()( 1O,020,oo( 9,120,00( 5602 OIN
ota!O&M 14.716001 14,419:OOi 20 15O.()(){ 17450,00( 16683 751
ota! Customers 83,48\ 86,53 83,10( 82,97\ 8402
ota! MWH Sold 1,084,715 1,094,32 1,071,27 1,054,015 107608
&M ~r Customer 176.2/ 166.63 242.4! 210.2\ 198.1)',
r'I&M """kWh 0.0131 0.013 0.018! 0.0161 0.015
IPasadena 2001 2000 1999 1998 Averaoe
rn. 18/ 201 18 21 19
Distribution O&M 5,423,241 4,663,42 4,005,8g, 4,512,73( 4,651,31'
ustomer Service O&M 621,71~ 672,64 563,88 751,691 65248
ustomer Account Exnenses ( 1,894,63 2,127,411 2,258,965 1.570.25:
IAdministrative and General O&M 7,429,42 6,287,90 7,074,261 8,079,14/ 7.217.68<
Irota! O&M 13,4741111 13~18"" 13 771,44< IS 602,S3' 1409174:
ota! Customers 59,35 58,3Qt 58,37 58,358 58621
ota! MWH Sold 1,100,721 1,171,75' 1,129,383 1,126,441 1,132,07
n&M "er Customer 227.0 231.5 235.1 j 267.3 240,4
n&M ner kWh 0.012, 0.0115 0.012 0.013\ O,O12!
139
------ ,-----,. ---------- ,--------
APPENDIX C
TECHNICAL APPENDIX
Irurlock ID 2001 2000 1999 1998 Avera2e
fTE 413 41 44 43 42
Distribution O&M 8,127,495 7,252,05 6,371,379 6,783,935 713371
ustomer Service O&M ( 0 0
usiomer Account ExDenses 2,351,283 2,152,845 2,291,88 1,699,80.1
k\dministrative and General O&M 9,505,49".. 12,730,19 9,187,869 8,489,695 9,978,31
Irota! O&M 1763298 22,333.53( 17712 09 17.565..'51 18811 031
trota! Customers 73,401 66,64 66,456 65,380 67,970
Irota! MWH Sold 1,451,272 1,451,48 1,415,16 1,347,431 1,416,33!
b&M Der Customer 240.23 335.13 266.5 268.6 277.64
Io&M per kWh 0.0122 0.015 0.0125 0.0130 o,om
D. Human Resources
1. Portfolio Operations and Scheduling - CCA
Portfolio Ope_lIS and Scheduling Coata Wor1<ahoot
Medium Size Municipal Electric Utility (50.000 to 90.000 Customers)
A. Labor C-
EYD!õIi!m ill ~ Bon- Annual Cost Potantial Outsourcino
RateslForecasting 3 $ 70.000 $ 9,'00 $ 237.300 Consultant
Resource Planning 2 $ 70.000 $ 10,500 $ '61.000 Consultant
rradingiRisk Management 4 $ 60.000 $ 12,000 $ 368.000 Power Marketer
Whole..1e S"'ements 2 $ 60.000 $ 9,000 $ 138.000 Scheduling Coordinator
Pre-Schedule.. 2 $ 60.000 $ 9,000 $ 138.000 Power Markatar
Real Time Desk 6 $ 60.000 $ 9.000 $ 4'4.000 Scheduling Coordinator
Credll 1 $ 70.000 $ 10.500 $ 60.500 Consultant
Manegoment 3 $ 95.000 $ 14.250 $ 327.750
IOU Transactions/Audits 2 $ 60.000 $ 9.000 $ 136.000 Consultant
IT suppon 1 $ 70,000 $ 10.500 $ 80.500 Scheduling Coordinator
Total Labor 26 $ 2.063.050
B. Administrative and Genaral Ccsts
Loading Rate 55%
Direct Labor Cas" $ 2.083,050
A&G and Cammon Cos.. $ 1.145.678
C. TotalC_Summary
Labor $ 2.083.050
OvarhOeds $ 1.145.678
rotal $ 3.226.728
2. Portfolio Operations - Greenfield (In-House Stand-Alone labor)
Minimum Portfolio Operations - Greenfield
Settlements 1
Procurement/Contracts 1
Rates 1
Credit 1
Management 1
5
FTE Average Annual Salary $69,500
Fringe Benefits (15%) $10.300
Annual Labor Estimates $399.000
140
APPENDIX C
TECHNICAL APPENDIX
3. Municipal Distribution Utility Human Resources Requirements
Director & Support Staff
3
Finance Mgr. & Supt Staff
3
Distribution Engineering & Operations Customer & Energy Services Power Operations Group
Manager & Support Staff 2 Customer & Energy Services Mgr. 1 Portfolio Operations
ESRs 4 Management 3
Substations (Supervisors and Tech.s) 19 Field Services 2 Rates/Forecasting 3
Meter Readers 14 Resource Planning 2
Dispatch (SCADA) 3 TradinglRisk Management 4
Operators 12 Credij & Collections 1 Wholesale Settlements 2
Accounting 3 Pre-Schedulers 2
Construction 4 Call Ctr CSRs 8 Real Time Desk 6
Troubleshooters 5 Billing Clerks 5 Credij 1
Materials Techs 2 IOU Transactions/Audits 2
Line Crew and Foremen 32 IT Support 1
Metering
Electronics Techs 4 Power Production
Power Plant Op.s 0
Service Planning (New Services) 1
Engineering Techs 5
Drafting Techs 4
Engineering 1
Power Engineers 5
Computer Maintenance 1
100 38 26
Total MDU Staff 170
141
SAN DIEGO GAS & ELECTRIC COMPANY
WHOLESALE DISTRIBUTION
OPEN ACCESS TARIFF
-
.-
-
-
-
-
- APPENDIX D
SAN DIEGO GAS & ELECTRIC COMPANY
WHOLESALE DISTRIBUTION
OPEN ACCESS TARIFF
-
-
-
-
-
SAN DIEGO GAS & ELECTRIC COMPANY
- WHOLESALE DISTRIBUTION OPEN ACCESS TARIFF
-
--- --- ----------....----.--.------.-.
Open Access Distribution Tariff
Orig inal Sheet No. i
--
TABLE OF CONTENTS
-
I. GENERAL SERVICE PROVISIONS.............................."""""'" 1
Preamble..................:.................................,..........1
- 1 Definitions.................................................... 1
1.1 Ancillary Services....................................... 1
1.2 .Application............................................. 1
- 1.3 CIAC. .. .. . .. . . . . . .. . . . . . . .. . . . . . . .. .. .. ..... . . .... .. . .. . . ..1
1.4 commission.................................................1
1.5 Completed Application...................,..................2
1.6 .Curtailment....................................,........ 2
1.7 Delivering Party........................................, 2
1.8 Designated Agent..........,...................,.......... 2
1.9 Direct Assignment Facilities............................. 2
1.10 Distribution Customer......................................2
1.11 Distribution Facilities....................................2
1.12 Distribution Provider.........................,............3
1.13 Distribution service.......................................3
1.14 Eligible Customer...........................""""""" 3
1.15 Facilities Study.......................................... 3
1.16 Generation....................................,.....,......3
1.17 Good Utility practice......................,.............. 4
1.18 ISO..........................................,.............4
1.19 ITCC..........................' . . . , . . . . . . . . . . . . . . . . . . . . . . . .4
1.20 Load Shedding,......,........,....,........,.............. 4
1.21 Native Load Customers.............,.....""""""""" 4
1.22 Parties........................""""""""""",.... 5
1.23 point(s) of Delivery...................................... 5
1. 24 point(s) of Receipt,..................,................... 5
1. 25 Power Purchaser..............,.....,.......""""""'" 5
1. 26 Receiving Party........................................... 5
1.27 Regional Transmission Group (RTG)......................... 5
1. 28 Service Agreement......................................... 5
1. 29 service Commencement Date..................""""""'" 5
1. 30 System Impact Study....................,................., 6
1. 31 Third-Party Sale................."""""""""""'" 6
1. 32 Transmission System....................................... 6
2 Ancillary Services.............................................. 6
3 Local Furnishing Bonds.......................................... 6
3.1 Distribution Providers That Own Facilities Financed by
Local Furnishing Bonds..................."""""""", 6
3.2 Alternative Procedures for Requesting Distribution
Service...................................................7
4 Reciprocity..................................................... 8
5 Billing and Payment............................................. 9
5.1 Billing Procedure..............................""""'" 9
5.2 Interest on Unpaid Balances......................,........ 9
open ACCe$S Dh.tribution Tariff
Original Sheet NO, ii
5.3 CU$tomer Default.......................................... 9
6 Accounting for the Di$tribution Provider' $ U$e of the Tariff... 10
6.1 Distribution Revenue$............"""""""""""" 10
6,2 Study Costs and Revenues................."""""""" 10
7 Regulatory Filings............................................. 11
8 Force Majeure and Indemnification.............................. 11
8.1 Force Majeure............................................ 11
8.2 .Indemnification........................................, 12 -
9 Creditworthiness............................................,.. 12
10 Di$pute Re$olution Procedure$..........................,....... 13
10.1 Internal Dispute Resolution Procedures................... 13 -
10.2 External Arbitration Procedures.......................... 13
10.3 Arbitration Dechioll$.....................,.............. 14
10.4 CO$t$ .................................................. .15
10.5 Rights Under The Federal Power Act. . . . . . . . . . . . . . . . . . . . . .. 15 -
II . DISTRIBUTION SERVICE
11 Applicability....................................""'"........15
12 Nature of Distribution Service.........,....................... 15
12.1 Term ......,.. ................................,......... 15
12.2 Service Priority......................................... 15
12.3 Use of Distribution service by the Dhtribution
Provider ........................................... 16
12.4 Service Agreements...............................,....... 17
12.5 Distribution Customer Obligations for Facility
Additions or Redi$patch Costs...................... 17
12.6 Curtailment of Distribution Service...................... 18
12.7 Classification of Distribution service. . . . . . . . . . . . , . . . . ., 18
12.8 Scheduling of Distribution Service....................... 19
13 Service Availability.......,................................,.. 19
13.1 General Conditions....................................... 20
13.2 Initiating Service in the Absence of an Executed
service Agreement........................................ 20
13.3 Obligation to Provide Distribution service that
Requires Expansion or Modification of Distribution
.Facilities............""""""""""""""""" 20
13.4 Deferral of Service...................................... 21
13.5 Other Distribution Service Schedules......... . . . . . . . . . . . . .21
13.6 Real Power Losses..............""""""""""""" 21
14 Distribution Customer Responsibilities .................. 21
14.1 Conditions Required of Distribution Customers............ 22
14.2 Distribution Customer Responsibility for Third-Party
Arrangements................"""""""""""""...22
15 Procedures for Arranging Distribution Service... . . . . . . . . . . . . ., 23
15.1 .Application......................."..........",.,..... 23
15.2 completed Application.................................... 23
15.3 Deposit.............................................,....24
15.4 Notice of Deficient Application.......................... 25
15.5 Response to a Completed Application. . . . . . . . . . . . . . . . . . . . .. 26
15.6 Execution of Service Agreement.................,......... 26
15.7 Extensions for Commencement of Service.,................. 27
--,---'~"-"------'.'._'-'_O_-"""- - ,.0--.'-'-..'
Open Access Distribution Tariff
Original Sheet No, iii
16 Additional Study Procedures For Distribution Service
Requests...........................................,........... 27
16.1 Notice of Need for System Impact Study................... 28
16.2 System Impact Study Agreement and Cost Reimbursement..... 28
16.3 System Impact Study Procedures........................... 29
16.4 Facilities Study Procedures.............................. 30
- 16.5 Facilities Study Modifications........................... 32
16.6 Due Diligence in Completing New Facilities............... 32
16.7 Partial Interim Service.................................. 32
17 Expedited Procedures for New Facilities........................ 33
- 18 Procedures if The Distribution Provider is unable to
Complete New Distribution Facilities for Distribution
Service........................................................ 33
- 18.1 Delays in Construction of New Facilities for
Distribution Services..........................."""", 34
18.2 Alternatives to the Original Facility Additions.. . . . . . ... 34
18.3 Refund Obligation for Unfinished Facility Additions. . . . .. 35
19 provisions Relating to Distribution Construction and
Services on the Systems of Other Utilities..................... 35
19.1 Responsibility for Third-Party System Additions.... 35
- 19.2 Coordination of Third-Party system Additions. . . . . . .. . . . .. 35
20 Changes in Service Specifications.............................. 36
21 Metering and Power Factor Correction at Receipt and Delivery
Points(s)....................................................... 37
21.1 Distribution Obligations........................,........ 37
21.2 Distribution Provider Access to Metering Data....,....... 37
21.3 Power Factor..................""""""""""""'" 37
22 Compensation for Transmission Service......................,... 37
23 Stranded Cost Recovery......................................... 37
24 Compensation for New Facilities and Redispatch Costs........... 38
SCHEDULE +..................................................................39
Wholesale Distribution service...............................,........39
ATTACHMENT A..............................""""""""""'",..........45
Form Of Service Agreement For Wholesale Distribution Service......... .45
ATTACHMENT B...................."""""""""""""""'"...........74
Methodology for Completing a System Impact Study...................... 74
ATTACHMENT C................................................................75
Methodology for completing a Facility Study............,..............75
.------.- ...-----------.---. -----
San Diego Gas & Electric Company Open Acc:ess Distribution Tariff
Original Sheet No ,1
-
1. GENERAL SERVICE PROVISIONS
-
Preamble
The Distribution Provider will provide Distribution Service to
-
Distribution Customers pursuant to the applicable terms and conditions
- of this Tariff. Distribution Service is for the receipt of capacity and
energy at designated point (s) of Receipt and the transmission of such
- capacity and energy to designated point (s) of Delivery. The Tariff must
be used in conjunction with the Independent System Operator's and
- Transmission Owner's Tariffs.
1 Definitions: Capitalized terms used in this Wholesale Distribution Tariff
-
shall have the meaning set out below unless otherwise stated in this
Tariff.
1.1 Ancillary Services: Those services that are necessary to support
the transmission of capacity and energy from resources to loads
while maintaining reliable operation of the Transmission
provider's Transmission System in accordance with Good Utility
Practice.
1.2 Application: A request by an Eligible Customer for Distribution
Service pursuant to the provisions of this Tariff.
1.3 CIAC: CIAC or Contribution In-Aid-of construction is all
property. including money, received by SDG&E from an Eligible
Customer to provide for the installation. improvement.
replacement. or expansion of SDG&E distribution facilities.
1.4 Commission: The Federal Energy Regulatory Commission.
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original S.haet No.2
1.5 Completed Application: An Application that satisfies all of the
-.
information and other requirements of this Tariff, including any
required deposit. -
1.6 Curtailment: A reduction in Distribution Service in response to a
capacity shortage as a result of system reliability conditions. -
1.7 Deli vering Party: The entity supplying capacity and energy to be
-
transmitted at point!s) of Receipt.
1.8 Designated Agent: Any entity that performs actions or functions
-.
on behalf of the Distribution Provider. an Eligible Customer, or
the Distribution Customer required under the Tariff.
1.9 Direct Assignment Facilities: Distribution Facilities or portions
of facilities that are constructed by the Distribution Provider -
for the sole use/benefit of a particular Distribution Customer
-
requesting service under the Tariff . Direct Assignment Facilities
shall be specified in the service Agreement that governs service
-
to the Distribution CUstomer and shall be subject to Commission
approval. -
1.10 Distribution Customer: Any El igible Customer (or its Designated
Agent) that (i I executes a service Agreement, or (ii) requests in -
writing that the Distribution provider files with the Commission a
proposed unexecuted Service Agreement. -
1.11 Distribution Facilities: The facilities of the Distribution
-
Provider as defined in the Commission' s order in Docket No. EL96-
98-000 dated October 30, 1996. This equipment will include
electrical equipment consisting of poles. conduit, splice boxes,
conductors, transformers and devices at less than SOkv.
.-,---------..-,-.-...., - --...--...----....
San Diego Gas' Blectric Company Open Access Distribution Tariff
Original Sheet NO.3
.-- 1.12 Distribution Provider, San Diego Gas' Electric Company ('SDG'S")
or its Designated Agent, that owns, controls, or operates
facilities used for the transmission of electric energy in
interstate commerce and provides Distribution Service under this
-
Tariff.
1.13 Distribut ion Service, The transporting of electric power over and
-
through, Distribution Facilities from the Point (s) of Receipt to
- the point(s) of Delivery under this Tariff.
1.14 Eligible Customer, Any electric utility (including the
- Distribution Provider and any power marketer), Federal power
market ing agency, or any person generating electric energy for
-
sale for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric
-
energy produced in the United States. Canada or Mexico. However.
with respect to Distribution Service that the commission is
prohibited from ordering by Section 212 (h) of the Federal Power
Act, such entity is eligible only if the service is provided
pursuant to a state requirement that the Distribution Provider
offer the Distribution Service. or pursuant to a voluntary offer
of such service by the Distribution Provider.
1.15 Facilities Study' An engineering study conducted by the
Distribution Provider to determine the required modifications to
the Distribution Provider's Distribution System. including the
cost and scheduled completion date for such modifications, that
will be required to provide the requested transmission service.
1.16 Generation, The capacity and output of any generating facility
connected to SDG'E's Distribution Facilities.
-----------------.
San Diego Gas & Elec~ric Company open Access Dis~ribu~ion TariH
Original Shee~ No.4
1.17 Good u~ility Prac~ice' Any of ~he prac~ices, me~hods and acts
-.
engaged in or approved by a significant portion of the electric
utility industry during ~he relevant time period, or any of the -
practices, me~hods and acts which, in ~he exercise of reasonable
judgmen~ in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired resul~ at
-
a reasonable cost consistent with good business practices,
reliabil i ~y, safety and expedit ion. Good u~ility practice is not
-
intended ~o be limited ~c the optimum practice, method, or act to
the exclusion of all others, but rather to be accep~able
practices, methods, or acts generally accepted in the region.
l.lB ISO: The Independent System Operator approved by the Commission --
to operate ~he in~erconnec~ed ~ransmission sys~em in California.
1.19 !TCC, ITCC or the Income Tax Component of Con~ributions is the
Federal and State tax the Distribution Provider pays on income
-
received as a CIAC.
1. 20 Load Shedding, The systematic reduction of system demand by
--
temporarily decreasing load in response to transmission system or
area capaci~y shor~ages, system instability, or voltage control _.
considerations under Part II of the Tariff.
1. 21 Native Load Customers, The wholesale and retail power customers
of the Dis~ribution Provider on whose behalf the Dis~ribu~ion
provider, by statute, franchise, regulatory requirement, or -
contrac~, has under~aken an obliga~ion to cons~ruct and operate
the Dis~ribution Provider's system to meet ~he reliable elec~ric
needs of such customers.
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San Diego Gas & Electric Company Open Access Diatribution Tariff
Original Sheet No.5
1. 22 Parties: The Distribution Provider and the Distribution Customer
receiving service under the Tariff.
1. 23 Point (s) of Delivery: Point (s) on the Distribution Facilities
where capacity and energy transmitted by the Distribution Provider
will be made available to the Receiving Party under this Tariff,
The point (s) of Delivery shall be specified in the Service
Agreement for Long-Term Firm point-To-Point Distribution Service.
1. 24 Point (s) of Receipt: Point (s) of interconnection on the
Distribution Provider's Distribution Facilities System where
capacity and energy will be made available to the Distribution
Provider by the Delivering Party under Part II of the Tariff. The
-
Point (s) of Receipt shall be specified in the Service Agreement
for Long-Term Firm point-To-point Transmission Service.
1.25 power Purchaser: The entity that is purchasing the capacity and
energy to be transmitted under the Tariff.
1. 26 Recei ving Party: The entity receiving the capacity and energy
transmitted by the Distribution Provider to Point (s) of Delivery.
1. 27 Regional Transmission Group (RTG): A voluntary organization of
transmission owners. transmission users and other entities
approved by the Commission to efficiently coordinate transmission
planning (and expansion), operation and use on a regional (and
interregional) basis.
1. 28 Service Agreement: The initial agreement and any amendments or
supplements thereto entered into by the Distribution Customer and
the Distribution provider for service under this Tariff.
1. 29 Service Commencement Date: The date the Distribution Provider
begins to provide service pursuant to the terms of an executed
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San Diego Gas I'< Electric Company Open Access Distribution Tariff
Original She.e.t No.6
Service Agreement, or the date the Distribution Provider begins to
provide service in accordance with Section 13.2 under this
Tariff. -
1. 30 System Impact Study, An assessment by the Distribution Provider
of (i) the adequacy of the Distribution Facilities to accommodate -
a request for Distribution Service and (ii) whether any additional
.-
costs may be incurred in order to provide Distribution Service.
The System Impact Study shall identify any system constraints and -
redispatch options and Direct Assignment Facilities required to
provide the requested service.
1. 31 Third-Party Sale, Any sale for resale in interstate commerce to a
Power Purchaser.
1. 32 Transmission System, The 69kV and above facilities owned by the
-
Distribution Provider and controlled by the ISO that are used to
provide transmission service under the ISO Tariff.
2. Ancillary services
Ancillary Services, although required for Transmission Service, are not
available in or through this Tariff. The Distribution Service offer is
conditioned on the Distribution Customer having retained necessary Ancillary
Services under other Commission approved tariffs.
3 Local Furnishing Bonds
3.1 Distribution Providers That Own Facilities Financed by Local
Furnishing Bonds, This provision is applicable only to
Transmission Providers that have financed facilities for the local
furnishing of electric energy with tax-exempt bonds. as described
in Section 142 (f) of the Internal Revenue Code ("local furnishing
bonds"). Notwithstanding any other provision of this Tariff. the
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.7
Distribution Provider shall not be required to provide
Distribution service to any Eligible customer pursuant to this
-- Tariff if the provision of such Distribution service would
jeopardize the tax-exempt status of any local furnishing bond(s)
-
used to finance the Distribution provider's facilities that would
be used in providing such transmission service.
-
3.2 Alternative Procedures for Requesting Distribution Service:
- Ii) If the Distribution Provider determines that the provision
of Distribution service requested by an Eligible Customer
- would jeopardize the tax-exempt status of any local
furnishing bond(s) used to finance its facilities that would
-
be used in providing such Distribution service, it shall
advise the Eligible Customer within thirty (30) days of
receipt of the Completed Application.
(ii) If the- Eligible Customer thereafter renews its request for
-
the same Distribution service referred to in (i) by
tendering an application under Section 211 of the Federal
Power Act. the Distribution Provider, within ten (10) days
of receiving a copy of the Section 211 application, will
waive its rights to a request for service under Section
213 (a) of the Federal power Act and to the issuance of a
proposed order under Section 212 (c) of the Federal Power
Act. The Commission, upon receipt of the Distribution
Provider's waiver of its rights to a request for service
under Section 213 (a) of the Federal Power Act and to the
issuance of a proposed order under Section 212 (c) of the
Federal Power Act. shall issue an order under Section 211 of
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original S.heet No.8
the Federal Power Act. upon issuance of the order under
Section 211 of the Federal Power Act. the Distribution
Provider shall be required to provide the requested
Distribution service in accordance with the terms and
conditions of this Tariff. -
4 Reciproci ty
-
A Distribution Customer receiving Distribution service under this Tariff
agrees to provide comparable distribution service that it is capable of -
providing to the Distribution Provider on similar terms and conditions over
facilities used for the transmission of electric energy owned. controlled or
operated by the Distribution customer and over facilities used for the
transmission of electric energy owned. controlled or operated by the
Distribution customer's corporate affiliates. A Distribution Customer that is
a member of a power pool or Regional Transmission Group also agrees to provide
comparable distribution service to the members of such power pool and Regional
Transmission Group on similar terms and conditions over facilities used for
the transmission of electric energy owned, controlled or operated by the
Distribution Customer and over facilities used for the transmission of
electric energy owned, controlled or operated by the Distribution customer' s
corporate affiliates.
This reciprocity requirement applies not only to the Distribution
CUstomer that obtains Distribution service under the Tariff, but also to all
parties to a transaction that involves the use of Distribution Service under
the Tariff, including the power seller, buyer and any intermediary, such as a
power marketer. This reciprocity requirement also applies to any Eligible
CUstomer that owns, controls or operates distribution facilities that uses an
intermediary. such as a power marketer. to request Distribution Service under
_. - ---- --... d_..__._----_._-------_._---~----" - ..-----
San Diego Gas & Electric Call1pany Open Access Distribution Tariff
Original Sheet No.9
the Tariff. If the Distribution CUstomer does not own, control or operate
transmission or distribution facilities, it must include in its Application a
sworn statement of one of its duly authorized officers or other
representatives that the purpose of its Application is not to assist an
Eligible Customer to avoid the requirements of this provision.
5 Billing and Payment
5.1 Billing Procedure: within a reasonable time after the first day
- of each month, the Distribution Provider shall submit an invoice
to the Distribution Customer for the charges for all services
- furnished under this Tariff during the preceding month. The
invoice shall be paid by the Distribution Customer within twenty
(20) days of receipt. All payments shall be made in immediately
available U. S. funds payable to the Distribution Provider. If
payment is by wire transfer payment shall be to a bank named by
the Distribution Provider and to an account number in the name of
the Distribution provider.
5.2 Interes.t on Unpaid Balances: Interest on any unpaid amounts
(including amounts placed in escrow) shall be calculated in
accordance with the methodology specified for interest on refunds
in the commission's regulations at 18 C.P.R. § 35.19a(a) (2) (Hi).
Interest on delinquent amounts shall be calculated from the due
date of the bill to the date of payment. when payments are made
by mail, bills shall be considered as having been paid on the date
of receipt by the Distribution Provider.
5.3 Customer Default: In the event the Distribution Customer fails,
for any reason other than a billing dispute as described below, to
make payment to the Distribution Provider on or before the due
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San Diego Gas & Slectric Company Open Access Distribution Tariff
original Sheet No ,10
date as described above, and such failure of payment is not
corrected within thirty (30) calendar days after the Distribution
Provider notifies the Distribution CUstomer to cure such failure,
a default by the Distribution Customer shall be deemed to exist.
Upon the occurrence of a default, the Distribution Provider may
initiate a proceeding with the Commission to terminate service but
-
shall not terminate service until the Commission so approves any
such request. In the event of a billing dispute between the -
Distribution Provider and the Distribution Customer, the
Distribution Provider will continue to provide service under the
Service Agreement as long as the Distribution Customer (i)
continues to make all payments not in dispute, and (ii) pays into
an independent escrow account the portion of the invoice in
dispute, pending resolution of such dispute. If the Distribution
Customer fails to meet these two requirements for continuation of
service, then the Distribution Provider may provide notice to the
Distribution Customer of its intention to suspend service in sixty
(60) days, in accordance with Commission policy.
6 Accounting for the Distribution Provider' s Use of the Tariff. The
Distribution Provider shall record the following amounts, as
outlined below.
6.1 Distribution Revenues, Include in a separate operating
revenue account or subaccount the- revenues it receives from
Distribution Service when making Third-Party Sales under
Part II of the Tariff.
6.2 Study Costs and Revenues, Include in a separate
transmission operating expense account or subaccount, costs
San Diego Gas &0 8lectric Company Open Access Distribution Tariff
Original Sheet No. 11
properly chargeable to expenee that are incurred to perform
any System Impact Studies or Facilities Studies which the
Distribution Provider conducts to determine if it must
construct new Distribution Facilities or upgrades necessary
for its own uses, including making Third-Party Sales under
the Tariff; and include in a separate operating revenue
account or subaccount the revenues received for System
Impact Studies or Facilities Studies performed when such
amounts are separately stated and identified in the
- Distribution customer's billing under the Tariff
7 Regulatory Filings
Nothing contained in this Tariff or any service Agreement, except to the
extent provided in such Agreement, shall be construed as affecting in any way
the right of the Distribution provider to unilaterally make application to the
Commission for a change in rates, terms and conditions, charges,
classification of service, Service Agreement, rule or regulation under Section
205 of the Federal power Act and pursuant to the Commission' s rules and
regulations promulgated thereunder.
Nothing contained in this Tariff or any Service Agreement, except to the
extent provided in such Agreement, shall be construed as affecting in any way
the ability of any Party receiving service under this Tariff to exercise its
rights under the Federal Power Act and pursuant to the Commission's rules and
regulations promulgated thereunder.
8 Force Majeure and Indemnification
8.1 Force Majeure: An event of Force Majeure means any act of God,
labor disturbance, act of the public enemy, war, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original Shee.t No,U
machinery or equipment, any Curtailment, order, regulation or
restriction imposed by governmental military or lawfully
established civilian authorities, or any other cause beyond a
Party's control. A Force Majeure event does not include an act of
negligence or intentional wrongdoing. Neither the Distribution
Provider nor the Distribution Customer will be considered in
default as to any obligation under this Tariff if prevented from
fulfilling the obligation due to an event of Force Majeure. --
However, a Party whose performance under this Tariff is hindered
by an event of Force Majeure shall make all reasonable efforts to
perform its obligations under this Tariff.
B. 2 Indenmification: The Distribution Customer shall at all times
indemnify, defend, and save the Distribution Provider harmless
from, any and all damages, losses, claims, including claims and
actions relating to injury to or death of any person or damage to
property, demands, suits, recoveries, costs and expenses, court
costs, attorney fees, and all other obligations by or to third
parties, arising out of or resulting from the Distribution
Provider's performance of its obligations under this Tariff on
behalf of the Distribution Customer, except in cases of negligence
or intentional wrongdoing by the Distribution Provider.
9 creditworthiness
For the purpose of determining the ability of the Distribution Customer
to meet its obligations related to service hereunder, the Distribution
Provider may require reasonable credit review procedures. This review shall
be made in accordance with standard commercial practices. In addition, the
Distribution Provider may require the Distribution Customer to provide and
-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.13
-- maintain in effect during the term of the Service Agreement, an uncondi tional
and irrevocable letter of credit as security to meet its responsibilities and
obligations under this Tariff, or an alternative form of security proposed by
the Distribution Customer and acceptable to the Distribution Provider and
consistent with commercial practices established by the Uniform Commercial
Code that protects the Distribution Provider against the risk of non-payment.
10 Dispute Resolution Procedures
10.1 Internal Dispute Resolution Procedures, Any dispute between a
Distribution Customer and the Distribution Provider involving
Distribution Service under this Tariff (excluding applications for
rate changes or other changes to this Tariff, or to any Service
-
Agreement entered into under this Tariff, which shall be presented
directly to the Commission for resolution) shall be referred to a
designated senior repreBentative of the Distribution provider and
a senior representative of the Distribution CuBtomer for
resolution on an informal bads as promptly aB practicable. In
the event the designated representatives are unable to resolve the
dispute within thirty (30) daYB by mutual agreement, such dispute
may be Bubmitted to arbitration and resolved in accordance with
the arbitration procedures set forth below.
10.2 External Arbitration Procedures, Any arbitration initiated under
this Tariff shall be conducted before a single neutral arbitrator
appointed by the Part ies. If the Parties fail to agree upon a
single arbitrator within ten (10) days of the referral of the
dispute to arbitration, each Party shall choose one arbitrator who
Bhall sit on a three-member arbitration panel. The two
arbitrators so chosen shall within twenty (20) days select a third
San Diego Gas & Electric Company Open Access Distribution Tarif f
Original Sheet No.14
arbitrator to chair the arbitration panel. In either case, the
arbitrators shall be knowledgeable in electric utility matters,
including electric transmission, distribution and bulk power
issues. and shall not have any current or past substantial
business or financial relationships with any party to the -
arbitration (except prior arbitration). The arbitrator (s) shall
provide each of the Parties an opportunity to be heard and, except
as otherwise provided herein, shall generally conduct the
arbitration in accordance with the Commercial Arbitration Rules of
the American Arbitration Association and any applicable Commission
regulations or Regional Transmission Group rules.
10.3 Arbitration Decisions, Unless otherwise agreed, the arbitrator(s) .-
shall render a decision within ninety (90) days of appointment and
shall notify the Parties in writing of such decision and the
reasons therefor. The arbitrator (s) shall be authorized only to
interpret and apply the provisions of this Tariff and any Service
Agreement entered into under this Tariff and shall have no power
to modify or change any of the above in any manner. The decision
of the arbitrator(s) shall be final and binding upon the Parties,
and judgment on the award may be entered in any court having
jurisdiction. The decision of the arbitrator(s) may be appealed
solely on the grounds that the conduct of the arbitrator(s) , or
the decision itself, violated the standards set forth in the
Federal Arbitration Act and/or the Administrative Dispute
Resolution Act. The final decision of the arbitrator must also be
filed with the Commission if it affects jurisdictional rates,
terms and conditions of service or facilities.
San Diego Gas &. Electric Company Open Access Distribution Tariff
Original Sheet No .1S
10.4 Costs, Each Party shall be responsible for its own costs incurred
during the arbitration process and for the following costs, if
applicable,
(A) the cost of the arbitrator chosen by the Party to sit on the
-
three member panel and one half of the cost of the third
arbitrator chosen; or
--.
(8) one half the cost of the single arbitrator jointly chosen by
- the Parties.
10.5 Righta Under The Federal Power Act, Nothing in this section shall
restrict the rights of any party to file a Complaint with the
Commission under relevant provisions of the Federal Power Act.
II. DISTRIBUTION SERVICE
11. Applicabil i ty
-
Distribution service is available to new Distribution Customers which
request Distribution service, and existing Distribution Customers which
request new Distribution Service for service to additional point (s) of Receipt
or Delivery. This Tariff is not for the purpose of retail service to a Native
Load Customers; such service is provided for and must be taken under CPUC
retail and direct access tariffs.
12 Nature of Distribution Service
12.1 Term, The minimum term of Point-To-point Distribution Service
shall be one day and the maximum term shall be as specified in the
Service Agreement.
12.2 Service priority, Distribution Service shall be available on a
first-come, first-served basis i. e., in the chronological sequence
in which each Distribution customer has submitted a Completed
Application. Distribution Service will be conditional based upon
~-~~-
San Diego Gas Ii< Electric company Open Access Distribution Tariff
Original Sheet No.16
the length of the requested transaction. If the Distribution
Facilities becomes oversubscribed, requests for longer term
service may preempt requests for shorter term service. Such
requests will be accepted by the Distribution Provider up to the
following deadlines, one day before the commencement of daily
service, one week before the commencement of weekly service. and
-
one month before the commencement of monthly service. Before the
condi tional service deadline, if the Distribution Facilities are
insufficient to satisfy all Applications, an Eligible Customer
with a service request for shorter term service has the right of
first refusal to match any longer term request for service before
losing its service priority. A longer term competing request for
Distribution Service will be granted if the Eligible Customer with
the right of first refusal does not agree to match the competing -
request within 24 hours from being notified by the Distribution
Provider of a longer-term competing request for Distribution
Service. After the conditional service deadline Distribution
Service will commence pursuant to this Tariff.
12.3 Use of Distribution Service by the Distribution Provider, The
Distribution Provider will be subj ect to the rates, terms and
conditions of Part II of the Tariff when making Third-Party sales
under (i) agreements executed on or after [insert date sixty (60)
days after publication in Federal Register] or (ii) agreements
executed prior to the aforementioned date that the commission
requires to be unbundled, by the date specified by the Commission.
The Distribution Provider will maintain separate accounting,
-"---"--'
San Diego Gas (, Electric Company Open Access Distribution Tariff
Original Sheet No.17
pursuant to Section 6, for any use of the Distribution Service to
make Third- party Sales.
12.4 Service Agreements: The Distribution Provider shall offer a
standard form Service Agreement (Attachment A) to an Eligible
.-.
Customer when it submits a completed Application for Distribution
Service. An Executed Service Agreement that contains the
information required under this Tariff shall be filed with the
Commission in compliance with applicable Commission regulations.
12.5 Distribution customer obligations for Facility Additions or
- Redispatch Costs: In cases where the Distribution provider
determines that its Distribution Facilities are not capable of
providing Distribution Service without III degrading or impairing
the reliability of service to Native Load or Distribution
Customers, or (2) interfering with the Distribution provider's
ability to meet prior firm contractual commitments to others, the
Distribution Provider will be obligated to expand or upgrade its
Distribution System pursuant to the terms of Section 13.3. The
Distribution customer must compensate the Distribution Provider
for any necessary transmission facility additions pursuant to the
terms of Section 24. To the extent the Distribution Provider can
relieve any system constraint more economically by redispatching
the Distribution Provider's resources than through constructing
upgrades, it shall do so, provided that the Eligible Customer
agrees to compensate the Distribution Provider pursuant to the
terms of this Tariff. Section 24. Any redispatch, Distribution
System Upgrade or Direct Assignment Facilities costs to be charged
to the Distribution Customer on an incremental basis under the
. ~---_..
San Diego Gas & Electric company Open Access Distribution Tariff
Original Sheet No. IS
Tariff will be specified in the Service Agreement prior to
initiating service.
12.6 Curtailment of Distribution Service: In the event that a
Curtailment on the Distribution Provider's Transmission System or
Distribution System, or a portion thereof, is required to maintain
reliable operation of such systems, Curtailments will be made on a
non-discriminatory basis to the transaction(s) that effectively
rel ieve the constraint. If multiple transactions require
curtailment, to the extent practicable and consistent with Good
Utility practice, the Distribution Provider will curtail service
to Distribution Customers on a basis comparable to the
curtailment of service to the Distribution Provider' s Native Load
Customers. All Curtailments will be made on a non-discriminatory
basis. When the ISO or the Distribution Provider determines that
an electrical emergency exists on the Transmission System or
Distribution System and implements emergency procedures to curtail
Distribution Service, the Distribution Customer shall make the
required reductions upon request of the Distribution Provider.
However, the Distribution Provider reserves the right to Curtail,
in whole or in part. any Distribution Service provided under the
Tariff when, in the Distribution Provider's sole discretion. an
emergency or other unforeseen condition impairs or degrades the
reliability of its Distribution System. The Distribution provider
will notify all affected Distribution Customers in a timely manner
of any scheduled Curtailments.
12.7 Classification of Distribution Service:
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No,19
(a) The Distribution Customer may purchase Distribution Service
to make sales of capacity and energy from multiple
generating units that are on the Distribution Provider's
Distribution Facilities. For such a purchase of
Distribution service, the resources will be designated as
multiple points of Receipt, unless the multiple generating
units are at the same generating plant in which case the
units would be treated as a single point of Receipt.
(b) The Distribution Provider shall provide deliveries of
capacity and energy from the point (s) of Receipt to the
point(s) of Delivery. Each Point of Receipt at which
distribution capacity is provided to the Distribution
Customer shall be set forth in the Service Agreement for
Distribution Service with each point of Receipt. Points of
Receipt and corresponding service shall be as mutually
agreed upon by the Parties for Distribution Service. Each
Point of Delivery at which Distribution service is provided
to the Distribution Customer shall be set forth in the
Service Agreement for Distribution Service associated with
each point of Deli very. points of Delivery and
corresponding service shall be as mutually agreed upon by
the Parties.
12.8 Scheduling of Distribution Service: Schedules for the
Distribution Customer' s Transmission Service and Distribution
Service shall be submitted to the ISO according to the
requirements set forth in the ISO Tariff.
13 Service Availability
San Diego Gas & Electrie Company Open Access Distribution Tariff
Original Shee.t No.20
13.1 General Conditions: The Distribution provider will provide
Distribution Service over, on or acrosS its Distribution System to
any Distribution Customer that has met the requirements of Section
14.
13.2 Initiating Service in the Absence of an Executed Service .-,
Agreement: If the Distribution Provider and the Distribution
Customer requesting Distribution Service cannot agree on all the
terms and conditions of the Service Agreement, the Distribution
Provider shall file with the commission, within thirty (30) days
after the date the Distribution Customer provides written
notification directing the Distribution Provider to file, an
unexecuted Service Agreement containing terms and conditions
deemed appropriate by the Distribution Provider for such requested
Distribution Service. The Distribution Provider shall commence
providing Distribution service subject to the Distribution
Customer agreeing to Ii) compensate the Distribution Provider at
whatever rate the Commission ultimately determines to be just and
reasonable, and (ii) comply with the terms and conditions of this
Tariff including posting appropriate security deposits in
accordance wi th the terms of Section 15.3.
13.3 Obligation to Provide Distribution service that Requires Expansion
or Modification of Distribution Facilities: If the Distribution
Provider determines that it cannot accommodate a Completed
Application for Distribution Service because of insufficient
capability on its Distribution Facilities, the Distribution
Provider will use due diligence to expand or modify its
Distribution Facilities to provide the requested Distribution
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 21
Service, provided the Distribution Customer agrees to compensate
the Distribution Provider for such costs pursuant to the terms of
Section 24. The Distribution Provider will conform to Good
Utility Practice in determining the need for new facilities and in
the design and construction of such facilities. The obligat ion
applies only to those Distribution Facilities that the
Distribution Provider has the right to expand or modify.
13 .4 Deferral of Service: The Distribution Provider may defer
providing service until it completes construction of new
distribution facilities or upgrades needed to provide Distribution
Service whenever the Distribution Provider determines that
providing the requested service would, without such new facilities
or upgrades, impair or degrade reliability to any existing
services.
13.5 Other Distribution service Schedules: Eligible Customers
recei ving Distribution service under other agreements on file
with the Commission may continue to receive Distribution service
under those agreements until such time as those agreements may be
modified by the Commission.
13.6 Real Power Losses: Real Power Losses are associated with all
Distribution service. The Distribution Provider is not obligated
to provide Real Power Losses. The Distribution Customer is
responsible for replacing losses associated with all Distribution
Service as calculated by the Distribution Provider. The
applicable Real Power Loss factors are calculated as shown in
Attachment A to this Tariff.
14 Distribution Customer Responsibilities
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.2.
14.1 Condi tions Required of Distribution Customers: Distribution
Service shall be provided by the Distribution Provider only if the
following conditions are satisfied by the Distribution Customer:
a. The Distribution Customer has pending a Completed
Application for service;
b. The Distribution Customer meets the creditworthiness
criteria set forth in Section 7;
c. The Distribution Customer will have arrangements in place
for any other distribution service necessary to effect the
delivery from the generating source to the Distribution
Provider prior to the time service under Part II of the
Tariff commences; -
d. The Distribution Customer agrees to pay for any facilities
constructed and chargeable to such Distribution customer -.
under this Tariff, whether or not the Distribution Customer
takes service for the full term of its service; and
e. The Distribution customer has executed a Service Agreement
or has agreed to receive service pursuant to section 13.2.
14.2 Distribution Customer Responsibility for Third-party Arrangements:
Any scheduling arrangements that may be required by other electric
systems shall be the responsibility of the Distribution Customer.
The Distribution Customer shall provide, unless waived by the
Distribution provider, notification to the Distribution Provider
identifying such systems and authorizing them to schedule the
capacity and energy to be transmitted by the Distribution provider
pursuant to Part II of the Tariff on behalf of the Receiving Party
at the point of Delivery or the Delivering Party at the point of
San Diego Gas & Electric Company Open Access Diatribution Tariff
Original Sheet No.23
Receipt. However, the Distribution Provider will undertake
reasonable efforts to assist the Distribution Customer in making
such arrangements, including without limitation, providing any
information or data required by such other electric system
pursuant to Good Utility practice.
15 Procedures for Arranging Distribution Service
lS.l Application: A request for Distribution Service for periods of
one year or longer must contain a written Application to:
(Manager of Distribution Management & Strategies, SDG&E, 8316
Century Park Court, San Diego, California 92l23] , at least sixty
(60) days in advance of the calendar month in which service is to
commence. The Distribution Provider will consider requests for
such firm Distribution Service on shorter notice when feasible.
Requests for firm service for periods of less than one year shall
be subject to expedited procedures that shall be negotiated
between the Parties within the time constraints provided in
section 15.5. The Distribution Provider shall time-stamp each
completed Application record for establishing the priority of the
Application.
15.2 Completed Applicat ion: A Completed Application shall provide all
of the information included in 18 CFR § 2.20 including but not
limited to the following:
(i) The identity, address, telephone number and facsimile number
of the entity requesting service;
(ii) A statement that the entity requesting service is, or will
be upon commencement of service, an Bligible Customer under
the Tariff;
--~-----~_..
San Diego Gas & Electric Company Open Access Distribution Tariff
original Sheet No.24
(iii) The location of the point Is) of Receipt and point (s) of
Delivery and the identities of the Delivering Parties and
the Receiving Parties; -
(iv) The location of the generating facility(ies) supplying the
capacity and energy and the location of the load ultimately -
served by the capacity and energy transmitted. The
Distribution Provider will treat this information as
confidential except to the extent that disclosure of this
-
information is required by this Tariff, by regulatory or
judicial order, for reliability purposes pursuant to Good
Utility Practice or pursuant to RTG transmission information
sharing agreements. The Distribution Provider shall treat -
this information consistent with the standards of conduct
-
contained in Part 37 of the CommisBion's regulations;
(v) A description of the supply characteristics of the capacity
-
and energy to be delivered;
Ivil An estimate of the capacity and energy expected to be
_.
received at the point (s) of Receipt and delivered to the
Receiving Party at the Point Is) of Delivery;
(vii) The requested Service Commencement Date and the term of the
requested Distribution Service; and
15.3 Deposit: A Completed Application for Distribution Service also
shall include a deposit of either one month's charge for service
or the full charge for service requests of less than one month.
If the Application is rejected by the Distribution Provider
because it does not meet the conditions for service as set forth
herein, or in the case of requests for service arising in
San Diego Gas & Electric Company Open Access Distribution Tariff
ot'iginal Sheet No.25
connection with losing bidders in a Request For proposals (RFP) ,
said deposit shall be returned with interest less any reasonable
costs incurred by the Distribution Provider in connection with the
review of the losing bidder' s Application. The deposit also will
be returned with interest less any reasonable costs incurred by
the Distribution Provider if the Distribution providsr is unable
-
to complete new Facilities needed to provide the service. If an
Applicstion is withdrawn or the Eligible Customer decides not to
enter into a Service Agreement for Distribution Service, the
deposit shall be refunded in full, with interest, less reasonable
costs incurred by the Distribution Provider to the extent such
-
costs have not already been recovered by the Distribution Provider
from the Eligible Customer. The Distribution Provider will
provide to the Eligible Customer a complete accounting of all
costs deducted from the refunded deposit, which the Eligible
Customer may contest if there is a dispute concerning the deducted
costs. Deposits associated with construction of new facilities
are subject to the provisions of Section 16. If a Service
Agreement for Distribution Service is executed, The deposit, with
interest, will be returned to the Distribution Customer upon
expiration or termination of the Service Agreement for
Distribution Service. Applicable interest shall be computed in
accordance with the Commission's regulations at 18 CFR .
35-l9a(a) (2) (iii), and shall be calculated from the day the
deposit check is credited to the Distribution Provider' s account.
l5.4 Notice of Deficient Application: If an Application fails to meet
the requirements of the Tariff, the Distribution provider shall
--.-----.---------____..0____- - ..---.---...
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No..6
notify the entity requesting service within fifteen (15) days of
receipt of the reasons for such failure. The Distribution
Provider will attempt to remedy minor deficiencies in the
Application through informal communications with the Eligible
CUstomer. If such efforts are unsuccessful, the Distribution -
Provider shall return the Application, along with any deposit,
-
with interest.
15.5 Response to a Completed Application, Upon receipt of a new or
-
revised Application that fully complies with the requirements of
this Tariff, the Eligible Customer shall be assigned a priority --
consistent with the date of the new or revised Application.
Following receipt of a Completed Application, the Distribution --
provider shall notify the Eligible Customer as soon as
-
practicable, but not later than thirty (30) days after the date of
receipt of a Completed Application either if it will be able to
provide service without performing a System Impact Study or if
such a study is needed to evaluate the impact of the Application -
pursuant to Section 16.1. The notice shall also include an
estimate of the cost of the study. Responses by the Distribution
Provider must be made as soon as practicable to all Completed
Applications (including applications by its own merchant function) -
and the timing of such responses must be made on a non-
-
discriminatory basi..
15.6 Execution of Service Agreement: Whenever the Distribution
Provider determines that a System Impact Study is not required and
that the service can be provided, it shall notify the Eligible
CUstomer as soon as practicable but no later than thirty (30) days
. .._----. --------- --_--'_H -----. - -------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No..7
- after receipt of the Completed Application. Where a System Impact
Study is required, the provisions of Section 19 will govern the
execution of a Service Agreement. Failure of an Eligible Customer
to execute and return the Service Agreement or request the filing
of an unexecuted service agreement pursuant to Section 13.2,
within fifteen (l5) days after it is tendered by the Distribution
-
Provider, will be deemed a withdrawal and termination of the
- Completed Application and any deposit submitted shall be refunded
with interest. Nothing herein limits the right of an Eligible
- Customer to file another Application after such withdrawal and
termination.
15.7 Extensions for Commencement of Service: The Distribution Customer
can obtain up to five (5) one-year extensions for the commencement
of service. The Distribution Customer may postpone service by
paying a non-refundable annual fee equal to one-month' s charge for
-
Distribution Service for each year or fraction thereof. If during
- any extension for the commencement of aervice an Eligible Customer
submits a Completed Application for Distribution Service, and such
- request can be satisfied only by releasing all or part of the
Distribution Customer's Capacity, the original Capacity will be
released unless the following condition is satisfied. Within
thirty (30) days, the original Distribution Customer agrees to pay
distribution rate for its Distribution Service concurrent with the
new Service Commencement Date. In the event the Distribution
Customer elects to release the Capacity, the fees or portions
thereof previously paid will be forfeited.
16 Additional Study Procedures For Distribution Service Requests
San Diego Gas & Electric Company Open Access Distribution Tariff
Original S.heet No.aS
16.1 Not ice of Need for System Impact Study: After receiving a request
for service, the Distribution Provider shall determine on a non-
discriminatory basis whether a System Impact Study is needed. A -.
description of the Distribution Provider's methodology for
completing a System Impact Study is provided in Attachment B. If -
the Distribution Provider determines that a System Impact Study is
-
necessary to accommodate the requested service, it shall so inform
the Eligible Customer, as soon as practicable. In such cases, the
-
Distribution Provider shall within thirty (30) days of receipt of
a Completed Application, tender a System Impact Study Agreement -
pursuant to which the Eligible customer shall agree to reimburse
the Distribution Provider for performing the required System -
Impact Study. For a service request to remain a Completed
Application, the Eligible Customer shall execute the System Impact -
Study Agreement and return it to the Distribution provider within
---
fifteen (15) days. If the Eligible customer elects not to execute
the System Impact Study Agreement, its application shall be deemed -
withdrawn and its deposit, pursuant to section 15.3, shall be
returned with interest. -
l6.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study Agreement will clearly specify the -
Distribution Provider's estimate of the actual cost, and
time for completion of the system Impact Study. The charge -
shall not exceed the actual cost of the study. In
performing the System Impact Study, the Distribution
provider shall rely, to the extent reasonably practicable.
on existing studies. The Eligible Customer will not be
-.. .-..---------------. --..-----...---.-.
San Diego Gas & Electric Company Open Access Distribution Tariff
Odginal Sheet No.¡¡9
assessed a charge for such existing studies; however, the
Eligible Customer will be responsible for charges associated
with any modifications to existing planning studies that are
reasonably necessary to evaluate the impact of the Eligible
Customer' s request for service on the Distribution
Facilities.
-
(ii) If in response to multiple Eligible Customers requesting
service in relation to the same competitive solicitation, a
single System Impact Study is sufficient for the
Distribution Provider to accommodate the requests for
service, the costs of that study shall be pro-rated among
the Eligible Customers.
(iii) For System Impact Studies that the Distribution Provider
conducts on its own behalf, the Transmission Provider shall
record the cost of the System Impact Studies pursuant to
Section 18.
- 16.3 System Impact Study Procedures: Upon receipt of an executed
System Impact Study Agreement, the Distribution Provider will use
due diligence to complete the required System Impact Study within
a sixty (60) day period. The System Impact Study shall identify
any system constraints and redispatch options, additional Direct
Assignment Facilities or Distribution System upgrades required to
provide the requested service in accordance with Attachment B. In
the event that the Distribution Provider is unable to complete the
required System Impact Study within such time period, it shall so
notify the Eligible Customer and provide an estimated completion
date along with an explanation of the reasons why additional time
---------_._-_. ------...--.-. .
San Diego Gas & Electric Company Open Access Distribution Tariff
Original S.heet No.30
is required to complete the required studies. A copy of the
completed System Impact Study and related work papers shall be
made available to the Eligible Customer. The Distribution
provider will use the same due diligence in completing the System
-
Impact Study for an Eligible Customer as it uses when completing
studies for itself. The Distribution Provider shall notify the
-
Eligible Customer immediately upon completion of the System Impact
Study if the Distribution Facilities will be adequate to -
accommodate all or part of a request for service or that no costs
are likely to be incurred for new Distribution Facilities or -
upgrades. In order for a request to remain a Completed
Application, within fifteen (15) days of completion of the System -
Impact Study the Eligible Customer must execute a Service
Agreement or request the filing of an unexecuted Service Agreement
pursuant to Section 13.3, or the Completed Application shall be
-
deemed terminated and withdrawn.
16.4 Facilities Study procedures: If a System Impact Study indicates -.
that addi~ions or upgrades to the Distribution System are needed
to supply the Eligible Customer' s service request, the
Distribution Provider, within thirty (30) days of the completion
of the System Impact Study, shall tender to the Eligible Customer
a Facilities Study Agreement pursuant to which the Eligible
Customer shall agree to reimburse the Distribution Provider for
performing the required Facilities Study. For a service request
to remain a Completed Application, the Eligible Customer shall
execute the Facilities Study Agreement and return it, together
with the payment for the estimated costs to do the study, to the
san Diego Gas & Electric Company Open ~c:c:ess Distribution TarHf
Original Sheet No. 31
Distribut ion Provider wi thin fifteen 115) days of receipt of the
Facilities Study Agreement by the Eligible Customer. If the
--
Eligible Customer elects not to execute the Facilities Study
Agreement, its application shall be deemed withdrawn and its
--
deposit pursuant to Section 15.3, shall be returned wi th interest.
Upon receipt of an executed Facilities Study Agreement, the
Distribution Provider will use due diligence to complete the
required Facilities Study within a sixty 160) day period. If the
Distribution provider is unable to complete the Facilities Study
-- in the allotted time period, the Distribution Provider shall
notify the Distribution Customer and provide an estimate of the
--
time needed to reach a final determination along with an
explanation of the reasons that additional time is required to
complete the study. when completed, the Facilities Study will
include a good faith estimate of Ii) the cost of Direct Assignment
Facil i ties to be charged to the Distribution Customer, (ii) the
Transmission Customer's appropriate share of the cost of any
required upgrades as determined pursuant to the provisions of
Part II of the Tariff, and (iii) the time required to complete
such construction and initiate the requested service. The
--
Distribution Customer shall provide the Distribution Provider with
a letter of credit or other reasonable form of security acceptable
to the Distribution Provider equivalent to the costs of new
facilities or upgrades consistent with commercial practices as
established by the Uniform Commercial Code. The Distribution
Customer shall have thirty (30) days to execute a Service
Agreement or request the filing of an unexecuted service Agreement
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.32
and provide the required letter of credit or other form of
security or the request will no longer be a Completed Application
and shall be deemed terminated and withdrawn. --
16.5 Facilities Study Modifications: Any change in design arising from
inability to site or construct facilities as proposed will require -
development of a revised good faith estimate. New good faith
-
estimates also will be required in the event of new statutory or
regulatory requirements that are effective before the completion
-
of construction or other circumstances beyond the control of the
Distribution Provider that significantly affect the final cost of -
new facilities or upgrades to be charged to the Distribution
customer pursuant to the provisions of Part II of the Tariff. -
16.6 Due Diligence in Completing New Facilities: The Distribution
-
provider shall use due diligence to add necessary facilities or
upgrade its Distribution System within a reasonable time. The
-
Distribution Provider will not upgrade its existing or planned
Distribution System in order to provide the requested
Distribution Service if doing so would impair system reliability
or otherwise impair or degrade existing firm service. -
16.7 Partial Interim Service: If the Distribution Provider determines
that it will not have adequate Distribution Facilities to satisfy -
the full amount of a Completed Application for Distribution
Service, the Distribution Provider nonetheless shall be obligated
to offer and provide the portion of the requested Distribution
Service that can be accommodated without addition of any
facilities and through redispatch. However, the Distribution
Provider shall not be obligated to provide the incremental amount
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San Diego Gas ¡, Electric Company Open Access Distribution Tariff
Original Shee.t No. 33
of requested Distribution Service that requires the addition of
facilities or upgrades to the Distribution System until such
facilities or upgrades have been placed in service.
17 Expedited Procedures for New Facilities: In lieu of the
--
procedures set forth above, the Eligible Customer shall have the
option to expedite the process by requesting the Distribution
---
Provider to tender at one time, together with the results of
required studies, an "ExpedJ.ted Service Agreement" pursuant to
which the Eligible CUstomer would agree to compensate the
-- Transmission Provider for all costs incurred pursuant to the terms
of the Tariff. In order to exercise this option, the Eligible
Customer shall request in writing an expedited Service Agreement
covering all of the above-specified items within thirty (30) days
..-
of receiving the results of the System Impact Study identifying
needed facility additions or upgrades or costs incurred in
providing the requested service. While the Distribution Provider
agrees to provide the Eligible Customer with its best estimate of
the new facility costs and other charges that may be incurred,
such estimate shall not be binding and the Eligible Customer must
agree in writing to compensate the Distribution provider for all
costs incurred pursuant to the provisions of the Tariff. The
Eligible CUstomer shall execute and return such an Expedited
Service Agreement within fifteen (15) days of its receipt or the
Eligible Customer' s request for service will cease to be a
Completed Application and will be deemed terminated and withdrawn.
18 Procedures if The Distribution Provider is Unable to Complete New
Distribution Facilities for Distribution Service
--- h_____- ---.-.------------------- -- --- -
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet NO. 34
18.1 Delays in Construction of New Facilities for Distribution
Services: If any event occurs that will materially affect the
time for completion of new facilities. or the ability to complete
them, the Distribution provider shall promptly notify the
Distribution Customer. In such circumstances, the Distribution
provider shall within thirty 130) days of notifying the
-
Distribution CUstomer of such delay, convene a technical meeting
with the Distribution Customer to evaluate the alternatives
-
available to the Distribution Customer. The Di stribution Provider
also shall make available to the Distribution Customer studies and -
work papers related to the delay, including all information that
is in the possession of the Distribution provider that is ---
reasonably needed by the Distribution customer to evaluate any
-
alternatives.
18.2 Alternatives to the Original Facility Additions: When the review
process of Section l8.l determines that one or more alternatives
exist to the originally planned construction project, the
Distribution Provider shall present such alternatives for
consideration by the Distribution CUstomer. If, upon review of
any alternatives, the Distribution CUstomer desires to maintain
its Completed Application subject to construction of the -.
alternative facilities, it may request the Distribution Provider
to submit a revised Service Agreement for Distribution Service.
the event the Distribution Provider concludes that no reasonable
alternative exists and the Distribution Customer disagrees, the
Distribution Customer may seek relief under the dispute resolution
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.35
procedures pursuant to Section 10 or it may refer the dispute to
the Commi ssion for resolution.
18.3 Refund Obligation for Unfinished Facility Additions: If the
Distribution Provider and the Distribution Customer mutually agree
-
that no other reasonable alternatives exist and the requested
service cannot be provided out of existing capability under the
-
conditions of Part II of the Tariff, the obligation to provide the
- requested Distribution Service shall terminate and any deposit
made by the Distribution Customer shall be returned with interest
- pursuant to Commission regulations 35.l9a(a) (2) (iii). However,
the Distribution Customer shall be responsible for all prudently
incurred costs by the Distribution Provider through the time
construct ion was suspended.
-
19 provisions Relating to Distribution Construction and Services on the
Systems of Other Utilities
-
19.1 Responsibility for Third-Party System Additions: The Distribution
- provider shall not be responsible for making arrangements for any
necessary engineering, permitting, and construction of
transmission or distribution facilities on the system(s) of any
other entity or for obtaining any regulatory approval for such
facilities. The Distribution Provider will undertake reasonable
efforts to assist the Distribution Customer in obtaining such
arrangements. including without limitation. providing any
information or data required by such other electric system
pursuant to Good Utility Practice.
19.2 Coordination of Third-Party System Additions: In circumstances
where the need for Distribution Facilities or upgrades is
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 36
identified pursuant to the provisions of Part II of the Tariff.
and if such upgrades further require the addition of distribution
facilities on other systems, the Distribution provider shall have
the right to coordinate construction on its own system with the
construction required by others. The Distribution Provider. after
consultation with the Distribution Customer and representatives of
-
such other systems, may defer construction of its new distribution
transmission facilities, if the new distribution facilities on
--
another system cannot be completed in a timely manner. The
Distribution Provider shall notify the Transmission Customer in -
writing of the basis for any decision to defer construction and
the specific problems which must be resolved before it will -
ini tiate or resume construction of new facilities. Within sixty
-
(60) days of receiving written notification by the Distribution
Provider of its intent to defer construction pursuant to this
-
section, the Distribution Customer may challenge the decision in
accordance with the dispute resolution procedures pursuant to -
Section 8 or it may refer the dispute to the Commission for
resolution. -
20 Changes in Service Specifications
Any request by a Distribution Customer to modify Receipt and Delivery -
shall be treated as a new request for service in accordance with
Section 15 hereof, except that such Distribution Customer shall
not be obligated to pay any additional deposit if the service does
not exceed the amount in the existing Service Agreement. while
such new request is pending, the Distribution Customer shall
retain its priority for service at the existing point (s) of
-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.3'
Receipt and Point (s) of Delivery specified in its Service
Agreement.
21 Metering and Power Factor Correction at Receipt and Delivery points (s)
21.1 Distribution Obligations, Unless otherwise agreed, the
Distribution Customer shall be responsible for installing and
maintaining compatible metering and communications equipment to
-
accurately account for the capacity and energy being transmitted
under Part II of the Tariff and to communicate the information to
the Distribution Provider. Such equipment shall remain the
- property of the Distribution Customer.
21. 2 Distribution Provider Access to Metering Data: The Distribution
Provider shall have access to metering data, which may reasonably
be required to facilitate measurements and billing under the
-
Service Agreement.
21.3 Power Factor, unless otherwise agreed, the Distribution Customer
is required to maintain a power factor within the same range as
the Distribution Provider pursuant to Good Utility Practices. The
power factor requirements are specified in the Service Agreement
where applicable.
22 Compensation for Distribution Service
Rates for Distribution Service are provided in the Schedules appended to
this Tariff Distribution Service (Schedule WDSl). The Distribution Provider
shall use Part II of the Tariff to make its Third- Party Sales. The
Distribution Provider shall account for such use at the applicable Tariff
rates, pursuant to Section 6.
23 Stranded Cost Recovery
San Diego Gas & Electric Company Open Access Distribution Tariff
original Sheet No. 38
The Distribution Provider may seek to recover stranded costs from the
Distribution customer pursuant to this Tariff in accordance with the terms,
conditions and procedures set forth in FERC Order No. 888 and B88-A. However,
the Distribution Provider must separately file any specific proposed stranded
cost charge under Section 205 of the Federal Power Act.
-
24 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed by the Distribution provider in -
connection with the provision of Distribution Service identifies the need for
new facilities, the Distribution Customer shall be responsible for such costs --
to the extent consistent with Commission policy. Whenever a System Impact
Study performed by the Distribution Provider identifies capacity constraints
that may be relieved more economically by redispatching the Distribution
Provider's resources than by building new facilities or upgrading existing
facilities to eliminate such constraints, the Distribution customer shall be
responsible for the redispatch costs to the extent consistent with Commission
policy.
-
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San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 39
SCHEDULE WDS 1
Wholesale Distribution Service
Subject to approval under Section 205 or Section 212 of the Federal
Power Act the Distribution Customer shall compensate the Distribution Provider
each month for Distribution Service at the sum of the applicable charges set
forth below.
A. Distribution service Charges:
a. Distribution Service for a Distribution Customer Who is an Electric
Utility
The monthly charge for Distribution Service to a Distribution Customer
who is an electric utility shall be based upon the following charges:
1. A customer service charge ISee Section 8.1): $_/month;
2. A distribution demand charge (See Section 8. 2a): $_/kW/month;
3a. Customer advance associated with .Direct Assignment Facilities (See
Section 8. 3a): $- lump sum payment;
3b. Monthly Facilities Charge associated with Direct Assignment Facilities
(See Section 8.3b): $_/kW/month;
4. A cost of ownership charge for Direct Assignment Facilities (See Section
8.4): $_/month;
5. Power factor adj ustment charge ISee Section 8.5): $_/month;
6. Distribution lOBS adjustment charge Isee Section 8.6): $_/month;
and
7. Costs associated with avoiding an impairment, if any (See Section 8.7):
$- lump sum payment
b. Distribution Service for a Distribution Customer Who is a Generator
The monthly charge for distribution service to serve a generator shall
consist of the following:
1. A customer service charge (See Section 8.1) $_/month;
San Diego Gas & Electric Company Open Access Distribution Tariff
original Sheet No.40
2a. Customer advance associated with Direct Assignment Facilities (See
section B.3) $_/month;
2b. Monthly Facilities Charge associated with Direct Assignment Facilities
ISee Section B. 3b) $_/kW/month;
3. A distribution demand charge associated with upgrades ISee Section B. 2b
) $_/kw/month
4. cost of ownership charge for Direct Assignment Facilities ISee Section
B.4) :$_/month;
5. power factor adjustment charge (See Section B.5) $_/month;
6. ¡'oss adjustment charges (See Section B.6) $_/month; and
7. Costs associated with avoiding an impairment, if any $_/lump sum
payment.
.-
B. Description of Specific charges
1. Customer Service Charge
A fixed monthly distribution customer service charge shall be assessed to
reimburse the Distribution Provider for its costs of labor and supervision for
billing services which it provides to the Distribution customer for the
specified Service point of Delivery, including, among other things, billing,
accounting for reactive power and distribution facilities usage as provided in
this Tariff. An individual special study is required to determine this
charge.
2a. Distribution Demand Charge Associated with an Electric Utility
Distribution Customers that are electric utilities shall pay a Distribution
Demand Charge. The Distribution Demand Charge shall recover the higher of:
(a) the Distribution customer's proportionate share of the embedded costs
(including expansion costs) of the Distribution Facilities that are used to
serve the Distribution Customer' s load (excluding Direct Assignment
Facilities); or (b) the incremental cost of whatever expansions or upgrades to
the Distribution Facilities are required to serve the Distribution Customer' s
load (excluding Direct Assignment Facilities) .
The Distribution Provider shall undertake a System Impact Study to identify:
(a) which preexisting Distribution Facilities will be used to serve the
Distribution customer' s load; and (b) what upgrade or expansions to the
_.-------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.4l
preexisting Distribution Facilities, if any, will be required to serve the
Distribution Customer' s load. The Distribution Provider will then calculate a
revenue requirement based upon the higher of embedded costs las expanded) or
incremental costs. The Distribution Demand Charge shall be assessed according
to the Distribution Customer's metered quantities at the Point of Receipt.
If the revenue requirement is based upon embedded costs (as expanded), the
cost of the Distribution Facilities used to serve the Distribution Customer
shall be calculated according to the Distribution Customer' S proportionate
share of the total load served from the identified Distribution Facilities.
The monthly demand charge shall be calculated by dividing the annual revenue
requirement associated with the identified Distribution Facilities by the sum
of the Distribution Customer' s twelve monthly maximum peak demands imposed on
those facilities.
-
2b. Distribution Demand Charge Associated with a Generator
Although a Distribution Customer who is a generator will not be charged for an
.- allocated portion of preexisting Distribution Facilities, he will be
responsible for the costs of distribution upgrades or an allocated portion of
the upgrades that directly benefit him. The Distribuion customer will have
one of two options to pay for these upgrades. First, he can pay a Customer
Advance as calculated in Exhibt 7c or he can pay a monthly demand charge as
derived ~n Exhibit 7b.
3a. Customer Advance Associated with Direct Assignment Facilities
In accordance with Attachment A of this Tariff, the Distribution Provider will
calculate a customer advance for Direct Assignment Facilities that will be
payable by the Distribution Customer at the time a service Agreement is signed
(See Attachment A). If the customer terminates service, the customer agrees to
pay for the remaining cost pf such facilities whether or not it takes service
for the full term specified in the Service Agreement.
The remaining life of the facilities will be the depreciated installed cost of
the Added Facilities plus removal costs, less salvage. In addition, the
Distribution Customers shall pay an amount equal to the difference between (i)
the sum of the payments which would have been made for the Added Facilities
during the period in which this Agreement was in effect, if the rate had been
--. --------.---
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.42
calculated pursuant to a traditional depreciated rate base methodology, and
Iii) the sum of the payments actually made, or which had become due, under
this Agreement as of the date of termination. Such comparison shall be made
for all payments made or due upon termination of this Agreement in accordance
with this provision. The Distribution Provider shall file all charges under
this provision with the FERC prior to termination. Following termination, the
Distribution Provider shall remove the Added Facilities from service to the
Distribution Customer.
3b. Monthly Facilities Charge Associated with Direct Assignment Facilities
Under the WDT, the Distribution Customer will be given one of two options to
pay for Direct Assignment Facilities. First, the customer can elect to pay a
customer advance which will recover the total cost of these facilities at the
time he signs the service Agreement. second, the Distribution Customer can
elect to pay a Monthly Facilities Charge that will recover the annual cost of
these facilities. In the latter case, the customer will have to agree to pay
for the remaining cost of such facilities whether or not it takes service for
the full term specified in the Service Agreement. The remaining life of the
facilities will be determined in accordance with Section B. 3a of Schedule
WDS-l.
4. Cost of Ownership Charge For Direct Assignment Facilities
The Cost of Ownership charge for Direct Assignment Facilities will recover the
Distribution Provider' s on going costs of owning and operating the Direct
Assignment Facilities. As indicated in Attachment A, such on-going costs will
include operation and maintenance costs, replacement costs (due to normal
deterioration), and property taxes.
The Cost of Ownership Charge shall also include the on going costs of any
facilities installed by the Distribution Customer or others, if any, that are
deeded to the Distribution Provider. The manner is which the monthly cost of
ownership charge is derived is shown in Attachment A.
5. Power Factor Adjustment Charge
Unless otherwise agreed, the Distribution Customer is required to maintain a
power factor within the rage of 0.95 leading to 0.95 lagging during daily peak
_.. ...- -..---------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 43
hours from 10 AM to 6 PM. If consumption falls outside this range a power
factor adjustment charge as indicated in Attachment A, shall be charged.
6. Distribution Loss Adjustment Charge
a. Distribution Loss Adjustment Charge Applicable to A Distribution
Customer Who is an Electric Utility
A Distribution Customer who is an electric utility will cause the Distribution
provider to incur energy losses on the Distribution Facilities used to provide
service. To insure the Distribution Provider is compensated for these losses,
the Distribution Customer will be required to pay for these losses.
The losses will be paid by the Distribution customer on a monthly basis and
will be calculated using standard engineering formulas applicable to the
Distribution Customers use of the Distribution Providers distribution system.
The energy loss factor calculated by these formulas shall be applied to a
Customer's monthly energy consumption for the billing month. The energy loss
charge shall will be priced in accordance with Attachment A.
b. Distribution Loss Adjustment Factors Applicable to a Distribution
Customer Who is a Generator
The generator in the process of inserting power into the Distribution
Provider's distribution system could increase or reduce the energy losses of
the Distribution Facilities. In this circumstance, the generator will be
charged or compensated, as the case may be, for these losses. A loss charge
or compensation shall be made in accordance with Attachment A.
7. Definition,
For purposes of WDS-l, following terms and conditions shall have the
following meaning:
a. "Impairment": Any event that could result from Distribution
Service which is reasonable likely to cause (i) the inclusion in
gross income for federal income tax purposes of the interest paid
and/or to be paid on any local-furnishing private activity bonds
("Bonds") as described in Section 142 (f) of the Internal Revenue
_... ---------- ------..---- ----- --
San Diego Gas & Electric Company Open Access Distribution Tariff
Odgi.nal Sheet No.U
Code of 1986, as amended, or in any predecessor statute (the
"Code"), issued for the benefit of Distribution Provider, (ii) the
inclusion in gross income of interest for federal income tax
purposes on debt which is reasonably expected to be issued in the
future to finance distribution or generation facilities of
Distribut ion Provider. or to be issued to refinance any
outstanding Bonds issued for the benefit of Distribution Provider,
or (iii) the loss of the deductibility, under Section 150 of the
Code, of any interest expense associated with interest paid or to
be paid on any such Bonds.
c. "Costs associated with avoiding an Impairment", All costs
reasonably necessary to avoid or minimize the costs of an
Impairment including: Ii) redispatch of generation; Iii)
construction or other physical modification of Distribution
Provider' s system; and/or (iii) redemption, defeasance or
financing of Bonds (the "Refinancing"). Among other things, the
costs of Refinancing shall include (A) the costs, including, but
not limited to, increased interest cost of refinancing any
outstanding Bonds which must be redeemed or defeased, (B) the
increased interest costs associated with the inclusion in gross
income for Federal income tax purposes of interest on any debt to
be issued to finance the distribution and generation facilities of
Transmission Provider and (C) any increased income and franchise
tax liability of Distribution Provider resulting from the loss of
deductibility of interest expense associated with interest on any
Bonds issued or to be issued for the benefit of Distribution
Provider. For purposes of computing costa resulting from
increased interest cOsts associated with (B), it shall be assumed
that Distribution Provider will have access to State of California
private activity bond volume cap under Section 146 of the Code to
finance distribution system costs to the same proportionate extent
as Distribution Provider's post-198S distribution system costs in
fact have been financed with tax-exempt Bonds.
---------.
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.45
ATTACHMENT A
Form Of Service Agreement For
Wholesale Distribution Service
1.0 This Service Agreement, dated as of is entered into, by
- and between Ithe Distribution Provider), and
("Distribution Customer").
-
2.0 The Distribution Customer has been determined by the Distribution
Provider to have a Completed Application for Firm point-To-point Distribution
Service under the Wholesale Distribution Tariff.
3.0 The Distribution Customer has provided to the Distribution Provider an
Application deposit in accordance with the provisions of Section lS.3 of the
Tariff.
4.0 Service under this agreement shall commence on the later of (l) the
requested service commencement date, or (2) the date on which construction of
any Direct Assignment Facilities are completed, or (31 such other date as it
is permitted to become effective by the Commission. Service under this agree-
ment shall terminate on such date as mutually agreed upon by the parties.
5.0 The Distribution Provider agrees to provide and the Distribution
Customer agrees to take and pay for Firm point-To-point Diatribution Service
in accordance with the provisions of Part II of the Tariff and this service
Agreement and Schedules attached here to.
6.0 The Distribution Customer shall make a customer advance payment to the
Distribution provider for all Direct Assignment Facilities at the time it
returns an executed Service Agreement.
7.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other Party as indicated
below.
San Diego Gas &< Electric Company Open Access Distribution Tariff
original Sheet NO. 46
Distribution Provider:
Distribution CUstomer: .-
-
8.0 Interconnection -
8.l Interconnection of Distribution Customer' s Wholesale Distribution
Load:
8.1.1 Direct Assignment Facilities for the interconnection of the
Distribution customer' s Wholesale Distribution Load to the
Distribution Provider's Distribution Facilities shall be
installed, operated and maintained in accordance with Good
Utility Practice.
8.1.2 The Distribution Customer shall specify: (i) the voltage
level of service desired, provided such voltage shall be
compatible with standard voltages used on the Distribution
Provider' s system, and (ii) any applicable service criteria
of the Distribution Customer, including, but not limited to,
any redundancy desired in elements available to service
Wholesale Distribution Load from Distribution Provider' s
Distribution Facilities. If technically feasible, the
Distribution Provider shall provide service at such voltage
and in accordance with such criteria, conditioned on the
Distribution Provider obtaining any necessary regulatory
permits and complying with any other federal. state, or
local requirements for the construction of any such
facilities.
8.1.3 The Distribution Customer shall keep the Distribution
Provider informed on a timely basis of changes in Wholesale
Distribution Load and cooperate in planning any addition to
or upgrade of Direct Assignment Facilities to accommodate
--. ------------.-------..-----..--------------- --- ....----..-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.4 7
load growth or additions. The Distribution Customer shall
provide to the Distribution provider by September 1 of each
year an update of its total load by delivery point and its
amount of interruptible load (location, conditions, and
limitations) for the following five calendar years.
- 8.1.4 The Distribution Provider shall own, operate, and maintain
all Direct Assignment Facilities on the DistributiOn
provider' s side of the point of Deli very. The Distribution
customer shall pay all costs and expenses for such Direct
Assignment Facilities that are used exclusively to provide
Distribution Service to the Distribution Customer including,
but not limited to, the costs of permitting, planning,
procuring, constructing, owning, maintaining, and operating
any such facilities.
8.1. 5 The Distribution CUstomer shall provide and maintain, at its
sole expense, facilities on its side of the Point of
Delivery in accordance with Good Utility practice. The
Distribution Customer shall install protective equipment on
its system and take any other reasonable measures to protect
the safe and reliable operation of the Distribution
provider's system from disturbances on the Distribution
Customer' s system in accordance with Good Utility Practice.
8.1. 6 If the Distribution Customer does not maintain its power
factor pursuant to the provisions of the Tariff, then the
Distribution Provider will charge the Distribution Customers
a Power Factor Adjustment Charge pursuant to the provisions
of this Tariff.
8.1.7 The Distribution Customer shall provide the Distribution
Provider access to the Distribution Customer's
interconnection facilities to the extent necessary for the
Distribution Provider to construct, operate, or maintain
interconnection facilities. The Distribution Customer
agrees to grant the Distribution Provider all necessary
easements and rights of way, including adequate and
continuing access rights, on the property of the
Distribution Customer to transport, install, operate,
- -------.------- -----.------------ -----
San Diego Gas & Electric Company Open Access Distribution Tariff
Odginal S.heet Na.48
maintain, replace, and remove the interconnection
facilities, and any equipment or line extension that may be
provided, owned, operated and maintained by the Distribution
provider an the property of the Distribution customer. The
Distribution Customer agrees to grant such easements and
rights of way to the Distribution Provider at no cost and in
a form satisfactory to the Distribution Provider and capable
of being recorded in the office of the County recorder.
8.1.8 The Parties shall cooperate with one another in scheduling
maintenance to any interconnection Facility or in taking any
interconnection facility out of service, provided that in an
emergency the Distribution Provider may take facilities out
of service if necessary to protect the Distribution
Provider's system.
8.2 Interconnection of Distribution CUstomer's Generation
-
8.2.l The Distribution CUstomer shall interconnect its Generation
with the Distribution Provider' s Distribution Facilities in
accordance with all applicable ISO, WSCC and NERC criteria,
and Good Utility Practice.
8.2.2 The Distribution Customer, at its sole expense, shall
design, own, procure. install, operate and maintain all
equipment and facilities, including the Generation, on its
side of the Point of Receipt (Distribution Customer' s
Facilities). The Distribution Provider shall design, own,
install, and maintain all facilities necessary to
interconnect the Distribution Customer's Generation on the
Distribution Provider's side of the Point of Receipt
IDistribution Direct Assignment Facilities) at the
Distribution CUstomer' s sole expense to the Extent permitted
by Commission policies. Such facilities shall include any
equipment necessary to protect the Distribution Provider's
electric system, employees, and customers from damage or
injury arising out of or connected with the operation of the
Distribution Customer' s Facilities, including, but not
limited to, short circuit protection, breaker
closing/rec1osing control. unit tripping, loss of
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet NCI.49
synchronism, over current/under current devices such as
relays, remote terminal units, circuit breakers, and meters.
The Distribution Customer's Facilities, and their operation
and maintenance, shall meet the Distribution provider' s
specifications and shall be subject to inspection and
testing by the Distribution Provider. follows,
8.2.2.1 Design of Interconnection Facilities
The Distribution customer, at Distribution Customer's
sole expense, shall acquire all permits and approvals
and complete all environmental impact studies
necessary for the design, construction, installation,
ope rat ion, and maintenance of the InterConnection
Facilities.
The Distribution Customer shall provide to the
Distribution Provider Distribution Customer's
electrical specifications and design drawings pertain-
ing to the Interconnection Facilities for Distribution
Provider' s review prior to finalizing design of the
Interconnection Facilities and before beginning
construction work based on such specifications and
drawings. Distribution Customer shall provide to the
Distribution provider reasonable advance written
notice of any changes in the Interconnection
Facilities and provide to the Distribution Provider
specifications and design drawings of any such changes
for the Distribution Provider's review and approval.
The Distribution provider may require modifications to
such specifications and designs as it deems necessary
to allow the Distribution provider to operate the
Distribution Provider's electrical system in
accordance with Good Utility Practices.
8.2.2.2 Interconnection Specifications for All
Generators
- .._- ----~------------_.--------- ------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.50
A means of disconnection must be available on both
sides of the Distribution Provider' s metering and must
be under the control of the Distribution Provider.
Disconnection can be accomplished with switches, load
break elbows, cutouts or secondary breakers.
Generator disconnects can also be used provided that
the switches meet with the Distribution Provider' s
approval and the Distribution Provider has preemptive
control. Generator's with three-phase generators
should be aware that certain conditions in the
Distribution Provider's system may cause negative --
sequence currents to flow in the generator. It is the
sale responsibility of the Generator to protect its
equipment from excessive negative sequence currents.
The Generator will be required to provide suitable
devices to ensure adequate protection for:
a) all faults on the Generator' s system
b) all faults on the Distribution Provider's system
c) back feed or start-up of a generator into a dead
utility bus
The following Generator protective devices are
required as a minimum to effect connection and
separation of the Distribution Provider and Generator
IFor induction generators below 10 kW, the following
are recommended but not required.):
a) individual phase over current trip devices,
b) under voltage trip devices,
c) over/under frequency trip devices,
d) synchronizing or equivalent controls, either
automatic or manual, supervised by a
synchronizing relay if over 1 MW, to ensure a
smooth connection with the Distribution
Provider' s system.
--.---------.-
-
San Diego Gas & Blectric Company Open Access Distribution Tariff
Original Sheet No.51
For synchronous generators, sufficient generator
reactive capability shall be provided to withstand
normal voltage changes on the Distribution Provider's
electric system. For induction generators, capacitor
installations will likely be required for reactive
- power support. Such capacitors will be at the expense
of the Distribution Customer. For induction
generators less than 100 kW, some of the trip devices
may be waived by the Distribution Provider.
- 8.2.2.3 Additional Interconnection Design Specifications
Generators interconnected above 50 kV must be equipped
- with Power System Stabilizers. The Distribution
configuration must meet the Distribution provider's
and the WSCC regional reliability criteria.
-
Where interconnection is at or below 480 v, the
Generator shall be served by a dedicated transformer
except in the following circumstances: a) the
generator is under 10 kW, or b) the generator is an
under 100 kW induction generator that explicitly
provides for 24-hour immediate access by the
Distribution Provider to all interconnection
facilities.
For Generator capacity above 100 kW, Generator shall
also (a) install relaying to provide adequate
- protection for unbalanced or single phase conditions
on the Distribution Provider' s system or deteriorating
voltage waveform conditions on the generator and (b)
install sensitive current unbalance relays
For Generator capacity greater than 1 MW, Generator
shall also provide sensitive ground protection.
San Diego Gas & Electric Company Open Access Distribution Tariff
Original S.heet No.52
For Generator capacity greater than 2 MW, Generator
shall also provide telemetering of generator output to
the Distribution Provider.
For Generator capacity of 5 MW or greater, the
Distribution Customer shall provide a: a} a -
complete supervisory control system, including
indication of the Generator' s main breaker, allowing
operation of Generator from the Distribution
Provider's control center, or
-
9.0 Interconnection Facilities and Review Disclaimer
~
Distribution Providers review of the design, construction,
operation, or maintenance of Interconnection Facilities or
-
Generation facility shall not constitute any representation as to
the economic or technical feasibility, operational capability, or
reliability of such Facilities. Distribution Customer shall in no -
way represent to any third party that any such review by
Distribution Provider of such Facilities is a representation by
Distribution Provider as to the economic or technical feasibility,
operational capability, or reliability of such Facilities.
Distribution Customer is solely responsible for economic and
technical feasibility, operational capability, and reliability of
the Interconnection Facilities and the Generation facility.
Distribution Provider shall notify Distribution Customer in
-
writing of the outcome of Distribution Provider's review of the
design and all of the specifications, drawings, and explanatory
material for Distribution Customer's Interconnection Facilities
(and the Generation facility, if requested by Distribution
Provider) within thirty 130) calendar days of the receipt of the
design and all of the epecifications, drawings, and explanatory
material for the Interconnection Facilities (and the Generation
facility, if requested by Distribution Provider). Any flaws in
the design perceived by Distribution Provider in the review of all
---- -------.- -..----------- - -------- - -..------.--.--
San Diego Gas &, Electric Company Open Access Distribution Tariff
original Shee.t No. 53
of the specifications, drawings, and explanatory material for the
Interconnection Facilities (and the Generation facility, if
requested by Distribution Provider) shall be described in
Distribution Provider's written notification.
lO.O operational Aspects of Generation Interconnection
The Distribution Customer shall not commence parallel operation of
- the generating facility until written approval for operation of
the Interconnection Facilities has been given by Distribution
Provider. Such approval shall not be unreasonably withheld.
Distribution Customer shall notify Distribution Provider of
Distribution customer' s intent to energize the Interconnection
facilities not less than forty-five 145) calendar days prior to
such energizing. Distribution Provider shall have the right to
inspect the Interconnection Facilities within thirty (30) calendar
days of receipt of such notice. If the Interconnection Facilities
are not approved by Distribution Provider, Distribution Provider
shall provide written notice to Distribution Customer stating the
reasons for Distribution Provider' s disapproval within five (5)
calendar days of the inspection.
The Distribution Customer shall provide written notice to
Distribution provider at least fourteen 14) calendar days prior to
the initial and subsequent testing of the Protective Apparatus.
The protective Apparatus shall be tested thereafter at intervals
not to exceed three 13) years using qualified personnel.
Distribution provider shall have the right to have a
representative present at the initial and subsequent testing of
the protective Apparatus and to receive 'copies of the test
results.
Distribution Customer shall operate and maintain the
Interconnection Facilities in accordance with Good utility
practices.
10.l Nominal Voltage and Grounding
- -----.----.-----....- - . ..------------.-.
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 54
Distribution provider' s most common voltages are as follows:
a) Distribution system voltages are 4 and l2 kV
The majority of the common distribution voltages are grounded.
Distribution Provider will provide information on the specific --
circuit serving the Generator.
-
10.2 Operating Requirements for Generators
In order for Distribution Provider to supply and maintain proper
voltages to its Native Load Customers, Distribution Provider
electric system voltages may fluctuate from the nominal values. -
Distribution Provider uses various regulation techniques to raise
and lower both distribution and transmission system voltages in
order to maintain desired customer service voltage - Generators
shall design and operate its facilities to withstand such voltage
changes and to respond with proper power factor adjustment in ..-
sufficient time so as not to interfere with Distribution
Provider' s voltage regulation.
Generators must assure that transformers serving both Native Load
Customers and the Generator shall be identified with a special tag
attached to the transformer or pole for. the purpose of notifying
Distribution Provider field crews of the possibility of back feed.
Distribution Provider may ground de-energized lines and equipment
upon which work will be performed. Distribution Provider may test
its electrical lines that have automatically tripped (de-
energized) due to a fault by reclosing the affected circuit at
least one time.
The Generator shall not reconnect his generator after a protective
device trip unless his system is energized from an Distribution
provider. Additionally, generator control circuit (s) must be
designed to prevent accidental generator connection to a dead
........
.-------.--
San Diego Gas & Electric Company Open Access Distribution Tariff
original Sheet No. S5
utility system. Design variations are acceptable provided the
requirements of this Exhibit are satisfied.
-
Distribution Customers with Generators interconnected above 50 kV
may be required to maintain a voltage schedule within specified
voltage ranges.
- lO. 3 Power Factor
Distribution Provider may require that the Distribution Customer
to maintain specified corrected power factors at peak load. In
-
this event, the Distribution Customer is responsible to maintain
such peak load corrected power factors at the point of Receipt, as
- specified by Distribution.
- Unless otherwise agreed, the Distribution Customer is required to
maintain a power factor within the rage of 0.95 leading to 0.95
lagging during daily peak hours from 10 AM to 6 PM. If consumption
- falls outside this range a power factor adjustment charge as
indicated in this Agreement will be charged.
-
10.4 Power Factor Maintenance and Future Changes in Target power Factor
Distribution Provider may change the target power factor from time
to time upon notice to Distribution Customer. Distribution
Provider shall allow reasonable lead time for corrective action by
- the Distribution Customer. If the Distribution Customer does not
comply with the new corrected power factor requirements,
Distribution provider may take the necessary corrective steps as
described in the Service Agreement.
- In no event shall Distribution Customer be responsible for their
reactive requirements (VARS) through the Transmission Owner Tariff
or the ISO Tariff and, in addition, incur responsibility for local
distribution power factor correction for the same VAR
requirements. If local power factor correction is installed at
Distribution Customer' s expense, such correction shall be credited
to the Distribution Customer's meter readings.
~---------_.~.__..-
San Diego Gas & Electric Company Open Access Distribution Tariff
Origin"l Sheet No. 56
-
ll. Real Property Rights
Distribution Customer agrees to grant Distribution provider all
necessary easements and rights of way, including adequate and
continuing access rights, on property of Distribution Customer to
transport, install, operate, maintain, replace, and remove the -
Direct Assignment Facilities, and any equipment or line extension
that may be provided, owned, operated and maintained by
Distribution Provider on the property of Distribution Customer.
Distribution Customer agrees to grant such easements and rights of
way to Distribution Provider at no cost and in a form satisfactory
to Distribution Provider and capable of being recorded in the
office of the County Recorder.
If any part of Distribution Provider' s Direct Assignment
Facilities, equipment, and/or line extension is to be installed on
property owned by other than Distribution Customer, or under the
j urisdict ion or control of any other individual, agency or
organization, Distribution Provider may, at its discretion and at
Distribution Customer's cost and expense obtain from the owners
thereof all necessary easements and rights of way including
adequate and continuing access rights, and/or such other grants,
consents and licenses, in a form satisfactory to Distribution
provider, for the construction, operation, maintenance, and
replacement of Direct Assignment Facilities, equipment, and/or
line extension upon such property.
If Distribution Provider does not elect to obtain or cannot obtain
such easements and rights of way. Distribution Customer shall
obtain them at its cost and expense. If Distribution CUstomer
requests, Distribution Provider shall cooperate with and assist
Distribution CUstomer in obtaining said easements and rights of
way. In any event, Distribution Customer shall reimburse
Distribution Provider for all costs incurred by Distribution
Provider in obtaining, attempting to obtain or assisting in
obtaining such easements and rights of way.
--....--....-....-...---- ...........--- -..-------..-.--
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.57
Distribution provider shall have the right of ingress to and
egress from the Generation facility at all reasonable hours for
any purposes reasonably connected with the Service Agreement or
the exercise of any and all rights secured to Distribution
Provider by law or its tariff schedules on file with the
- Commission.
- Distribution Provider shall have no obligation to Distribution
Customer for any loss, liability, damage, claim, cost, charge, or
expense due to Distribution provider's inability to acquire a
satisfactory right of way, easement or other real property
interest necessary to Distribution Provider's performance of its
obligations under the Service Agreement or this Tariff.
- Nothing in this Service Agreement shall be construed to require
Distribution Provider to acquire land rights through condemnation
or any other means for Distribution Customer either inside or
outside of Distribution Provider's service area unless
Distribution Provider shall in its sole discretion elect to do so.
l2. Assignment
Neither Party shall voluntarily assign its rights nor delegate its
duties under the Service Agreement without the written consent of
the other party, except in connection with the sale or merger of a
substantial portion of its properties. Any such assignment or
delegation made without such written consent shall be null and
void. Consent for assignment shall not be withheld unreasonably.
13. Non-Waiver
None of the provisions of the Service Agreement shall be
considered waived by either Party except when such waiver is given
in writing. The failure of any party at any time or times to
enforce any right or obligation with respect to any matter arising
in connection with the Service Agreement shall not constitute a
waiver as to future enforcement of that right or obligation or any
right or obligation of the Service Agreement.
-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 58
-
14. Section Headings
Section headings appearing in the Service Agreement are inserted
for convenience only and shall not be construed as interpretations
of text.
--
15. Governing Law
-
The serv'ice Agreement shall be interpreted, governed, and
construed under the laws of the State of California as if executed
and to be performed wholly within the State of California except -
to the extent disputes are the responsibility of the Commission.
-
16. Amendment, Modification or waiver
Any amendments or modifications to this Agreement, other than to
-
Attachment A, shall be in writing and agreed to by both parties.
The failure of any Party at any time or times to require
performance of any provision hereof shall in no manner affect the -
right at a later time to enforce the same. No waiver by any Party
of the breach of any term or covenant contained in this Agreement, -
whether by conduct or otherwise, shall be deemed to be construed
as a further or continuing waiver of any such breach or a waiver
of the breach of any other term or covenant unless such waiver is .-
in writing.
--
17. The Tariff is incorporated herein and made a part
hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
-
Distribution Provider:
--
By:
Name Title Date
-- ..---.----------.-----'---------------------- --------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 5~
Distribution Customer:
-
By:
Name Title Date
-
-
-
-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 60
Specifications For
Wholesale Distribution Service
-
1.0 Term of Transaction:
-
Start Date:
Termination Date:
-
2.0 Description of capacity and energy to be transmitted by Distribution
Provider including the electric Control Area in which the transaction -
originates.
3.0 Point (s) of Receipt:
Delivering Party:
Delivery Voltage,
--
4.0 point Is) of Delivery:
Receiving Party: -
Delivery Voltage:
5.0 Max.imum amount of capacity and energy to be transmitted: --
6.0 Designation of party (ies) subj ect to reciprocal service
obligation:
7.0 Name (s) of any Intervening Systems providing transmission
service: -
8.0 Service under this Agreement may be subject to some combination of the
charges detailed below. (The appropriate charges for individual transactions
will be determined in accordance with the terms and conditions of the Tariff.)
8.1 Customer Charge
-..----------------------------..- - -----..-
San Diego Gas & Electric Company Open Access Dis.tributicn Tariff
original Sheet No. 61
8.2 Distribution Demand Charge: (See Attachment A, Exhibit 7)
8.3 Cost of Ownership Charge: (See Attachment A, Exhibit 4)
-
8. 4a Customer Advance Associated with Direct Assignment Facilities: (See
- Attachment A, Exhibit la)
- 8. 4b Monthly Facilities charge Associated with Direct Assignment Facilities:
(See Attachment A, Exhibit lb)
8.5 Power Factor Adjustment Charge: ISee Attachment A, Exhibit 5)
-
8.6 Distribution Los.s Adjustment Charge: (See Attachment A, Exhibit 6)
-
8.7 System Impact Study Charge: (See Attachment B)
-
8. S Facilities Study Charge: (See Attachment C)
- 8.9 Transformer Loss Compensation Factor
For a Distribution Customer who is a generator, if the generation meter is on
the low voltage side of the generation transformer, a transformer loss
compensation factor shall be applied to determine the capacity and energy
delivered to the point of Receipt.
-
-
-
San Diego Gas & Electric company Open Access Distribution Tariff
Original Sheet No.6.
-
Distribution Service Agreement
Attachment A
-
Exhibit la
Calculation of Distribution Customer's Advance Payment
-
Distribution Customer
-
Project Name and Location
The total Advance payment for Direct As~ignment Facilities required for the
above proj ect prior to the start of construction is as follows: -
1. Direct Assignment Facilities Incurred by the Distribution Provider -
The Distribution Customer agrees to pay the Distribution provider's total
estimated cost of the facilities to serve the Distribution Customer, less
credits, if any.
(From Exhibit 2 - Direct Assignment Facilities) $
-
2. ITCC Tax
The Distribution CUstomer must pay the taxes on such contributions, in
addition to any other applicable contributions, such as facilities installed
by the Distribution Customer, and deeded to the Distribution provider.
IFrom Exhibit 3 - ITCC Tax) $
3. Total -
(Sum of Installation charge and ITCC Tax) $
-
If future relocation is required, it is not included in these cost
determinations. The Distribution Customer is responsible for the cost of
relocating the subject facilities herein. The future relocation costs will be -
determined at the time of relocation and are subject to approval by FERC.
--
.-....--------
San Diego Gas & Electric Company Open Access Dis~ribution Tariff
Original Sheet No. 63
Distribution Service Agreement
Attachment A
Exhibit lb
Calculation of Monthly Facilities Charge Associated
with Direct Assignment Facilities
-
Under the WDT, the Distribution Customer will be given one of two options to
- pay for Direct Assignment Facilities. First, the customer can elect to pay a
customer advance which will recover the total cost of these facilities at the
time he signs the Service Agreement. Second, the Distribution Customer can
elect to pay a Monthly Facilities Charge that will recover the annual cost of
these facilities. In the latter case, the customer will have to agree to pay
for the remaining cost of such facilities whether or not it takes service for
the full term specified in the Service Agreement.
If the Customer Elects to pay a monthly facilities charge the calculation of
the charge is as follows:
1. Total Initial Installation Charge
(Exhibit 2 Line 7) $ -
2. Annual Fix Carrying Charge INote A) - '
3. Annual Facili ties Charge (Line 1 & Line 2) $-
4. Monthly Facilities Charge (Line 3/12 Months) $_/mo.
Note A: The annual fix carrying charge will be derived to recover the
Distribution' S Provider's cost of capital. depreciaêion, O&M expenses.
property taxes, income taxes, etc. related with the Direct Assignment
Facilities.
._......-----~------ -------------_._-----
San Diego Gas & Electric Company Ope.n Access Distribution Tariff
Original Shee.t No. 64
Distribution
Service Agreement
Attachment A
Exhibit 2 - Direct Assignment Facilities
The following is the Distribution Provider' s site-specific estimate (Gross
Financial Costs -- labor, material, indirect and overhead cost components) for
the facilities required to provide Distribution Service to the above project.
-
It excludes any work on the Distribution Provider' s facilities which is done
for the convenience of the Distribution Provider, such as work to accommodate
future system expansion, or capacity increases.
Description of Direct Assignment Facilities to be installed:
1. Protection System Modifications $
(installation and reconfiguration of protective devices)
2. Power Factor Correction $
( - KVAR of (_I Fixed, I - I Switched Capacitors required
to attain - \ Power Factor)
3. Voltage Correction Devices S
(Installation of regulators, boosters, and capacitors)
4. Primary Extension Estimated Costs $
(Poles, conductors, other equipment)
5. Revenue Meters $
(Initial cost to install and the field set up revenue
meters, plus the administrative costs of setting up the
revenue data retrieval)
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Shee.t No.6S
6. Telecommunications Faci li ties $
(Initial payments to telephone company for the
-- installation of phone lines etc., plus related
telecommunications work by the Distribution Provider to
establish telecom links. Does not include on-going
- monthly service charges.)
7. Total Initial Installation Charge $
ISum of 1 through 7)
-
-
-
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 66
Distribution
Service Agreement
Attachment A
-
Exhibit 3 ITCC Tax
1. One-time advance payment by Distribution Customer
(From Exhibit 2 - Direct Assignment Facilities) $-
-
2. Value of trenching and conduits subj ect to ITCC (Description of
facilities) $ -
3. Total taxable amount (Sum of Items 1 thru 2) $-
4. Tax Rate 34%
S. Tax Due Tax Rate (line 4) x Taxable Amount (line 3)0 $ -
--
....-----...------
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No.67
Distribution
- Service Agreement
Attachment A
Exhibit 4 Coet of Ownership Charge
For Direct Assignment Facilities
The Cost of Ownership for Direct Assignment Facilities is the Distribution
Provider's on-going cost liabilities of owning and operating facilities,
including such costs as maintenance costs, replacement costs Idue to age and
normal life and deterioration}, and property taxes
1. Cost of Direct Assignment Facilities Installed by
the Distribution Provider (From line 7 of Exhibit 2 - Installation Charge)
$-
2. Cost of Direct Assignment Facilities Installed by Distribution Customer
or Others and Deeded to the
Distribution provider IBased on Distribution
CUstomer' s Gross Financial installed cost) $-
3. ITCC Tax IFrom line 5 of Exhibit 3 - ITCC Tax) $-
4. Total Cost Basis (Sum of line 1, line 2 and
line 3) $-
S. Applicable Cost of Ownership Rate INote A) _XX_ ,
(Rate to be determined at time of request)
6. Applicable Monthly Cost of Ownership
(line 4 x line 5) 112 $_/month
Note A: Cost of ownership rate to be determined by Distribution Provider to
recover ongoing costs Service Agreement
-.--..---------. ------....------.-------..-
San Diego Gas & Electric Company Open Access Distribution Tariff
original Sheet No. 68
Attachment A
Exhibit 5 Power Factor Adjustment Charge
-
The power factor adjustment charge will be designed to recover the
Distribution Provider' S incremental cost to install capacitor banks located at
Distribution Provider' s distribution substation level. The power factor
adjustment charge factor shall be calculated at the time a Distribution
Customer takes service under this Service Agreement.
-----.. -.-
San Diego Gas & Electric: Co.mpany Open Acc:ess Distribution Tariff
Original Sheet No.69
Service Agreement
Attachment A
Exhibit 6 Distribution Losses
-
A. Distribution Losses Applicable to a Dietribution Customer Who is an
Electric Utility
Based upon a case by case analysis, the Distribution Customer shall compensate
the Distribution Provider for the monthly energy losses that occur on its dis-
tribution system. The energy losses will be based upon the Distribution
Customer's maximum monthly demand and average energy use as applied to
standard engineering loss formulas. The energy losses thus calculated will be
converted to a percentage of the customers total average annual energy
consumption. This percentage amount will then be applied to the customers
monthly meter amount to adjust for distribution loss recovery by the
Distribution Provider.
Example
Assume a Distribution Customers average monthly energy consumption is 1, 000
MWH at the meter. Assume, based upon engineering formulas the customers
average qistribution losses are 50 MWH. The customers distribution loss
factor is calculated as 5%.
Based upon the above calculation, the Distribution provider on a monthly basis
will multiply the Customer's monthly metered energy consumption by 5%. The
resul tent energy losses times that months average monthly Power Exchange price
will be paid by the customer to the Distribution Provider. In this example,
the customer will pay Distribution Provider $1,250 (SO MWHs . 25 mills). This
assumes an average Power Exchange cost of 25 mills for the applicable month.
B. Distribution Losses Applicable to a Distribution Customer Who is a
Generator
Distribution losses applicable to the Services Agreement will reflect a
Distribution Loss Factor (DLF) of 1. O. The use of a DLF of 1. 00 implies that
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 70
there are no energy loss payments or credits associated with the generation of
energy under this service Agreement.
-
-.
-
--.------
San Diego Gas & Electric Company open Access Distribution Tariff
Original Sheet No.71
Service Agreement.
Attachment A
Exhibit 7a Calculation of Distribution Demand Charge for A Distribution
CUstomer Who is An Electric Utility
-
1. Allocated Preexisting Distribution Facilities
- (Note A) $ -
2. Annual Fix Carrying Cost (Note B) - '
-
3. Annual Revenue Requirements (Line 1 x Line 2) $ -
-
4. Monthly Demand charge ILine 3 / Note C) $ - /kw
Note A: The Distribution Provider shall do a special study to determine the
allocated portion of preexisting facilities that should be assigned to the
customer.
Note B: Note A: The annual fix carrying charge will be derived to recover the
Distribution's Provider' s cost of capital, depreciation, O&M expenses,
property taxes, income taxes, etc. related with the allocated preexisting
Distribut ion Faci li ties.
Note C: The sum of the CUstomers twelve monthly maximum demands as measured
at the Customer's meter.
-----------
San Diego Gaa & Electric Company Open Access Distribution Tariff
Original Sheet No. 72
Service Agreement
Attachment A
Exhibit 7b Calculation of Distribution Demand Charge for A Diatribution
--
Customer Who is A Generator
Although a Distribution Customer who ia a generator will not be charged for an -
allocated portion of pre-existing Distribution Facilities, he will be
responsible for the costs of distribution upgrades or an allocated portion of -
the upgrades that directly benefit him. The Distribution cuatomer will have
one of two options to pay for these upgrades. First, he can pay a Customer
Advance as calculated in Exhibit 7c or he can pay a monthly demand charge as -
derived in this Exhibit.
-
1. Distribution Upgrade or allocated portion thereof
INote A) $-
2. Annual Fix Carrying Cost INote B) - '
-.
3. Annual Revenue Requirements (Line 1 x Line 2) $-
4. Monthly Demand Charge (Line 3 I Note C) $_/kw
Note A: The Distribution Provider shall determine the upgrade or allocated
portion of the upgrade the Customer will pay. These upgrades will be
determined in the Facility Study.
Note B: The annual fix carrying charge will be derived to recover the
Diatribution' s Provider' s cost of capital, depreciation, O&M expenses,
property taxes, income taxes, etc. related with the upgrade.
Note C: The aum of the Customers twelve monthly maximum demands as measured
at the CUstomer's meter.
San Diego Gas & Electric Company Open Acce$s Distribution Tariff
O.riginal Sheet No.73
Distribution Service Agreement
Attachment A
Exhibit 7c
Calculation of Distribution Customer' s Advance Payment for a Distribution
Customer Who is a Generator
Distribution Customer
proj ect Name and Location
The total Advance payment for the upgrade facilities or an allocated portion
thereof required for the above project prior to the start of construction is
as follows:
1. Upgrade Costs or portion thereof incurred by the Distribution Provider
The Distribution Customer agrees to pay the Distribution Provider' S total
estimated cost of the facilities to serve the Distribution Customer, less
credits, if any.
$
2. ITCC Tax
The Distribution Customer must pay the taxes on such upgrades.
Calculation will be made similar to that shown in Exhibit 3 - ITCC Tax)
$
3. Total
(Sum of Installation Charge and ITCC Tax) $
San Diego Gas & Electric Company Open Access Distribution Tariff
Original Sheet No. 74
ATTACHMENT B
Methodology for Completing a System Impact Study
The Distribution Provider will assess the capability of its Distribution
System to provide the energy and capacity levels of the service requested. In
determining the level of capacity available for new service requests, the
-.
Distribut ion Provider may exclude, from capacity to be made available for new
service requests, that capacity needed to meet current and reasonably
forecasted load of Native Load Customers Service, previously pending
Applications for Distribution Service and existing contractual obligations
under other rate schedules.
The System Impact Study shall include:
. An assessment whether the Distribution Provider's existing Distribution
System is adequate to provide the requested service.
. A preliminary non-binding estimate of scope of the Direct Assigns
Facilities and Distribution System upgrades required to provide the requested
service.
,----- ------'---
San Diego Gas œ Electric Company Open Access Distribution Tariff
Original Sheet No.15
ATTACHMENT C
Methodology for Completing a Facility Study
The Distribution Provider will utilize the results of the completed
System Impact Study to,
. Determine the scope of the Direct Assigned Facilities and Distribution
System upgrades required to provide the requested service. INote that
the scope of required new upgraded facilities should generally be the
same as those determined in the System Impact Study. However,
additional or changing information about the requested service, or
changes to the Distribution Provider' s system may warrant an addition
assessment of the Distribution System impacts. Every reasonable effort
should be made to utilize the results of the System Impact Study to
avoid duplication of work.
. Determine the cost and schedule to construct the Direct Assigned
Facilities and perform Distribution System upgrades necessary to provide
the requested service.
Attachment 7
CITY COUNCIL AGENDA STATEMENT
ITEM dO
MEETING DATE: March 25. 2003
ITEM TITLE: Resolution 1) Approving selection of the energy consulting
team of Duncan, Weinberg, Genzer & Pembroke, McCarthy &
Berlin and Navigant Consulting, Inc. ("Duncan/Navigant") to
analyze the financial, legal and technical feasibility of various
possible municipal energy businesses, and alternatives thereto;
2) Authorizing and directing staff to negotiate a consultant services
contract with Duncan/Navigant consistent with the terms and
conditions outlined herein, and;
3) Directing staff to return with a final proposed agreement and
appropriatiån of funds for council consideration.
SUBMITTED BY: A:;,;",o, C<y M""gee ~
REVIEWED BY: C"' Ma",g~,.Dt TI ..----' ('15th' Vote, y,,- No.xl
In May 2001, in response to an unstable energy market, the City Council adopted the "City
of Chula Vista Energy Strategy and Action Plan" (Attachment 1). Components of that plan
included direction to staff to pursue a cost benefit analysis of:
1. Operating a municipal energy utility business, including the potential for ownership
and/or operation of all or a portion of the local distribution system;
2. Becoming a municipal aggregator for the purchase of electricity for City facilities,
residents and/or businesses; and
3. Partnering with the Port District to repower and/or acquire capacity in a reconstruction
of the South Bay Power Plant.
At that time, the City Council preserved future municipal energy utility options by adopting
an ordinance that established the City as a municipal utility.
Since May 2001, City staff has implemented many of the Energy Strategy action items,
and has developed considerable in-house expertise on energy issues. However, given the
complexity of energy issues, specialty consulting services are now necessary to complete
a cost/benefit options analysis.. To complete the analysis, staff issued a request for
proposal (RFP) for energy consultant services in December of 2002. The timing of this
analysis is ideal. The expiration of the electricity and natural gas franchise agreements
with San Diego Gas and Electric provide the City with a unique opportunity to evaluate and
make comparisons on the most cost effective means of providing reliable energy supply to
;;.o-{
March 25, 2003
Page 2 of 9
City facilities, residents and businesses and controlling at least some of the revenues
generated by the delivery of energy to local residents and businesses.
This report outlines staffs recommendation based on the consultant selection process.
RECOMMENDATION
Staff recommends that the City Council adopt a Resolution:
1. Approving selection of the energy consulting team of Duncan, Weinberg, Genzer
& Pembroke, McCarthy & Berlin and Navigant Consulting, Inc.
(UDuncan/NavigantU) to analyze the financial, legal and technical feasibility of
various possible municipal energy businesses, and alternatives thereto;
2. Authorizing and directing staff to negotiate a consultant services contract with
Duncan/Navigant consistent with the terms and conditions outlined herein, and;
3. Directing staff to return with a final proposed agreement and appropriation of
funds for Council consideration.
BOARDS/COMMISSIONS RECOMMENDATION
Not applicable.
DISCUSSION
During the course of implementing the elements of the Energy Strategy and the
development of its own expertise on energy issues, staff has become more keenly
aware of the potential opportunities of some form of a municipal energy utility business
(MEU). Whether or not some form of a municipal energy utility works for the City of
Chula Vista is the subject of the proposed MEU analysis. The following are
representative of the items that have peaked staffs interest in determining the feasibility
of an MEU in Chula Vista.
. U.S. Department of Energy data indicates that residential customers of an
investor owned utility paid rates 16% above those paid by customers of a publicly
owned system. Commercial customers paid 9% more.
. A municipal energy utility could provide greater local control over energy
revenues and programs. For example, current SDG&E programs for use of
Public Purpose fees and Rule 20a undergrounding fees are beneficial, but might
be improved and tailored to meet Chula Vista's goals and objectives under an
MEU. Currently these programs are subject to CPUC regulations and SDG&E's
own service territory-wide priorities.
. An MEU could be a valuable economic development tool to attract and retain
businesses and enhance local quality of life.
. The City has been contacted by three separate entities extolling the potential
benefits of an MEU. Although each contact was independent, the identification of
potential benefits were similar in nature and content.
c9()'~')...
March 25, 2003
Page30f9
. As an MEU, the City could also more directly control the procurement of a
renewal energy supply.
. The City's size, growth potential, local power generation options, and an expiring
energy franchise could present unique MEU opportunities.
A. Development of the MEU Study ScoPe of Work
In December 2002, staff issued an RFP for consulting services to evaluate
various possible MEU businesses, along with alternative approaches to meeting
the City's energy objectives. In preparing the RFP, staff reviewed numerous
RFPs on similar subjects that had been prepared, or were being prepared, for
issuance by other California public agencies. Staff also consulted with and
received input from SDG&E. Based on that input, staff implemented several
revisions to the RFP Scope of Work. Staff also solicited proposals from
consultants SDG&E recommended as qualified. Staff believes SDG&E input to
this process is important and will continue to solicit such input where appropriate.
The following city energy objectives were described in the RFP:
. Reliable energy supply delivered at stable rates
. A high level of customer service
. A cost benefit formula that justifies the City's time and investment
. An environmental benefit for City residents
. Broad distribution of MEU benefits
. The utilization of the MEU as an economic development tool to retain and
attract businesses
The RFP Scope of Work (Attachment 2) identified specific issues to be
addressed by the energy consultant. Highlights of that scope of work are
identified below. The scope of work was designed to get answers to the
questions: Is it desirable for the City to pursue the implementation of an MEU
business? If so, what form of MEU?
Specifically, the following information was required:
1. Identify the characteristics of Chula Vista that present opportunities or
challenges to MEU implementation.
2. Estimate and describe the costs, risks, potential environmental impacts
and vulnerabilities of MEU formation and implementation; determine how
such costs and risks can be managed and mitigated.
3. Describe the current legal, regulatory, political and economic framework in
which an MEU would operate, the challenges and opportunities presented
thereby, and approaches to overcoming and taking advantage of same.
4. Estimate the financial and human capital resources required for each
stage of municipalization.
5. Describe the potential benefits of an MEU operation in Chula Vista: In
what specific ways could a Chula Vista MEU deliver benefits not currently
provided by SDG&E?
6. Identify alternative/lower risk approaches to MEU implementation
;;20-3
March 25, 2003
Page 4 of 9
including potential partnerships with SDG&E.
7. If justified, recommend an initial MEU business model that would
implement City energy objectives.
B. The RFP Process
Issuance
On December 20, 2002, staff distributed the RFP by mail and email to more than
sixty energy-consulting firms (including SEMPRA, SDG&E's parent company).
On January 9, 2003 approximately nineteen representatives from fifteen
consulting firms attended the pre-bid conference. (SDG&E was also represented
at the pre-bid conference.)
Shortlist Selection
On February 7,2003 the City received nine responses to the City's RFP. A City
MEU Selection Committee, approved by the City Manager, was formed to
evaluate the proposals. This team included municipal industry experts as well as
City staff: Bill Carnahan, Executive Director of Southern California Public Power
Authority; David Wright, Deputy Director of City of Riverside Municipal Utility
Department; Sid Morris, Assistant City Manager; Maria Kachadoorian, Director of
Finance; Dave Byers, Director of Public Works-Operations; Glen Googins, Sr.
Assistant City Attorney; Michael Meacham, Special Operations Manager; and
Willie Gaters, Environmental Resource Manager.
A preliminary screening was conducted, and each proposal was numerically
scored and ranked based on the City's selection criteria published in the RFP.
The top five respondents to the RFP were placed on a short list for interviews.
ConsultinQ Firm Rank IAssiQned Score)
Selected for Interview Shortlist
. RW. Beck 1 (210)
. Duncan/Navigant 2 (201)
. Alliant Energy Integrated Services & SMH Team 3 (195)
. Black and Veatch 4 (188)
. GDS Associates & SAIC Team 5 (186)
Not Selected for Interview
. EES Consulting 6 (160)
. McDonald Partners & Michael Woods Team 7 (139)
. Astrum Utility Services Team 8 (123)
, I
March 25, 2003
Page 5 of 9
. Milbank, Tweed Team 9 (94)
Short listed teams were scheduled for interviews over a two-day period (March 5-
6). Each interview lasted approximately 2 hours. The int~rview process included
prepared questions that were provided to the energy consulting firms in advance
as well as proposal-specific and industry-specific questions from the outside
experts. The advance questions were designed to calibrate aspects of the
energy-consulting firm's proposal with the City's RFP objectives such as project
team make-up, assigned project manager, proposed tasks, deliverables, project
. costs, schedule, presentation style and consultant's knowledge of the industry.
The proposal-specific questions were designed to address the technical aspects
of each proposal that required clarification or expansion (e.g. specificity as to the
ratio of financial, technical, and legal services provided in the proposals to
address the City's scope of work). Industry-specific questions were asked by
the City's outside experts to gauge the energy consulting firm's understanding of
the current energy environment and to gauge the consultant's level of
sophistication.
Following the interviews, the energy-consulting firms were again numerically
scored and ranked based on overall presentation, technical expertise, cost, and
the ability to adequately address the proposed scope' of work. A key factor was
each respondents intent and ability to provide the City Council with a firm "go/no
go" recommendation on the implementation of an MEU business, or alternative
approaches. The City's MEU Selection Committee unanimously, ranked the top
two firms in the 1 and 2 positions. Duncan/Navigant and RW. Beck, respectively
were selected for further consideration.
Consultina Firm Interview Rankina lAssianed Score)
Selected for Further consideration
. DWG&P/MB and Navigant Consulting Team 1 (302)
(All City MEU Selection Committee members ranked team in number 1
position)
. R.W. Beck 2 (267)
(All City MEU Selection Committee members ranked team in number 2
position)
Not Selected for Further Consideration
. Alliant Energy Integrated Services & SMH Team 3 (202)
. GDS Associates & SAIC Team 4 (151)
. Black and Veatch 5 (145)
Reference checks were conducted on both finalists. In addition, each firm was
'JrJ-C:;
March 25, 2003
Page 6 of 9
requested to respond to an additional set of questions intended to "drill down" into
the experience/background of each that was most directly related to the scope of
work identified by the City. Examples of these questions include:
. Describe your team's level of knowledge with the Department of Water
Resources (DWR) power contracts.
. Describe any involvement your team has regarding ongoing discussions
pertaining to "exit fees" (Le., the charge by the State of California to local
jurisdictions to opt out of the State energy contracts).
. Provide a 5-year history, and relevant reference contacts, pertaining to
"go/no go" recommendations for municipalization efforts.
. Please address/justify the need for legal services as part of the Phase I
analysis.
Staff was particularly interested in the consultant's response to the question on
legal services. This component of the RFP was a major, differentiating point in the
comparison of the two finalists - Duncan/Navigant and R.W. Beck. As originally
submitted, the two proposals addressed the technical aspects of evaluating the
MEU options in a comparable fashion. One significant distinction between the two
proposals was that Duncan/Navigant also included an integrated legal and
legislativelregulatory analysis component. Staff's view is that a focused, integrated
legal analysis of issues like exit fees, potential cost of wires acquisition and
severance, corporate structure and risks and liabilities is crucial to informed
decision-m-aking in this complex area.
RW. Beck was given an opportunity to revise the relatively limited legal component
of its submittal in order to insure that staff could make an appropriate comparison of
the component parts of the proposals and their related costs. R.W. Beck did
identify qualified legal counsel with whom the City could work; what remained
missing, however, was an integrated legal/business analysis with a set cost
amount.
Contract Cost
Duncan/Naviqant: The original cost proposal submitted by Duncan/Navigant was
$330,000. Based on preliminary discussions regarding clarification of scope and
expenses, this amount was revised downward to $275,000, includinq expenses.
Work would be performed on a time and materials basis not to exceed $275,000.
RW. Beck: The original cost proposal from R.W. Beck was a fixed fee of $145,904
2J.hê expenses. Based on preliminary discussions regarding clarification of scope,
RW. Beck revised its proposal to include legal services that were estimated (but
not fixed) at $50,000. In addition, R.W. Beck's proposal assumed utilization of
existing City agreements for legal services to supplement its legal component.
Staff estimated that cost at between $25,000 - $50,000. In sum, this equates to a
total contract price estimated (but not fixed) at $225,000 - $250,000 2J.hê expenses.
Consultant Recommendation
~') ¡j ,- (,..,
March 25, 2003
Page 7 of 9
Staff is recommending a contract with the Duncan/Navigant group based on the
following analysis:
. The proposal as originally submitted (Attachment 3) was complete in its
approach, addressing all of the major scope of work components.
. The consultant team Duncan/Navigant has a longstanding working
relationship with one another, and past efforts by this group reflect
extensive, detailed research in addressing the client's concems.
. Duncan/Navigant was most knowledgeable in identifying the South Bay
Power Plant and other possible local generation options as a potential key
opportunity for a Chula Vista MEU.
. Duncan/Navigant was most clear in its intent and ability to provide the City
with an "actionable intelligence" .
. The consultant has relevant Califomia experience including extensive work
with Califomia regulatory agencies.
. The consultant has demonstrated the experience and ability to deliver a
report on time, within budget and according to established criteria.
. The consultant team exhibited the best overall breadth and depth of energy
industry sophistication.
. Duncan/Navigant offered the greatest number of hours applied to the task,
approaching, in many respects, a phase II level of analysis.
Overall, the Duncan/Navigant team was identified as providing the best balance of
skills and expertise necessary to deliver the required scope of work.
If approved, staff will retum to Council with a final contract consistent with the scope
as outlined in the RFP.
Consultant Selection Guidelines
The consultant selection process complies with the guidelines established by the
City. The proposed consultant has performed no work for the City, and eamed no
money, during the past twelve months. Further, Duncan/Navigant has identified no
potential conflicts of interest.
C. Citv StrenQths and Weaknesses
During the interviews, consultants were asked to identify the City's strategic
strengths and weaknesses with regard to formation of an MEU business.
Consistently, Consultants identified the following strengths:
. A proactive City Council. A successful municipalization effort requires
community leaders to champion the effort.
. A comprehensive Energy Strategy
. A Franchise Agreement, which expires in 2003.
.J7
March 25, 2003
Page 8 of 9
. A growing housing, commercial and industrial base.
. The City already owns energy infrastructure that has produced savings:
(streetlights), and operates it¡¡ own utility system (sewer).
. "Economy of Scale." A Chula Vista MEU customer base would be in the
top 15 of all 48 utilities in California and would be in the top 50 to 100 of
more than 2,000 public utilities nationwide (if the entire existing and
proposed new developed territories are included).
. New (Greenfield) development could represent an excellent "low level of
investment" opportunity to begin a municipal utility.
. Chula Vista is roughly the size of a utility "regional office." Since utilities
cover large areas, regional offices are set up as individual profits centers
to better manage safety, reliability and operating costs.
. Chula Vista has an attractive energy (gas and electricity) load profile that
would attract competitive bids for power contracts from private and public
power providers.
. Attractive supply options exist with the potential repowering of the South
Bay Power Plant.
The energy consultants also commented that the City's strategic weaknesses
include the following:
. SDG&E is likely to mount an aggressive challenge to any municipalization
effort.
. A stabilizing energy market - in the near term - could draw consumer
attention away from rising cost of energy.
. The financing cost of new construction and/or acquisition of energy
infrastructure will be a major issue.
. The configuration, availability and proximity of energy infrastructure (gas
pipes and electricity transmission) will present a challenge.
. Legislative changes on the state and federal level will influence the
feasibility of all options since exit fees; stranded costs and severance fees
are currently being established, and may change in the future.
"Ìl\-ï?
March 25, 2003
Page90f9
FISCAL IMPACTS
Adoption of the proposed resolution requires an appropriation from the unappropriated
balance of the General Fund. The cost proposal for the MEU Analysis is for a
guaranteed maximum price of $275,000 including expenses. Given the importance of
this study in helping to compare the relative value of a long-term franchise renewal and
on MEU business, staff believes this expenditure is more than justified.
ATTACHMENTS:
1. City Energy Plan and Action Plan or Energy Strategy
2. MEU Scope of Work
3. Duncan Weinberg Genzer & Pembroke/McCarthy & Berlin and Navigant
Consulting Team Proposal
i
I
\
~o-q
-----------.-------------.-- -------