HomeMy WebLinkAboutAgenda Packet 2001/04/17 ADJOURNED REGULAR MEETING OF THE CITY COUNCIL
I declare under penalty of perjury that I am
employed by the City of Chula Vista in the
AGENDA Office of the City Clerk and that I posted this
document on the bulletin board according to
Brown Act requirements.
Council Chambers Dated / ,, Signed.
Public Services Building
276 Fourth Avenue
April 17, 2001 4:00 P.M.
CALL TO ORDER
ROLL CALL: Councilmembers Davis, Rindone, Padilla, Salas, and Mayor Horton
1. REPORT ON ASSESSMENT OF ENERGY MANAGEMENT OPTIONS FOR THE
CITY OF CHULA VISTA
In light of the State energy crisis, the City of Chula Vista secured the services of MRW &
Associates to provide an assessment of energy management options which may allow the
City to gain a measure of control over the City's demand and supply of energy as well as
the financial costs of the City's energy use. This report presents a portfolio of options for
the near and long term and stafI~s recommended actions. Staff recommends the City
Council accept the report and direct staff to bring back energy strategy implementing
resolutions for Council consideration.
ORAL COMMUNICATIONS
ADJOURNMENT to the Regular Meeting of April 24, 2001 at 6:00 p.m. in the Council
Chambers.
I declare under penally 01 perjury Ihal I am
employed by the City of Chula Vista in the.
Office 01 the City Clerk and that I posted this
document on the bulletin board according 10 .
Brown Act re uirementa. ~ ~
Dated ,¡/;~, Signed 'N. .~.
NOTICE OF CANCELLATION/ADJOURNMENT OF MEETING
OF THE CHULA VISTA CITY COUNCIL
NOTICE IS HEREBY GIVEN that the Regular City Council Meeting scheduled
for Tuesday, April 17, 2001 has been cancelled in accordance with Chula Vista
Municipal Code, Section 2.04.020.
The City Council will meet for an Adjourned Regular Meeting on Tuesday, April
17,2001 at 4:00 p.m. in the Council Chambers, located in the Public Services
Building, 276 Fourth Avenue, California. The purpose of the Adjourned Meeting
is to discuss energy-related issues.
Dated April 12, 2001 ~
Lorraine Bennett, Deputy City Clerk
--~----- -
Community Development Department
INFORMATION
(~r~' OF Chula Vista, Ca 91910 MEMO
CHULA VISTA 619.691.5047 -619.476.5310 Fax
cvcomdev@ci.ch ula-vist a.ca.us
TO: The Honorable May/~and Councilmembers
VIA: David D. Rowlan~'7~ity Manager
FROM: Chris Salomone, Community Development Director
DATE: April 12, 2001
RE: Energy Management Options Report
BACKGROUND
In light of the State's energy crisis, the City of Chola Vista secured the services of MRW and
Associates to provide an assessment of energy management options which may allow the City
to gain a measure of control over the City's demand and supply of energy as well as the
financial costs of the City's energy use over time. Transmitted herewith is the final Energy
Management Options Report from MRW accompanied by a staff prepared Executive Summary.
Additionally, a comprehensive Legislative Update from MRW is provided outlining recent
significant legislation and Executive Orders as well as proposed legislation that collectively
form the basis for staff's recommended legislative strategy.
As Council will read, MRW provided broad general options/recommendations with staff
recommending a variety of action items to implement or advance them to the extent possible
or feasible. The majority of the report is MRW's analysis of the state of the energy markets
and the legislation recently enacted or proposed to correct the impacts of deregulation. The
report also includes their recommendations for action with case studies that describe similar
actions and outcomes by other California jurisdictions. Additionally, the report contains a
summary of energy conservation efforts that Council has previously directed staff to implement
and the positive impacts that those actions have already had on City facilities, residents,
businesses and development activities.
Finally, it is important to note that the report does not contain an easy or quick solution to the
energy crisis for Chula Vista. If such a solution exists, it lies in the hands of state and federal
authorities, not the City. The report does include however, the best-known options at this
time for developing an Energy Strategy and Action Plan best suited to respond to the unique
opportunities and needs for Chula Vista. It is hoped that through these efforts, the City can
prevent energy from being a limiting factor in the economic future and sustainable growth of
our community.
Energy Management Options Report
Page 2
April 12, 2001
CITY COUNCIL WORKSHOP
A City Council Workshop has been scheduled for Tuesday, April 17 at 4:00 p.m. in the Council
Chambers (since there is expected to be a larger than normal audience for this workshop).
Representatives from the consultant team will present their report and
options/recommendations. Staff will then follow with a presentation of recommended actions.
A summary of the Governor's overall plan for addressing the crisis will be provided as well.
Representatives from Duke Energy, SDG&E and BFGoodrich have been invited to attend.
Additionally, the Planning Commission, Economic Development Commission, and Resource
Conservation Commission will be advised of the workshop and have expressed an interest in
attending. After receiving input and direction from Council, staff will return at a regular
Council meeting with a recommended Energy Strategy and Action Plan for formal Council
adoption.
RECOMMENDED ACTIONS
As will be more fully discussed at the workshop, provided on the following page are the
recommended actions the City should pursue and/or further evaluate at this time. The
recommended options/actions (discussed in greater detail in the Executive Summary) are
provided within three (3) broad-based categories determined by risk-level and benefit time
frames; I) Highly Recommended (Low Risk/Short-term Payoff), 2) Promising (Increased
Risk/Medium-term Payoff) and 3) Higher Risk (High Risk/Long-term Payoff). Generally, the
options/actions with Iow-risk and short-term benefits (Highly Recommended) are those that
positively effect the energy demand side (i.e.,. conservation and therefore, reduced
consumption Costs) whereas the actions with increased and significant risks with medium- and
long-term benefits (Promising and Higher Risk) could positively effect the energy supply side
(i.e., distributed generation, utility municipalization, and municipal aggregation) that promote
reliability, price stability and economic development opportunities.
Staff's recommendations tend to place a priority on those options that produce tangible results
for businesses, residents and City operations regardless of what occurs in the energy market or
at the State legislature. It is important to note that, particularly on the energy supply actions,
staff recommends taking concurrent proactive steps on a variety of fronts (i.e., Duke and
SDG&E negotiations as well as Distributed Generation projects) in order to keep options open
and be poised to take further action as opportunities present themselves or are precluded by
further analysis, negotiations, and future legislative actions.
Please review the staff executive summary of the report for greater detail on staff's
recommendations. Each of the following recommended actions have a number of specific
action items that are fully discussed in the Executive Summary and will be outlined in the
workshop.
1. Highly Recommended Options (Low Risk/Short-term Payoff)
A. Continue/expand energy conservation projects for City facilities
B. Continue/expand and promote energy efficient and renewable energy programs
for businesses and residents as well as provide community education
Energy Management Options Report
Page 3
April 12, 2001
C. Monitor the market and legal restrictions and be prepared to enter into an
electrical services contract with an Energy Services Provider as allowed by law
D. Develop and implement a legislative strategy that facilitates the City's overall
Energy Plan
E. Continue/expand efforts to implement the Carbon Dioxide (CO2) Reduction Plan
and GreenStar Building Incentive Program (Staff generated; not included in MRW
report)
2. Promising Options (Increased Risk and/or Medium-term Payoff)
A. Pursue Distributed Generation opportunities
i. City Facilities (New Corporation Yard; Civic Center/Police Facility;
Library and Recreation facilities
ii. Economic Development Opportunities (BFG; Maxwell Road site;
LandBank site)
B. Monitor the market and legal restrictions and be prepared to enter into a bilateral
agreement with a power generator
C. Partner with a third-party to build and operate power generation facilities
D. Develop an emissions offsets program based on mobile sources (as permitted by
law)
3. Higher Risk Options {Significant Risk and Long-Term Payoff)
A. Form a Municipal Distribution Utility to own/operate all or portions of local
distribution system
B. Become a municipal "aggregator' and acquire electricity at negotiated rates for
the City, and included residents and businesses (if "opt out" legislation is
passed) (as permitted by law)
4. Legislative Strategy
Support measures that:
A. Assist the City and its energy consumers improve supply/demand conditions and
enhance conservation measures.
B. Preserve local options to control and fund the supply and distribution of energy
(including the formation of a municipal utility district) or that fund conservation
programs.
C. Enhance the City's ability to enter into distributed generation agreements
without having to pay stranded transmission or distribution charges.
D. Impose wholesale price caps based on fair and reasonable costs and rates of
return.
E. Repeal the provision in AB l X that suspends customer choice, and pass a
favorable bill for customer choice (SB 27X or a similar one).
F.Make municipal aggregation programs available on an "opt-out" basis.
Energy Management Options Report
Page 4
April 12, 2001
G. Allow public agencies (not just municipal utilities) such as the City to participate
in state power supply programs.
Oppose measures that:
A. Impinge on or restrict the City's ability to exercise land use review/control with
respect to the generation or transmission of power.
B. Erode the City's ability to acquire power from alternative soruces, operate as a
municipal utility, or enter into aggregation distributed generation arrangements.
SUMMARY
Staff's recommendations attempt to make progress, to the extent the City can, on both the
demand and supply sides of the energy market. Certainly the City has the ability to
immediately affect the demand side to a much greater degree than the supply side; particularly
in the short run. The recommendations reflect the City's commitment to expand our strong
record in energy conservation and the promotion and use of renewable energy sources.
Relative to the supply side, it is important to note that there are a significant number of new
plants, both major power plants and smaller peaker plants, in various stages of development
and approval that will make a tremendous difference on supply statewide over the next several
years. The California Energy Commission (CEC) is currently reporting that it has in its
application process, 13 projects expected to deliver a net capacity amount of 6,187 MW of
new power supply. This includes the 510 MW Otay Mesa plant. Additionally, CEC reports
that there are currently 29 peaker plant applications statewide being processed under the
Governor's emergency siting authority. These peakers are expected to deliver a total of 3,219
MW of peak load generation capacity including the Otay Mesa Larkspur project (90 MW) and
the proposed second peaker on Main Street in Chula Vista (57 MW). However, these plants
will be primarily utilizing natural gas and therefore further taxing the limited supply of natural
gas to the State and San Diego region (Section 2.6 of report). Long-term supply issues need
to address natural gas supply, and in the process, could pave the way for greater market
potential for renewable energy sources.
NEXT STEPS
Council will be asked to provide staff with direction on the recommended actions/options and
legislative strategy. Based upon that direction, staff will return with a recommended Energy
Strategy and Action Plan for Council consideration. The Energy Strategy will include an overall
project management team structure.
J:\COMMDEV\INFOMEMO\Energy Report.doc
MRW Assessment of Chula Vista's
Energy Management Options
[April 5, 20011
pyrDose of the R®..ert
1. In light of the State's energy crisis, the City of Chula Vista secured the serwces of MRW and
Associates to provide an assessment of energy management options which may allow the City to gain
a measure of control over the City's demand and supply of energy as well as the financial costs of the
City's energy use over time,
2. The report is to provide a historical perspective and analysis of California's deregulation of the
electricity market (first approved in 1996), and the dramatic developments in California's power and
natural gas markets. A better understanding of the events leading up to the energy crisis will help the
City of Chula Vista take a proactive approach to managing energy costs and supply.
3. Based on this understanding, present a portfolio of options that help to: (a) insulate the City, its
residents, and its businesses from unfair or unreasonable energy costs, (b} ensure the reliability of
electricity supply, and (c) reduce adverse environmental impacts of energy production and use,
4. Assemble the best options into the City's own Energy Action Plan. Identify the steps needed to
implement the plan. Begin to identify and evaluate specific projects that have the potential to create
unique opportunities and advantages for the residents and businesses of Chula Vista.
parameters of the Re.-ort
I. ~L~3~~
Electricity supply and cost is the primary focus of the report. Natural gas is a secondary focus albeit an
important one. Environmental impacts were considered, but were not the driving factor.
2.~
City-owned and operated facilities. The City currently uses 14 MWhrs of electricity per year. 40% of
that is used during off peak hours by street lights. The City's energy bill during year 2000 was $1.622
million. The February 2001 bill was $267,000 ($161,000 with a balancing account amount of
$106,000). At the average rate of $267,000 per month, the City's energy bill for 2001 would double
to $3.2 million.
Residents. City residents currently use an averaoe of 287,8 MWhrs of electricity per year. The City is
projecting that new housing developments will add more than 2,000 units in each of the next two
years. This represents an incremental demand for electricity of 11.8 million kWh, or 4,% of Chula
Vista's current residential demand.
Businesses, both current and future. City businesses currently use ~405 MWhrs of
electricity per year (commercial businesses use 304 MWhrs and industrial businesses use 101 MWhrs).
Chula Vista is home to a number of manufacturing facilities where energy costs are a substantial
component of overall costs. Providing these manufacturers with the means to manage energy costs will
provide an incentive for the manufacturers to remain in Chula Vista, expand their operations and create
new jobs. Energy incentive programs could also help attract new businesses to the City.
3. ~..-::.~.~me for ms~-'~. ~s to be Derived from In®rev Plan Adions · Short 'let'm: Benefits could be realized within the next 12 months and thereafter.
· Mediu,1 '/'erin: Benefits could be realized within the next I to 3 years.
· £e,~ Term: Benefits could be realized within the next 3 to 7 years.
Portfolio of Options
Consistent with the above-described purposes and parameters, MRW developed a portfolio of
12 options to help the City better manage its energy needs and costs. THESE OPTIONS ARE
EXPLAINED AND DISCUSSED IN GREATER DETAIL STARTING AT PAGE 7 AND ARE NOT ALL
RECOMMENDED TO BE PURSUED AT THIS TIME. Additionally, each of the options listed
below include specific tasks to implement.
Based on an assessment of the benefits and risks of these options, the current market
situation, and the implementation time frame for each option, MRW grouped the options into
the following categories:
HIGHLY RECOMMENDED [Options with Low or Manageable Risk and Potential for Short-Term
Payoff]:
· Continue/expand energy conservation projects in existing and future City facilities.
· Continue/expand and promote energy efficiency and renewable energy programs for
businesses and residents as well as provide community education.
· Monitor the market and legal restrictions and be prepared to enter into a contract with an
Energy Service Provider (as permitted by law).*
· Develop and implement a legislative strategy that facilitates the City's overall Energy Plan.
· Continue/expand efforts to implement the Carbon Dioxide (CO2) Reduction Plan and
GreenStar Building Incentive Program (Staff generated; not in MRW Report).
PROMISING [Options that Offer Significant Benefits but with Increased Risk and/or Medium
Term Payoff]:
· Pursue distributed generation opportunities for both City facilities and economic
development opportunities.
· Monitor the market and legal restrictions and be prepared to enter into a bilateral
agreement with a power generator,
· Partner with a third party to build and operate power generation facilities,
· Develop an emissions offsets program based on mobile sources (as permitted by law), *
HIGHER RISK: [Op~ons that Require Large Capital Outlays and/or Carry Significant Business
Risks and have a Longer-Term Payoff]
· Finance, own, and operate large-scale power plant to meet a portion of the City's demand
for electricity. [Not recommended]
· Form a municipal distribution utility to own and operate all or portions of local distribution
system.
· Become a municipal "aggregator" and acquire electricity at negotiated rates for the City,
and include residents and businesses (as permitted by law)."
The passage of ABIX and the withdrawal of major ESPs from the market make these options effectively
unavailable at this time. However, proposed competing legislation and different interpretations of ABlX may
reverse this situation. Legislation will be needed to clarify relationship between AB1X prohibitions and
aggregation provisions. "Opt out" legislation would make this option much more attractive.
I;x~:..tiv~ .~*:mmarv - Th, lr~dRv. Anril 12.20al..q:l_q AM Peae 2
A Timeline of Key Events in California Electric
Industry Restructuring and Energy Crisis
Prior to Retail electricity customers purchased "bundled" transmission, distribution and
Deregulation generation services from monopoly utility companies. Bundled prices were
regulated by the CPUC on a "cost plus" basis. The average retail price for
bundled electricity during the 90's prior to deregulation was 9.5¢ per kWh.
1996 Governor Wilson signed AB 1890, putting California on course for deregulation.
Theory of law is to reduce energy costs to consumers by unbundling energy
services and offering access to alternative energy providers. The Independent
System Operators (ISO) is created to operate (but not own) the state's
transmission system. The Power Exchange (PX) is created to provide a
transparent spot market for power purchases. Investor owned utilities are
required to sell some of their power generation facilities and purchase their
power from the PX. Power is to be sold at the highest "clearing" price bid into
the market.
1997 The Public Utility Commission approves a request by San Diego Gas and Electric
to sell natural gas to Mexico to power the Rosarito generating facility.
1998 On April 1 the California Power Exchange began wholesale trading of electricity.
Initially, power prices were reasonable, if not Iow. During the first two years of
operation, the PX market averaged $29 per MWh (2.9 cents per kWh). Utilities
begin to divest themselves of generating assets.
1999 On July 1 the rate freeze is lifted in SDG&E's service territory. SDG&E is the
first to enter into the deregulated marketplace due to its rapid recovery of its
"stranded costs" (i.e., its unrecovered, pre-deregulation capital investment).
Recovery of stranded costs comes from sales proceeds well above its book
value for its power plants and stranded asset charges (CTCs) passed through to
ratepayers. As a result, customers' rates begin to reflect the wholesale power
prices paid by SDG&E, including the volatile PX market prices, Note: The rate
freeze is not lifted for Pacific Gas & Electric (PG&E) and Southern California
Edison ("SCE") customers setting up a situation where they cannot pass on
volatile wholesale prices to customers.
2000 May SDG&E customers' bills double from an average residential bill of $49 to $100
as the utility passes on high wholesale costs to consumers. The ISO declares
the first of 36 Stage Two alerts, when power reserves drop below 5 percent.
2000 June Rolling "brc;'.'.':.c::tcblackouts" in San Francisco affect hundreds of thousands of
customers. Insufficient power supplies due to several Northern California power
plants shut down for maintenance cause the ~;=;'.'.-.c;tcblackouts.
2000 SDG&E customers' bills have tripled. Wholesale electricity prices during the
August months of May through September 2000 increased dramatically in the PX and
ISO markets. In June 2000 prices were 411% higher than in June 1999,
increasing from $23 per MWh to $122 per MWh. (2.3¢ per kWh to 12.2¢ per
kWh.)
2000 High wholesale prices prompt Gov. Gray Davis to call for an investigation into
August "possible manipulation in the wholesale electricity marketplace".
2000 The CPUC approves a 6.5C/kWh rate ceiling plan for SDG&F residential and
September small business customers retroactive to June 1, 2000. (This action by the
CPUC was preceded by the passage of AB 265, which set the 6.5 cents/kWh
ceiling but needed to be implemented through a CPUC proceeding.) Larger
businesses (with usage above 100 KW) continue to be susceptible to volatile
wholesale prices. Electricity charges above 6.5 cents are not forgiven, but
tracked in "balancing accounts" for later payment. No provision is made for the
source of repayment. September 26: Davis signs two bills stemming from
power crisis in San Diego. One would spread energy price increase for San
Diego customers over several years, the other speeds up the approval process
for new power plants.
2000 Electricity and natural gas prices for the California markets reached record highs.
December Spot market prices for natural gas at the California border climbed to over $72
per MMBtu at one point on December 11, compared to prices of $2 to $3 in
1998 and 1999. December 7: For the first time, the ISO declares a Stage
Three emergency when power reserves fall below 1.5 percent. Officials say
conservation efforts averted rolling ~rc;:'.-.c:~tc blackouts throughout the state.
December 15: Based on an investigation into the electric markets in the
western United States, the Federal Energy Regulatory Commission (FERC) orders
a number of changes to the California electric market. These include: (a) $150
per MWh "soft" price cap on wholesale electricity to remain in place until at
least April 30, 2001; (b) an end to the utilities' obligation to buy and sell
electricity in the PX market; (c) a "benchmark price" of $74 per MWh for five-
year contracts; and (d) an order that the ISO governing board be replaced with a
non-stakeholder board. December 26: Southern California Edison sues FERC,
alleging the government body failed to ensure that wholesale electricity is sold
at "just and reasonable rates". The South Bay and Carlsbad generating plants
experienced 13 days of natural gas "curtailment," and were forced to run on
fuel oil or shutdown.
Power generators begin to refuse to sell power into the California ISO/PX
system on credit due to the increasing questionable credit worthiness of PG&E
and SCE. In response, federal authorities require generators to sell their excess
power into California if requested by the ISO.
2001 SCE and PG&E declare that they are teetering on the verge of bankruptcy.
January Because SCE and PG&E are unable to pass along to customers their full cost of
procuring power; they have seen their financial condition worsen every month
since the summer of 2000. In response, Governor Davis declares a state of
emergency. Emergency legislation allows the state Department of Water
Resources to buy and sell electricity up to a $400 million limit. This authority
expired on February 15, but is later extended. January 2: Davis joins SCE's
suit against FERC, filing a friend-of-the court brief. He says the commission
"has failed in its responsibility to protect Californians from what the agency
itself describes as a dysfunctional market for electricity% January 4: PUC
votes 5-0 tb approve rate hikes for PG&E and SCE. The increases are 9 percent
for homes, and between 7 percent and 15 percent for businesses.
2001 Governor Davis signs into law ABIX authorizing the Department of Water
February 1 Resources to begin buying power to serve California. Governor Davis sets a
target of $69 /MWh for a portfolio of long-term contracts. To date the
electricity contract information has been kept confidential by the Governor's
office. Multiple bills (discussed in the legislative update) are prepared to address
the crisis. Governor Davis is negotiating the possible state acquisition of the
utilities' transmission assets in an effort to restore the financial condition of the
utilities.
Governor Davis signed into law AB 1X authorizing the Department of Water
Resources to begin buying power to serve California. Governor Davis set a
target of $69/MWh for a portfolio of long-term contracts. AB 1X also suspended
direct access for California's retail electricity customers. The Legislature worked
through a review of multiple bills (discussed in the legislative update) to address
the crisis. Governor Davis attempted to negotiate the possible state acquisition
of the utilities' transmission assets in an effort to restore the financial condition
of the utilities. The Governor reached a tentative deal with SCE. Under the
terms of the deal with SCE, the state reportedly will pay about $2.7 billion, or
2.3 times book value, for the IOU's transmission assets. In return for the
infusion of cash from the state, SCE'is agreeing to a lO-year contract at cost-
plus rates for power from some of its assets. SCE also will be required to drop a
federal lawsuit in which it sought to back-bill customers for past procurement
costs.
2001 Qualified Facility (QF) owners and operators shut down plants totaling about
March 3,000 MW because they have not been paid by the utilities for several months
for energy deliveries. QF's include dozens of small and medium sized power
generators that use wind, solar, co-generation and other sources to produce
power. Due in part to the shut down of QF plants, rotating blackouts affected
customers in both southern and northern California on March 19 and 20. FERC
ordered power suppliers to refund $69 million, ruling that power suppliers
overcharged Californians by that amount in January. FERC found that
overcharges for power sold in February totaled $55 million. CaI-ISO filed a
report with FERC alleging power suppliers overcharged by $6.2 billion for power
delivered to California customers over the period May through November 2000.
March 27: The CPUC ordered a three-cent per kWh increase in electric retail
rates for Southern California Edison and PG&E customers.
2001 April April 5: In a televised statewide address, Governor Davis dropped his opposition
to increases in electricity rates and called on the state's residents to continue
conserving power. The Governor outlined a proposal for increasing electricity
rates that is similar to the CPUC's March decision. The Governor also said the
only long-term solution to the crisis is to build more power plants. The
Legislature approved a package of legislation that will make available $1.1 billion
for energy conservation programs. April 6: PG&E (the regulated utility) filed for
Chapter 11 bankruptcy protection after failing to come to an agreement with
Governor Davis on a state takeover of its transmission assets.
I;XAmltivA R~mmArv - Thair~tf~v. Anril 12. 2(}01. -q:l.q AM PA{IR ~
Market Outlook
Next f to f2 Months
· The outlook for wholesale electricity prices in the short term is extremely uncertain.
General market fundamentals point toward continued high and volatile prices during this
time frame.
· Some 2,368 MW of new generation is scheduled to come on line by the end of 2001, but
whether this along with increased conservation will be sufficient to fend off shortages is
unknown (shortages appear increasingly likely to occur).
· The vast majority of the proposed new power generation is dependent on natural gas.
Increased cost for natural gas has driven up the cost of producing electricity and is
expected to do so until new delivery capacity is added or conservation and alternative fuel
sources reduce the demand sufficiently below supply to reverse the price trends.
· Current efforts by the State of California (DWR) to secure wholesale power through long-
term contracts may help to stabilize wholesale electricity prices and provide power at rates
well below current wholesale spot market prices.
· Retail rates for SDG&E customers could rise if the CPUC authorizes a 2.3 cents/kWh rate
surcharge requested in January by SDG&E. The request is still pending with the CPUC.
SDG&E requested the increase in order to begin "buying down" the approximately $600
million in the balancing account.
Next I to 3 Years
· Wholesale electricity prices should begin to level off, however prices are likely to remain
much higher than in 1998-1999. Price stability should result from State's procurement of
longer-term contracts. Higher prices will result in part from higher input costs and in part
from possible supply constraints, particularly if hydroelectric resources remain Iow.
· San Diego area customers may be in for a potential rate shock as a result of the accrual of
large amounts of deferred power costs by the California utilities. SDG&E's rate stabilization
plan is set to end in 2002. It is unclear what the CPUC or the Legislature will do if SDG&E
has an uncollected balance of purchased power costs - a likely though not certain
outcome. Generally speaking, it could be expected that consumers will have a balancing
account of about 50% of their total annual bill.
· SDG&E's regulated distribution rates will be reviewed in 2003. This could lead to yet
another increase in electricity rates.
3 to 7 Years Out
· Wholesale electricity prices should further stabilize and begin declining as new sources of
electricity supply and natural gas capacity come on line and demand response continues to
take hold.
· Unless new power plants are located within SDG&E's service territory with adequate
natural gas to supply them, transmission constraints in the San Diego area could limit the
cost and reliability benefits to the region of new sources of electric supply being added to
the state's grid. Constraints on the natural gas distribution system also could contribute to
prices remaining high or a tight supply - demand situation. The proposed development of
the Otay Mesa plant (500 MW with potential expansion to 1,000 MW) could provide
approximately half of the power the region currently needs to import during peak loads,
however the plant's sole source of fuel is natural gas and that could have an impact on the
South Bay and Carlsbad plants ability to receive natural gas.
Highly Recnmmondod Options
1. CONTINUE/EXPAHD ENERGY CONSEBVATION PROJKTS FOR CITY FACILITIES.
[OPTION 4, REPORT PP. 641
A. Rationale
· The City has a good record of implementing conservation programs in City facilities.
Current high prices of electricity and improved conservation technologies make the
paybacks on energy efficiency facilities even more attractive. Therefore, capital
investments in this area face minimal risk and should yield near-term paybacks and
they have the added benefit of complementing the City's CO2 reduction plan,
· Energy efficient facilities will reduce consumption and therefore reduce relative
ongoing energy costs regardless of the outcome of market reforms and other state
or federal actions.
· Legislative initiatives will make millions of dollars of funding available to lower the
financial costs of energy conservation. Again, funding assistance reduces the City's
risk of pursuing energy efficiency options. Over $500 million in funding was
pledged under AB 1890 to reinvigorate the renewable energy industry in California.
So far, over $162 million has been paid for the development of 500 MW of new
renewable resources, while customers have received about $47 million in bill credits
through October 2000 for buying power from renewable energy providers.
B. Next Stel~
Backgrou.d: Since 19@3, the City's energy effciency efforts have saved 3.7 MW of
combined capital cost for these efforts is approximately $900,000 with about
$110,000 in incentives from SDG&E. In Spring 2001, after installation of Green LED
traffic signal lights, the City will have saved 4.7 MW of electricity with annual savings
of $700,000/yr at slightly below current market prices (savings based on average cost
of $. 15/kWw-hr for electricity including transmission/distribution).
· Provide additional energy design, management and funding support to the City
Facilities Project Team.
· Coordinate grant and other funding sources to implement energy savings.
· Install additional energy savings measures in future buildings and design and install,
where appropriate, retrofits in existing City facilities.
· Coordinate efforts with energy service providers, the San Diego Regional Energy
Office, the California Energy Commission and other agencies to take advantage of
public facility programs and obtain energy conservation certifications for new and
remodeled facilities.
· Establish a modified work schedule for City employees, such as a 9/80 schedule.
Under a 9/80 schedule employees, with the exception of emergency services
department employees, will work 9 hours a day and have every other Friday off.
City services will be extended by one-hour per day on the 9 hour work days and
City buildings and services will shutdown on Fridays that employees have off.. One
viable schedule could be from 7:00 a.m. to 5:00 p.m. with a one-hour lunch or from
7:30 a.m. to 5:00 p.m. with a half-hour lunch.
I:x~mltiv~ ~:lmrn~rv - Ttutr~dAv. Anril 1~. ~N01. R:l.q AM PA~I~ ?
Fiscal impact will be primarily from staff time in Special Operations and some capital
investment in retrofits. Some staff time may be eligible for offset by grants and/or
SDG&E incentives. Staff costs could also be recovered through avoided costs from
energy savings.
The modified work schedule could render potential savings of up to 1 MW of City's
annual non-street light electricity usage or a cost savings of up to $150,O00/year based
on average cost of $.15/kw-hr for electricity including transmission/distribution. The
City can maximize savings from a modified work schedule by shifting as much of the
workday from on-peak period (11:00 a.m to 6 p.m..) where electricity charges are
highest to semi-peak period (6:00 p.m. to 11 a.m.) where charges are lower.
.. ,,,,,,,......,......, ,.,...
,..,.,,o.. .. ,,,.,., ..°..,
· Making information on the power crisis readily available and supporting energy
conservation or other energy management efforts may be a critical factor in
convincing businesses where energy costs are a large component of an operating
budget to remain located in Chula Vista. It will also help businesses remain
competitive over the short run. High energy consumption businesses include high-
tech and bio-tech manufacturers, refrigerated food wholesale and retailers, precision
machine shops and aerospace parts manufacturers.
· Increased state funding for promotion of conservation options is likely to become
available. The City is in a good position to assist residents in availing themselves of
these funds.
· Conservation represents the lowest risk to the investor, and the highest benefit to
the region and the environment. Every kilowatt saved or produced by an alternative
source is a reduction on demand pressures that should result in lower costs for
others. Conservation and alternative energy are also most productive during peak
hours when they are needed most.
· Conservation and alternative energy have the added benefit of being good for the
environment and complement the City's commitment to climate protection.
· An array of proactive energy programs could be critical in assisting business
attraction and retention activities.
Note: The benefits of such programs may be difficult to measure in strict cost-
benefit terms.
Note: Special Operations is in the process of distributing up to $100.00 of
Compact Flourescent Lights (CFL) to 300 homes in the City {a total of
500+ homes have signed up leaving a waiting list of about 200
residents). The CFLs are being distributed and installed by two trained
Energy Administrative Interns who will also conduct energy and solid
waste audits to identify additional conservation opportunities and to
additional resource information.
I;x~n.fiv~ R. mrn~rv - Th.r~d~v. Anri! 12.2fl~1..c):1~ AM P~o~ R
· Distribute free energy saving retrofits for existing residences.
· Develop matching fund programs to assist local businesses with energy retrofits.
Note: Special Operations is in the process of soliciting small businesses with 10
employees or less to participate in a matching fund program that will provide up
to ~1,000 for energy efficient lighting retrofit. The retrofit will be conducted by
a licensed contractor who will conduct an energy audit and provide a proposal
to the City and business for prior approval.
· Analyze available options to provide incentives to businesses that utilize renewable
sources of energy (i.e. solar panels, wind power, distributive, etc.)
~ City matching funds
~ Grants or Iow interest loans (Sec. 108, CDBG, CEC Solar Energy Grant Program)
~ Rebates (in partnership with SDG&E)
~ Free publicity
· Identify and support state and federal grant opportunities that encourage businesses
to further develop or bring-to-market new energy-related technologies (i.e. wave
technology, fuel cell, etc,)
· Work with local retailers to market and distribute energy saving options.
· Provide public education, information and assistance to residents and businesses so
they may take advantage of rebate, loan and grant programs that assist energy
conservation. This could include developing an Energy Conservation and Resource
Guide.
· Include energy resource information on the City's website with links to relevant
energy assistance websites (i.e.U.S. Dept. of Energy, SDG&E Small Business
Services, San Diego Regional Energy Office, etc.)
· Conduct business outreach workshops inviting guest speakers from various
consulting groups and service organizations/agencies to provide information on
energy conservation, renewable/sustainable sources of energy, and government
programs that provide funding/rebates to support these efforts.
· Partner with other service/community organizations to broadcast energy saving
resources and tips to businesses via newsletters, information pamphlets and
websites and coordinate efforts with the Planning Department.
· Continue to utilize MRW to assist companies with contract negotiations as well as
with general energy-related inquiries.
Fiscal impact is primarily from substantial staff time from Special Operations,
Community Development and Public Information. The first phase of retrofits for 300
homes and ten businesses have already been approved by Council. Additional costs
could include the Energy Conservation and Resource Guide as well as consultant
services from MRW to assist companies with individual contract negotiations {ranged
from $500 to $1,000 per company). Existing funds are available for MRW services.
The resource guide is estimated to cost about ~1.00 per printed copy.
;xRcllt[Vl~ ~llmrnRrv -- Th.r~d;~v. ~nrl~ 12. 2001..0:l.q AM P;l(]l~..q
3. MONITOR THE MARKET AND LEGAL RESTRICTIONS AND BE PREPARED TO ENTER
INTO AN ELECTRICAL SERVICES CONTRACT WITH AN ENERGY SERVICES PROVIDER
(AS PERMII'rED BY LAW). [OPTION 6, REPORT PP. 71]
A. Rationale:
· About 55% of the City government's power purchases are bought at market rates.
As a result, the March 2001 bill for electric/gas service was $303,688.40 (includes
t~106,004.50 electricity balancing account and ~197,684.00 for electricity/gas. A
contract with an ESP might provide electricity more cheaply than taking service
from SDG&E.
· ABlX currently prohibits direct energy purchases for as long as the state has
outstanding long-term contracts. This law needs clarification, and may be
overturned, but for now, has squelched this market opportunity.
· There is some risk that if market conditions improve in the next 1-3 years, a long-
term commitment to an ESP will burden the City with higher cost electricity.
C. Next Steos:
Seek Council authorization to execute contracts within the following parameters:
· Pledge up to City's entire Icad (14MW).
· The contract term should be for the shortest time possible, but not to exceed three
years.
· Establish a per kilowatt ceiling price under which staff has the authority to
negotiate..
Note: Direct energy purchases may be subject to legal restrictions under ABlX; any
contract will require legal validation or escape clauses.
Staff time, primarily from City Manager's office, Community Development and City
Attorney.
4. DEVELOP AND IMPLEMENT A LEGISLATIVE STRATEGY THAT FACILITATES THE
CITY'S OVERALL ENERGY PLAN. (STAFF GENERATED; NOT SPECIFICALLY
REFERRED TO IN MRW REPORT)
Energy supply and cost issues will be dramatically affected by federal and state actions.
Issues such as electricity supply costs, transmission reliability, natural gas
supply/reliability, municipal utility operations, distributed energy, aggregation,
environmental protection, power plant siting, direct energy procurement, and
aggregation are all subjects of current Legislation. Favorable state laws could enhance
and facilitate numerous City Energy Plan Options.
iL Next StelM:
Add a new category to the City's existing Legislative Program that embodies the City's
goals in such key areas as environmental protection, electrical supply costs, transmissin
reliability, natural gas supply and availability and power plant siting. This category
would include the following:
Support measures that:
FXAm;tivR R;~mmArv - Tht~rRdAv Anril 12. 2001..q:l.q AM P;IoA 1(")
1. Assist the City and its energy consumers improve supply/demand conditions and
enhance conservation measures.
2. Preserve local options to control and fund the supply and distribution of energy
(including the formation of a municipal utility district) or that fund conservation
programs.
3. Enhance the City's ability to enter into distributed generation agreements without
having to pay stranded transmission or distribution charges.
4.Impose "fair and reasonable" wholesale price caps.
5. Repeal the provision in ABlX that suspends customer choice, and pass a favorable
bill for customer choice (SB 27X or a similar one).
6.Make municipal aggregation programs available on an "opt-out" basis.
7. Allow public agencies (not just municipal utilities) such as the City to participate in
state power supply programs.
8.Encourage use of real time metering.
Oppose measures that:
1. Impinge on or restrict the City's ability to exercise land use review/control with
respect to the generation or transmission of power.
2. Erode the City's ability to acquire/generate power from alternative sources, operate
as a municipal utility, or enter into aggregation and/or distributed generation
arrangements.
Staff time, primarily from City Manager's office and Community Development.
5. CONTINUE/EXPAND EFFORTS TO IMPLEMENT THE CARBON DIOXIDE (CO2)
REDUCTION PLAN AND GREENSTAR BUILDING INCENTIVE PROGBAM. (STAFF
GENERATED; NOT INCLUDED IN MRW REPORT).
A. Rationale,.-
The City recently adopted the Carbon Dioxide (CO2) Reduction Plan establishing 20
Action Measures to promote energy savings and emissions reduction. Implementation
of the C02 Plan allows the City to move forward with energy efficient land use and
construction level programs.
B. Next Stems
1. Implement applicable measures in C02 Plan under three tiers; Citywide General Plan
Level, Site Planning (Sectional Planning Area) Plan Level and Individual Project
(Building Permit) Level.
Study the feasibility of citywide land use measures as part of the General Plan
Update. Evaluate possible locations for mixed use and higher density
development near transit and major activity centers
· Develop and implement "Sustainable Development" concepts in new SPA Plans
through updating guidelines for preparation of Air Quality Improvement Plans
(AQIP's) as a part of SPA Plan review
· Develop and implement construction-level conservation measures in conjunction
with energy efficient building programs that are at least 20% more energy
efficient than current Title 24 Energy Code requirements.
2. Implement the GreenStar Building Incentive Program and promote energy efficient
building practices. Identify air quality/energy conservation measures for
implementation in new developments.
3. Conduct a "pilot study" through use of a consultant to establish a set of site
planning and construction indicators (energy features and calculating methods), and
to develop a customized computer model for use in analyzing development projects
relative to air quality improvement and energy conservation.
4. Develop formal guidelines for the preparation of AQIP's based on the "pilot study"
results and determine any necessary amendments to the Growth Management
Ordinance.
5. Coordinate with the local development community and actively promote
participation in available energy efficient building programs such as ComfortWise
and Home Energy Partnership (HEP), and develop incentives to encourage this
participation.
6. Remain actively involved with the statewide Community Energy Efficiency Progra'm
(CEEP) to provide oversight for the development and implementation of energy
efficient building programs and related incentives.
Staff time primarily from the Planning and Building Department. The "Pilot Study"
($58,000) will be funded from an existing EPA grant.
I;X~C-~II{vR .c;iJmm;~rv _ Thilr~rl;~v. Anril 19.2(~O1..q:l.cJ AM Paoa 12
Promising Options
] PU~UE DI~RIB~ED GENE~TION OPPORTUN~I~ FOR ~TN C~
FACILITI~ ~D PR~ATE KONOMIC D~LOPM~ OPPO~UN~I~.
[O~ION 3, REPORT PP. 56] "Distributed ~er~tion' r~rs ~o s~all p~w~
generation units (generally up to 30 megawatt~) that are located near consumer or
tar~t~ load ~nt~rs. Technologi~ i~clu~ ~impl~ c~le ~ tur~n~s,
microturbines, fuel cells and p,hctcvc~tcgc~hotovoltaics.
~ R~ale:
· ~i~ri~u~d g~n~r~ion ~ ~ u~d ~ a ~ou~ of ~n~r~ ~t p~ p~rio~ when
power i~ mo~ exp~nsive.
· B~u~ ~i~ri~ut~d ~e~tion ~n ~ ~c~ompli~d wit~ ~ Iow ~pit~l inw~tm~nt
(relative to large-scale power plants), the financial ris~ to the Cit~ of this option ~s
mor~ mana~l~ ~h~ pur~ui~ th~ d~v~lopm~nt of ~ Oi~-fin~n~ power pl~n~.
· Current and proposed funding and ~ncentive programs that are available for
distributed ~n~r~ion projects ~n~n~ t~ ~tt~tiv~fl~s ~ t~i~ option vi~-G-vi~
other options. In p~i~ul~r, t~ L~isl~ur~'s Sp~l S~ssion ~oul~ I~a~ ~ n~w
f~n~i~ for ~i~tri~ut~ ~n~r~tion an~ po~nfiall~
· Distributed g~neratio~ can power just CiT~ facilities, or, depending upo~ capacit~
a~d Io~ation, ~ould ~ ufili~ with ~dja~t i~ustd~l
develop~e~t of those ~e~ou~ces, as has bee~
S~mor~ ~d O~y I~ndfills ~t u~ l~n~fi, m~th~n~ ~ to m~n~fa~tur~ ~n~r~.
in ~ ~poth~fi~l ~pli~fio~ o~ di~tri~u~ ~ration ~ th~ Chula Vi~ Poli~
Department, a best-case scenario for distributed generation provides power to the
~oli~ ~ep~tm~n~ a~ ~bou~ ~-~ ~n~ ~r ~W~
Not~: I~ ~rm~ of ~ow~id~ ri~, ~r~ ~ ~ d~ th~ ~PU~ will r~l~ i~ f~or of t~
B. Ne~
1. Solici~ proposal~ for distributed generation ~roj~cts a~ s~l~c~d ~it~ faciliti~ as well
~ for potential p[ivs~ ~o~omic ~v~lopm~t opportunities. S~sff will ~oli~i~
d~lopm~nt propo~l~ for ~p~ifi~ ~r~io~ ~iliti~/t~hflolo~i~
f~ciliti~s ~h~t p~o~u~ p~a~ or f~ll Io~ ~n~r~ti~ ~t
~o~t ~s~ima~. Po~fi~l ~it~ ~i~ identified ~ s~ff in~lud~ fa) th~ new
Economic Development Opportunities
· Staff will evaluate potential business development and retention opportunities
and solicit development proposals for Distributed Generation and/or other
developer/economic development "over the fence" transactions.
· Potential Economic Development Opportunities include (a) Maxwell Road site
(northern portion) (synergy with the landfill, Corporation Yard, Energy Way
redevelopment potential); (b) LandBank site (northwest corner - synergy with
Corporation Yard, landfill, LandBank and Auto Park redevelopment); and (c)
BFGoodrich site (new BFG campus development/Co-Generation opportunity).
2. Pursue the Solar Energy and Distributed Generation Grant Program offered through
the CEC. Program offers rebates and/or other financial incentives for residential,
business, and government users who purchase and install solar energy and
distributed generation facilities.
3.Monitor CPUC proceedings and encourage decisions that facilitate the program.
C. Fiscal I,-oact
Staff time primarily from City Manager's office, Community Development and City
Attorney's office. Depending on the outcome of some preliminary investigations by
staff, there may be the need to secure the services of specialized legal, financial and/or
energy consultants as various economic development proposals emerge.
2, MONITOR THE MARKET AND LEGAL RESTRICTIONS AND BE PREPARED TO
ENTER INTO A BILATERAL AGREEMENT WITH A POWER GENERATOR.
[OPTION 7, REPORT PP. 74]
A. Rationale:
· In effect, acting as its own ESP, the City could choose to purchase power directly
from a power supplier and obtain a longer-term access to electricity at a fixed or
hedged price.
Note: As with the ESP contract, described above, pursuing this option at this time
could lead to the City locking itself into a power supply contract at a price that will be
above market prices in a more stable electricity market.
B. Next Stem:
Seek Council authorization to execute contracts within the following parameters:
1. Pledge up to City's entire load (14 MW).
2. The contract term should be for the shortest time possible, but not to exceed three
years.
:~. Authorize staff to negotiate an agreement up to but not to exceed a specified
ceiling price.
Note: Direct energy purchases may be subject to legal restrictions under AB1X; any
contract will require legal validation or escape clauses.
C. Fiscal Immz4~
Staff time primarily from City Manager's office, City Attorney and Community
Development.
3. PARTNER WITH A THIRD PARTY TO 5B3U~LD AND OPERATE POWER GENERATION
FACILITIES. [OPTION 2, REPORT pp.
· The City has an excellent opportunity to pursue this option with Duke Energy as
part of the modernization of the South Bay plant.
· A partnership can be structured in numerous ways to share the risks and
benefits of development and operation, and to leverage what each party brings
to the table. For example, in consideration for facilitating the redevelopment of
the South Bay plant, the City could obtain rights to receive a dedicated share of
the plant's capacity, a share of plant revenues, and/or other public benefits such
as Bayfront infrastructure, City facility energy projects, etc.
· Proposed legislation may expedite the licensing and permitting process for new
power plants (primarily peaking plants) and for the repowering of existing power
plants. Because this legislation will likely have sunset provisions (i.e., dates
upon which they expire), the next one to three years may provide an ideal
window to push through the development and siting of a power plant.
· Competing legislation may reduce the attractiveness of owning or sharing in the
development of a power plant. For example, legislation, if passed, may require the
owner of a power plant to sell its electricity only to in-state customers, limiting the
potential market for the plant's output (legislation pushing for this "California First"
policy has been softened in latest versions and now is framed in terms of price
parity for California vis-;~-vis out of state customers). A more draconian measure
proposed in new legislation would make any owner of a power generation facility a
public utility subject to the jurisdiction of the CPUC (although the legal validity of
such legislation is uncertain).
· California's electricity market structure is still in a state of flux and there is
considerable uncertainty as to how the market will operate in the future. This
regulatory uncertainty is significant.
· Continue negotiations with Duke Energy and the Port District regarding the terms
for redevelopment of the South Bay Plant. Basic premise is to derive public benefit
in consideration of City facilitation of plant development.
Staff time from City Manager's office, City Attorney's office and Community
Development. As discussions advance, there may be the need to secure additional
outside legal, financial and/or energy consultant services.
4. DEVELOP AN EMISSIONS OFFSETS PROGRAM BASED ON MOBILE SOURCES (AS
PERMITTED BY LAW). [OPTION 10, REPORT pp. 83]
New power generators must obtain emissions offset credits (CNG vehicles) or other
conservation projects from the APCD to mitigate increased NOX pollutants.
· Some City conservation programs could be utilized to obtain emission offset credits
from conversion of diesel/gasoline-powered vehicles to Natural Gas power. These
I=x~h~l]tiv~ ~::mrn~rv - Thllr~rlAv. AnrJl 12. ?aol..CJ~l.q AM PgJ~ll~. 1.~
could be sold or utilized to facilitate local alternative sources of power generation or
fund the conversion of City fleet vehicles to cleaner air vehicles.
B. Next Steps:
· City staff should work with air quality officials to realize benefits of any City
investment in alternative fuel vehicles (e.g. CNG buses) to allow the City to provide
the value of those reductions to potential partners.
· City staff can also work with future generators and the APCD to ensure that any
mitigation funds generated are invested locally.
· Develop portfolio of potential offset projects to make available to new generation
sources requiring offsets.
Staff time from Special Operations.
EXR~I ItiV~ Riimm;irv - Th, Jr~dav. Anrll 1~. 2~n 1..q: 1 .q AM PR~- 1 ~
Higher Risk Options
1. FINANCE, OWN, AND OPERATE A LARGE-SCALE POWER PLANT TO MEET A
PORTION OF THE CITY'S DEMAND FOR ELECTRICITY. [OPTION I, REPORT PP. 49]
A. Rationale:
· Plant ownership and efficient operation could provide protection from high and/or
volatile wholesale electricity prices, a potential source of revenue if excess power is
sold into the open market, and improved local electric reliability.
B. Risks to Consider:
C. Next Stens~
· In light of these risks, this option is not recommended at this time. This option may
be revisited in the future if other options f~il to achieve desired results.
2. FORM A MUNICIPAL DISTRIBUTION UTILITY TO OWN AND OPERATE ALL OR
PORTIONS OF THE LOCAL DISTRIBUTION SYSTEM. [OPTION P, REPORT PP. 77]
The formation of a municipal utility could entail anything from the mere declaration of
municipal utility status (akin to what San Marcos did recently), all the way up to ownership
and operation of some portion of, or all of, a power generation and distribution system to
serve some or all of the City's actual gas and electricity needs. To be able to control the
delivery of power to any substantial segment of the population, the City would need to
control or own some substantial portion of the distribution system.
A. Rationale:
· A municipal utility has preferential access to cheap federal hydropower (but there is
a "waiting list" for access to this power) and potentially Other alternative power
supply sources. Jt does not pay federal income taxes, and it has access to tax-
exempt debt to finance capital projects,
· A municipal utility may be able to provide distribution services at a lower cost than
the incumbent utility. Note, however, distribution costs are not the primary driver
of current high power costs.
· By operating the distribution system the City would have the ability to structure
rates in a manner that rewards conservation, encourages the use of off-peak power,
and provides the City with control over how and where "public benefit,"
conservation funds are invested.
· With the structure of California's electricity market in flux, the outlook for a
municipal utility is uncertain. It is unclear at this stage whether municipal utilities,
particularly ones yet to be established, will be able to buy power from DWR. If they
cannot, a City utility would have to procure power on the open market.
· Lassen Municipal Utilities District is the most recent example in California of a
formation of a new municipal utility. LMUD now faces significant rate increases due
to power procurement decisions that, with hindsight, were ill advised. SMUD also is
planning to raise its electricity rates; however, this will be the first rate increase in
ten years and rates will still be lower than PG&E's electricity rates before this recent
round of PUC approved rate increases.
C. N®xt ~1)~:
· Commence negotiations with SDG&E for mutual beneficial partnerships.
· Conduct preliminary appraisal and pre-feasibility consultant services necessary to
evaluate rough costs to acquire existing SDG&E facilities (or build new facilities)
and evaluate legal/regulatory issues/obstacles. If approved by Council, issue an RFP
for services to valuate SDG&E facilities.
· Consider resolution to declare City a Municipal Utility (effective immediately with no
real tangible benefits).
· Coordinate any effort on this strategy with the efforts of other local jurisdictions.
Staff time primarily from City Attorney, City Manager, and Community Development.
Additionally, it is currently anticipated that the preliminary appraisal and feasibility
consultant services would cost approximately $40,000 to ~50,000. If after the pre-
feasibility phase is completed, and the City elects to proceed, it is anticipated that the
final phase would cost up to $250,000 that would produce a condemnation quality
appraisal including severance issues analyzed and valuated.
3. BECOME A MUNICIPAL "AGGREGATOI~' AND ACQUIRE ELECTRICITY AT
NEGOTIATED RATES FOR THE CITY, AND INCLUDE RESIDENTS AND BUSINESSES
(AS PERMITTED BY LAW). [OPTION 8, REPORT PP. 74]
A. Rational®;
· Municipal aggregation offers the potential for lower electricity costs and certain
non-price benefits at minimal initial capital investment.
· The City of Palm Springs saved customers in its aggregation program $88,000 in
only two years. (The program has since been suspended.)
· Current law requires procedures whereby local residents and businesses must
affirmatively "opt in" to an aggregation plan. This dramatically reduces
participation, and therefore the benefits of aggregation. However, there is
legislation currently under discussion to change this provision and allow municipal
aggregation programs to be done on an "opt-out" basis. If there is a change in the
law, this option is more promising in terms of the potential benefits such a program
could provide to Chula Vista's residents and businesses.
Ex~;stive R.mmarv - Th.r~dav. Anrll 12. :~0~1..CJ:l.Cl AM Pao~ 1R
· Although the risk to the City under this option is less than the above two options,
municipal aggregation is likely to yield Very minimal benefits while burdening the
City with administrative and COntractual responsibilities.
· Support legislation that preserves COnsumer choices and authorizes "opt out"
municipal aggregation programs.
~x~fiv~ *c~rnrn'~rv - Thr;r~rlAv. Anrll 1~. 2001. 9'1~ AM
Summary of Major Adion It®ms
] ~ Rel;rofit~n~ew ~nd e,~i~ting..~i_.t~' fa~cili~ies_.whil~ also.~ul;inq retrofit~ tO_ r~id~nt~.
2. Pur~ modified w~rk ~¢hcdule for C.ity e_mployee~.
4~3. Continue/expand energy conservation projects for City facilities and promote energy
efficient and renewable energy programs for businesses and residents.
~--%4. Continue to monitor the market and negotiate with ESP's and Duke as the law allows -
execute deal within specified parameters if obtainable.
~.5.. _Continue to monitor the legislative process and implement the Legislative Strategy.
4~.6.~__lmplement the CO2 Reduction Plan through efforts on three tiers: the Citywide General
Plan Update, Sectional Planning Area (SPA) Plans/Site Planning, and Building Construction
(GreenStar Program).
E~.~7.. Implement the GreenStar Building Incentive Program.
~.~_8. Conduct a "pilot study" through use of a consultant to establish a set of site planning
and construction indicators, and to develop a computer model for use in analyzing
development projects relative to air quality improvement and energy conservation.
7~.9. Solicit proposals for Distributed Generation projects at selected City facilities and
evaluate potential economic development "over the fence" transaction opportunities,
~10. Pursue the CEC Solar Energy and Distributed Generation Grant Program for both City
facilities and other economic development opportunities.
~Negotiate (in cooperation with the Port District) public benefits with Duke Energy as
new plant is entitled.
1_0.12._Develop an Emissions Offsets Program based on mobile sources (as permitted by law).
_11.13. Negotiate with SDG&E for mutually beneficial opportunities,
._12.14.?repare Request for Proposals for consultant services to perform preliminary appraisal
and pre-feesibility studies to valuate SDG&E facilities and analyze legal/ regulatory
environment for municipalization. Estimated cost to $50,000.
13.15. Present resolution for declaring the City a Municipal Utility.
Next Steps
1. Based on Council direction at workshop, proceed with Major Action Items.
2. Determine overall Energy Strategy, staffing and management plan and more refined general
implementation costs.
3. Present Energy Strategy and Action Plan to Council for formal adoption in June 2001, and
report on progress made on the Major Action Items.
J:\COMMDEV\HAYN ES\EXECUTIVE SUMMARY.doc
Fx*qm,tlvA ~,lmmnrv - Th~,r~rlnv. Anril 12. 2onl..q:lR AM P~a~ 2~
MEMORANDUM
To: Members of the City Council
City of Chula Vista
From: Steve McClary and Heather Vierbicher
MRW & Associates, Inc.
Subject: Summary of Legislative and Gubernatorial Initiatives
Date: April 5, 2001
This memo summarizes for the benefit of the members of Chula Vista's City Council legislative and
gubernatorial initiatives which have taken place since February 1, 2001. MRW & Associates, Inc.
(MRW) prepared for the City of Chula Vista a study that incorporates an overview of the state of
California's electric and natural gas industry. The material included in the report is current through
January 31, 2001. Therefore, this memo is intended to update City Council members on important
legislative and gubernatorial activities that have taken place since the report was completed.
This memo first provides an overview of the Executive Orders Governor Davis issued in February
and March. The second part of this memo outlines the pending legislation in the State Legislature's
First Extraordinary Session.
Confidential Memorandum For Chula Vista City Council and Cily Staff Use Only
Gubernatorial Initiatives
On January 17 Governor Davis declared a State of Emergency in California due to the current
energy crisis affecting the state. Governor Davis has used his constitutional authority a number
of times since then to issue Executive Orders directing various actions to be taken to address the
state's power crisis. The Executive Orders expire on December 31,2001.
This section summarizes the salient provisions of a number of these Executive Orders.
Executive Order 23
This Order directs the California Independent System Operator (ISO) to develop a system for
coordinating and managing both planned and unplanned outages at generation facilities in
California and connected to the ISO system. Outages at generation facilities contributed to the
supply-demand imbalance last fall and winter. Specifically, this Order requires the ISO to direct
generators to submit to the ISO planned outage schedules, prepare a coordinated outage plan
which shall be updated quarterly, identify generation .facility maintenance criteria to be met by
generation facilities, maintain records of any unplanned generation facility outages and to
provide those records to the Electricity Oversight Board and conduct audits of generation
facilities that have fallen below performance benchmarks.
Executive Order 24
This Order addresses air quality and air emissions limits. The Governor directed local air
pollution control and air quality management districts to modify emissions limits that limit a
generation facility's hours of operation. Last year some generators reached their allowed limit for
hours of operation or total air emissions and could not operate without incurring penalties. This
contributed to the supply-demand imbalance.
Executive Order 25
To encourage construction of already approved power plants as quickly as possible, the Governor
issued this Executive Order directing the California Energy Commission (CEC) to expedite the
review and approval of project amendments. Also under this Order, certain simple cycle power
plants can be converted to combined cycle power plants by amending current certificates rather
than filing new applications with the CEC.
Executive Orders 26 and 28
The first of these Orders directed the CEC to prepare a report of potential peaking power plant
sites in California. The report was to identify those areas of the state that would benefit from the
installation of a peaking power plant to augment power supplies through the summer of 2003.
The CEC prepared this report, "Potential Peaking Power Plant Sites in California" and presented
it to the Governor on February 2 I. The report found that constraints in the natural gas supply
delivery system in the San Diego region made any potential sites in that area questionable.
The second Order, Executive Order 28, directs the CEC to permit new peaking and renewable
power plants on an emergency, expedited basis. Power plants that are permitted under the
emergency process are exempt from the requirements of the California Environmental Quality
April 5,2001 2 MR W & Associates, Inc.
Confidential Memorandum For Chula Vista City Council and City Staff Use Only
Act. Plants must be able to be online by September 30, 2001 to be eligible for permitting under
the emergency process.
Executive Order 30
In March Governor Davis issued this Executive Order to encourage greater energy conservation
this coming summer (the order expires at the end of 2001). The order directs the Department of
Water Resources to implement financial incentives for conservation efforts by residential,
commercial and industrial customers. Under this program, the utilities will provide rate
reductions o£up to 20% to consumers who reduce their electricity consumption by at least 20%
during June to September 2001. The program will be financed through a reduction in the
utilities' payments to the Department of Water Resoumes in subsequent months.
Legislative Initiatives
This section provides the most recent information on 15ending legislation in the First Extraordinary
Session. Members in both the Assembly and Senate have proposed over 180 bills to deal with
various aspects of California's power crisis. The majority of bills continue to be discussed at the
committee level where they are being amended to address practical, jursidictional, and political
concerns. The proposed bills generally target the following range of issues:
· mechanisms to provide financial relief to the state's three main utilities;
· the permitting and licensing process for power generation facilities (primarily to expedite the
process) (i.e., ABXI 34, ABX1 36, SBX1 28);
· electricity rate issues, particularly in relation to rate caps and rate freezes;
· energy efficiency, renewable energy, and distributed generation funding and financial incentives
to encourage wider adoption rates (i.e., ABX1 38, ABXI 54);
· measures to prohibit or restrict utility "stand-by" charges in an effort to encourage distributed
generation and self generation; and
· tax issues related to energy production or consumption.
Because many of the bills overlap in their objectives or intended result, one bill typically emerges as
the lead vehicle for addressing a specific issue. Thus, many of the bills currently proposed will not be
acted on but instead will be incorporated with other bills on a similar topic. However, some
legislators are resisting the pressure to combine bills.
Highlights of a few bills which include provisions relevant to the City include:
· SBX1 5 (Sher) provides approximately $733 million for energy efficiency initiatives, including
$20 million targeted for energy conservation in buildings owned and operated by cities and
counties located in utility (e.g. SDG&E) territories.
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Confidential Memorandum For Chula Vista City Council and City Staff Use Only
· ABX 1 29 contains a provision providing $25 million for a grant program and $25 million for a
loan program to a city, county, or special district to fund energy efficiency projects. The grant
funds can be used for administrative expenses.
· SBX1 28 (Sher) is a package of generation initiatives, including limited waivers of standby
charges for customer-owned generation.
· SB×I 23 and AB×I 47 would reduce several hurdles cities face in forming municipal electric
utilities.
The following summarizes pending bills that are relevant to Chula Vista's development of an energy
management strategy and that may emerge from the legislative process for passage. Assembly bills
are presented first, followed by Senate bills.
ABX1 4, Daucher and Rod Pacheeo: ASM
ELECTRIC GENERATION: For owners of generation plants that offer to sell the energy to in-
state buyers first, this bill would authorize a tax credit beginning in January 2002 equal to the
owner's costs of purchasing emission reduction credits for an electrical generating facility.. A
hearing of this bill has been postponed.
Impact on Chula Vista: Should encourage private investment in power generation. It is unclear if
a municipality could take advantage of the tax credit.
ABX1 9, Richman: ASM
ELECTRIC GENERATION: Requires the CEC to identify regions in the state with the greatest
electrical energy supply-demand imbalance. Local governments with land-use authority, would
be required to identify potential sites for locating a power plant facility. It is intended to reduce
the NIMBY hurdles confronting power plant projects. TMs bill passed out of the Assembly on a
75-0 vote.
Impact on Chula Vista: No immediate effect on Chula Vista or the energy management options
under consideration. The language of this bill was amended to remove requirements that local
governments work to site a power plant in their jurisdiction. The new bill language now states
that the local authorities need only identify a potential site but are not required to actually
develop a power plant on the site.
ABX1 15, Pacheco: ASM
ENERGY EFFICIENCY: Provides a credit of up to $1,000 per year against net taxes for
qualified costs incurred by a taxpayer for energy conservation measures (such as replacing or
installing air conditioners, refrigerators, windows, insulation, weather stripping, low-flow
devices, ventilation cooling fans, attic ventilators, economizer systems, and heaters with more
energy efficient models, devices, or designs). The taxpayer can claim the credit each year for the
years 2001, 2002, 2003, and 2004. This level of a credit for energy conservation measures is
unprecedented in California, where the tax credit is typically only 5-10% of the cost and meant to
leverage private investment. This bill could subsidize the entire cost of some homeowner
improvements with an unknown impact on energy consumption. This bill is in the Assembly
Revenue and Taxation Committee for hearing.
April 5,2001 4 MR W & Associates, Inc.
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Impact on Chula Vista: This bill would provide additional incentives to residents to install
energy-efficient devices. The credit cannot be applied toward the installation of energy
conservation measures for a building being constructed or where square footage is added. The
City could incorporate this tax incentive in a community education program designed to
illustrate the financial benefits of energy efficiency. But taxpayers cannot "double dip" by
claiming a credit for a purchase from two different sources.
ABX1 20, Zettel: ASM
POWER PLANT SITING/ENERGY EFFICIENCY: This bill would permit air pollution control
districts to issue a temporary, expedited, consolidated permit for a power plant if it met certain
conditions and would require the CEC to implement an expedited decision process for a peaking
plant facility or amendments to pending applications for a change from a combined cycle project
(non-peaking plant) to a peaking plant project. This bill would authorize the CPUC to implement
an expedited process for considering utility applications for certificates of public convenience
and necessity or for a permit to construct transmission and substation facilities. The CPUC would
also be required to authorize utilities to provide financing for time-of-use meters for residential
and small commercial customers, to create incentives for commercial customers to reduce
nonessential lighting, and to offer incentives to builders to exceed energy standards in new
construction. Funding would be made available to mitigate or offset emissions from such power
plants. This bill would remain in effect only until January 2003. No action has been taken on
this bill since February.
Impact on Chula Vista: This bill is intended to expedite the siting of peakingfacilities. This bill
reduces the regulatory hurdles for siting a peaking plant, which may be beneficial to the City if it
pursued one of the options related to developing a generation plant in the City limits. The bill
could facilitate the siting of the 49 M~ l~MCO plant in Chula Vista or a new peaking power
plant in the City.
ABX1 21, Kelley: ASM
DIRECT ACCESS: This bill would allow customers to switch their electric service to an
alternative provider. These customers may face an "exit" fee which would ensure that DWR
recovers its power procurement costs. This bill passed out of the Assembly on March 22.
Impact on Chula Vista: This bill, if it led to determinations by the CPUC that cities could choose
an alternative provider, would put the option of signing an agreement with an ESP back into
play for the City.
ABX1 27, Koretz and Horton: ASM
ON-SITE GENERATION: This bill would authorize $50 million annually in tax incentives for
the purchase or lease of qualified power generation facilities. The power generation facility must
have a capacity of 50 MW or less and be a renewable source of power (solar energy, wind-
driven, fuel cell, microturbine, photovoltaic, and natural gas generation system, but does not
include any diesel, oil, gasoline, or steam generation system). The bill outlines four separate tax
incentives from which the user may choose: a credit equal to the percentage of the cost, a
depreciation-based incentive, a credit against net sales and use tax, or exemption from the sales
and use tax. The on-site system would have to provide 80% of the electricity consumed by the
user, and the user may not sell, trade, or exchange the electrical output. The tax incentives would
April 5, 2001 5 MR W & Associates, Inc.
Confidential Memorandum For Chula Vista City Council and City Staff Use Only
remain in place for the period 2001-2005. This bill is in the Assembly Appropriations
Committee.
Impact on Chula Vista: This bill primarily acts as an incentive for the installation of on-site
generation. It is unclear whether the tax benefits would extend to the City itself or only
businesses. Residential customers are unlikely to find this bill beneficial. Because the bill takes
effect only 90 days afier passing, the bill is unlikely to provide incentives to taxpayers in time to
meet the summer demand Taxpayers would have to go forward with a purchase without knowing
the final outcome for this bill.
ABX1 29, Kehoe: ASM
ENERGY EFFICIENCY: This bill establishes a variety of new programs related to energy
efficiency and distributed generation. The bill provides financial assistance to community
colleges for energy efficiency and load management. Businesses would access to a new loan
guarantee program for renewable energy projects. The bill provides $50 million for a grant and
loan program for residents and small business owners for building retrofits and another $50
million for cities, counties, and special districts. The bill also requires the CPUC to undertake
measures to allow for the replacement of meters with time-of-use meters for non-residential
customers with demand greater than 100 kW and would make available $50 million for the
purchase of time-of-use meters by customers with usage greater than 100 kW. The Assembly
passed the bill, and it is now in a Senate committee.
Impact on Chula Vista: This bill provides additional financial incentives for energy
conservation. The City itself wouM not directly benefit from this program, but the City couM
facilitate access to the programs for its residents and businesses.
ABX1 32, Nation and Aroner: ASM
EI~ECTRIC RATES: This bill would require the CPUC to establish a 3-tier rate structure for
residential electric customers. The bill would exempt certain customers from the higher third tier
rate. Customers that consume electricity below a baseline amount would pay the first tier rate.
Consumption higher than the baseline would be billed under the second- and third-tior rates,
depending on the quantity consumed. This bill also requires that all charges for residential
electric customers be based on electricity consumption, until at least January 2004 [Heather - do
you know what this means? Sounds like a hit on demand charges, perhaps?]. Finally, this bill
requires the CPUC to authorize the installation of time-of-use meters for nonresidential
customers with loads greater than 100 kW. (This provision overlaps with ABX1 29 (see above).
This bill is in the Assembly.
Impact on Chula Vista: There is no City-specific effect on Chula Vista.
ABX1 35, Bates: ASM
DIRECT ACCESS: Deletes ABX1 1 language that suspends all direct access transactions until
DWR no longer supplies power to customers. No action has been taken on this bill since
Febrnary.
Impact on Chula Vista: This bill wouM enable Chula Vista to pursue an energy supply contract
with an ESP.
ABX1 36, Wright: ASM
April 5, 2001 6 MRW & Associates, Inc.
Confidential Memorandum For Chula Vista City Council and City Staff Use Only
SITiNG: This bill would include plant modernizations in the CEC's six-month siting process
under AB 970. License applications would no longer have to have air-emission offsets in hand at
the time the CEC does the data-adequacy determination. The Assembly passed tMs bill on
March 12, and it is now in the Senate Committee on Environmental Quality.
Impact on Chula Vista: This bill wouM facilitate the modernization of the South Bay plant, which
may provide benefits to the City.
ABX1 40, Steinberg: ASM
ENERGY EFFICIENCY: This bill would require the CEC to administer a program of grants and
loans to a city, county, or special district, including a school district, to fund energy efficiency
and conservation projects in facilities owned by those entities. The bill would appropriate $50
million for this purpose. The Assembly passed this bill on March 22, and it is now itt the Senate
Committee on Energy, Ut#itie~, and Communications.
Impact on Chula Vista: This bill could provide significant financial assistance for the City for
any energy efficiency projects it intends to pursue in the future.
ABX1 45, Kelley: ASM
MANUFACTURERS INVESTMENT CREDIT: Extends the MIC to include the generation of
electricity through the use of solar, wind, geothermal, solid-fuel biomass, waste tire, municipal
solid waste, digester gas, or hydropower with a generating capacity of 30 MW or more. The
generating facilities must be new (i.e., not selling electricity to a utility prior to Jan. 1, 2001).
This bill is being reviewed by the Assembly Energy Costs and Availability Committee.
Impact on Chula Vista: Businesses located in Chula Vista may be able to benefit from this bill.
ABX1 48, Migden: ASM
MUNICIPAL AGGREGATION: This bill would authorize customers to aggregate their electric
loads with private aggregators or as part of a municipal aggregation program. The bill authorizes
municipalities to create municipal aggregation programs if each customer is given an opportunity
to opt out of the program. Customers that choose to opt out of a municipal aggregation program
would be served by the current utility or its successor. This bill also provides that municipalities
that establish aggregation programs may apply for a pro rata share of energy efficiency funds
collected from customers by the incumbent utilities. Provisions of this bill conflict with the
conununity aggregation provisions of SBXI 8. This bill was passed by the Assembly Energy
Costs and Availability Committee on March 28.
Impact on Chula Vista: This bill wouM have a direct impact on the viability of a municipal
aggregation program. Currently, municipal aggregation programs must be done on an "opt-in"
basis, a provision which constrains the effectiveness of aggregation programs. If this bill is
adopted to allow "opt-out" aggregation programs, more ESPs will likely be willing to bid to
serve as the supplier (because of the potential large customer base) and the administrative costs
could be spread over a large customer base.
ABX1 49, Campbell: ASM
ELECTRIC GENERATION FACILITIES: Requires that portions of property tax revenues of a
power plant facility be allocated to the county and/or city in which the primary power-generating
operation of that facility is located; and grants the board of supervisors of the county or the city
April 5, 2001 7 MRW & Associates, Inc.
Confidential Memorandum For Chula Vista City Council and City Staff Use Only
and county in which a new facility is located to have the right of first refusal to the electricity
generated in that facility.
Impact on Chula Vista: This bill would give the City additional leverage in managing the energy
supply to the City and possibly provide additional revenues.
ABXl 51, Daucher: ASM
ON-SITE GENERATION: Provides a tax exemption for generators installed under a qualified
interruptible service contract of 3 years or more. This bill is intended to provide an incentive to
businesses to purchase and install on-site generators. A first hearing of this bill was postponed.
Impact on Chula Vista: Businesses located in Chula Vista may be able to benefit from this bill.
ABX1 53, Reyes: ASM
RENEWABLE PROGRAMS: Establishes the California Renewable Energy Loan Guarantee
Program to guarantee loans up to 80% of the loan value made by financial institutions to eligible
businesses for the permitting, manufacturing, acquisition, construction, or installation of
renewable energy systems intended to decrease demand on the electricity grid. The minimum
amount that may be guaranteed for any renewable energy system is $25,000 and the maximum
amount is two million dollars $2,000,000. The Assembly passed this bill on March 22.
Impact on Chula Vista: Businesses, particularly small businesses,, located in Chula Vista may be
able to benefit from this bill.
ABX1 60, Hertzberg: ASM
ELECTRIC GENERATION: This bill would require, as a condition of certification by the CEC,
that a new generating facility offer to sell its output to an electrical corporation, a municipal
corporation, or the Department o£ Water Resources, on terms not less favorable than the terms of
the next offer that the applicant makes for the sale of electrical power generated by that facility.
Given this provision, new generating facilities could still sell power at prices consistent ~th the
prevailing market conditions and also sell output outside of Califomia. This language is less
stringent than previous versions which sought to push a "California First" policy. The Assembly
passed this bill on March 22.
Impact on Chula Vista: May affect economics of South Bay replacement project.
SBX1 1, Soto: SEN REVENUE AND TAXATION
INCENTIVE: Provides a tax exemption until 1/1/03 for the sale and the storage, use, or other
consumption of microturbines, fuel cells, photovoltaic cells or any other solar energy cell or
panel.
Impact on Chula Vista: This bill would provide additional incentives to businesses and residents
to install distributed generation applications.
SBX1 5, Sher and Burton: SEN
ENERGY EFFICIENCY: Appropriate $1,039,500,000 from the General Fund to the CEC and
CPUC to implement energy efficiency programs and supplement existing energy efficiency
programs, distributed generation, peak demand reduction, expansion of low-income discounts,
and more. This bill provides $20 million for programs targeting load shifting and energy
efficiency in municipal buildings. The Senate passed this bill on March 22.
April 5,2001 8 MR W & Associates, Inc.
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Impact on Chula Vista: SB 5X would make local governments eligible to receive funding for
programs aimed at reducing peak energy use, including v~ater and waste water system efficiency,
HVAC operations and traffic light systems.
SBX1 6, Burton and Bowen: SEN
STATE POWER AUTHORITY: This bill (1) creates the California Consumer Power and
Conservation Financing Authority, (2) authorizes the issuance of bonds up to $5 billion, and (3)
specifies that no new projects be undertaken after January 1, 2007. This bill establishes the
California Consumer Power and Conservation Financing Authority (CPCFA), which would have
the authority to build, finance, own, or acquire, either on its own or with others, electric power
plants. The intended goal is to improve long-term resource planning for the electricity sector and
augment private sector investment in power plants. The CPCFA would also provide financial
assistance, through programs administered by others, for ener~'-efficient appliances and
renewable energy projects and for energy efficiency and environmental improvements of existing
power plants. This bill is currently under review by the Senate Appropriations Committee.
Impact on Chula Vista: This bill wouM provide additional incentives to businesses and residents
for energy efficiency and renewable energy projects. It is unclear how the formation of an
Authority wouM affect -positively or negatively - Chula Vista's options, particularly those
addressing the development of a power plant. The South Bay plant could benefit from this bill if
it can take advantage of funding for environmental improvements at the facility.
SBX1 8, Alarcon: SEN
MLrNICIPAL UTILITIES: This bill would permit a public agency that seeks to serve as a
community aggregator for direct access customers to provide aggregation service to all of the
customers within its jurisdiction after a majority vote of its elected governing body. Ifa customer
of the public agency desires to receive service from a different service provider, it may do so
upon written notice to the public agency and pursuant to the opt-out rules established by the
public agency. This bill remains bt the Senate Energy, Utilities, and Communications
Committee.
Impact on Chula Vista: This bill wouM make it easier for Chula Vista to develop a municipal
aggregation program.
SBX1 17, Brulte: SEN
SOLAR: Provides a tax credit for costs incurred by a taxpayer for the purchase and installation of
a solar energy system for the production of electricity installed on property in this state. The
credit would equal $2.50 per rated watt of generating capacity, and would be limited to 50% (for
2001 through 2003) or 25% (for 2004 and 2005) of the net cost of the system after deducting the
value of all other available credits. This bill remains in the Senate Revenue and Ta. vation
Committee.
Impact on Chula Vista: This bill would provide additional incentives to businesses and residents
to install solar energy systems.
SBX1 23, Soto: SEN
PUBLIC POWER DISTRICTS: This bill is known as the "Fair Citizen Access to Public Power
April 5, 2001 9 MRW & Associates, Inc.
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Act". It streamlines the process for forming public power districts. SB 23X passed out of the
Senate Local Government Committee. As amended, the bill limits the authority of a local agency
formation committee (LAFCO) to disapprove formation of a municipal utility district. It will
next be heard in the Senate Judiciary Committee, where the issues of how the CPUC reviews
municipal utility proposals and the eminent domain procedures used to purchase the existing
distribution system will face significant scrutiny by the utilities. The bill lowers most of the
hurdles cities must face when contemplating formation o£a municipal utility. (ABX1 47 is a
similar bill.) The bill would also require the CEC to provide assistance to local authorities who
wish to consider forming a municipal utility district. TMs bill remains in the Senate Energy,
Utilities, and Communications Committee.
Impact on Chula Vista: This bill would make it easier for Ch ula Vista to pursue the formation of
a municipal utility.
SBX1 27, Bowen: SEN
DIRECT ACCESS.'. This bill would allow customers previously taking service from an
alternative provider (prior to January 17) to continue to do so. Customers who choose to switch
their electric service to an alternative provider after that date may be allowed to do so, pending a
decision by the CPUC. These customers may face an "exit" fee if the CPUC determines one
should be paid by switching customers. This bill remains in the Senate Energy, Utilities, and
Communications Committee.
Impact on Chula Vista: This bill, if it led to determinations by the CPUC that cities couM choose
an alternative provider, would put the option of signing an agreement with an ESP back into
play for the City. It is probably superseded by ABX1 21 (see above).
SBX1 28, Sher: SEN
POWER PLANT SITING: This bill would expedite the retrofitting of power plants and provide a
1 O-year waiver of stand-by charges for distributed generation projects of 5 MW or less. It would
limit the comment period for local jurisdictions to 100 days in applications for certification of
power plants. The bill requires the CEC to issue final certification for "re-powering" projects
within 180 days (decisions on modifications to existing power plants are currently subject to a
12-month deadline). It extends the application of the four-month siting process for temporary
"peaker" power plants. As established by AB 970, plants had to be in service by August 1, 2001
to qualify. This bill extends the date 17 months, to December 31, 2002. Similar to SBX1 30, this
bill would allocate 100 percent of property tax revenues associated with new generation projects
to applicable local jurisdictions by requiring property taxes from any new power plant, co-
generation, transmission or distribution facility that would be locally assessed (i.e., non-utility) to
be allocated entirely to the county or city in which the plant is located. Finally, the bill
appropriates $53 million to the CEC to increase rebates for clean, renewable distributed energy
systems smaller than 10 kilowatts, to assist cities and counties with expedited review o£power
plant applications, and for other uses. TMs bill passed out of the Senate on March 22.
Impact on Chula Vista: This bill may facilitate the modernization of the South Bay plant. It may
also make it easier for the City to implement a distributed generation project. Under Section 16
of Article XVI of the California Constitution, a redevelopment agency is entitled to keep all
property tax growth inside a project area. This bill says that the underlying city or county would
April 5, 2001 10 MR W & Associates, Inc.
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keep all property taxes associated with a new power plant.
SBXI 33, Burton: SEN
ELECTRIC POWER: TRANSMISSION FACILITIES: This bill authorizes the Governor to
develop a plan, as specified, for the state to purchase transmission facilities owned by electrical
corporations. The Governor is to negotiate this plan with the utilities (only those under the
operational control of the ISO) and then submit the plan for approval to the Legislature. Once the
plan is approved, the state is authorized to issue revenue bonds to finance the acquisition of the
transmission facilities and to pay for the necessary improvements to the transmission grid. The
state would contract with the utilities to repair, maintain, expand, or construct the transmission
facilities purchased by the state.
SBX1 39, Speier: SEN
ELECTRIC GENERATORS: This bill repeals a provision of AB 1890 that states ownership of a
wholesale generator does not necessarily make the owner a "public utility." The effect of this is
to subject these generators to the "jurisdiction, control, and regulation" of the CPUC, to the
extent permitted by federal law. This bill remab~s itt the Senate. The provisions of this bill are
similar to ABX1 8, which is moving forward in the Assembly.
Impact on Chula Vista: This bill would create a significant regulatory risk for the City if it chose
to pursue the development of a power plant by making the City, as an owner of a generating
facility, subject to the jurisdiction of the CPUC. The bill couM also have the effect of seriously
curtailing private investment in power plants because private companies such as Duke Energy
will unlikely be willing to subject themselves to the regulatory oversight of the CPUC. It is
unclear whether the CPUC couM actually enforce the provisions of this bill without federal
concurrence.
SBX1 43, Alpert: SEN
ELECTRIC RATES: This bill would require the CPUC to establish a frozen rate of 6.5 cents per
kWh on the energy component of electric bills for all customers of SDG&E not currently subject
to the rate ceiling (i.e., large commercial customers would not have their rates frozen at 6.5 cents
per kWh as well as residential and small commercial customers). The frozen rate would be
effective through December 31, 2002 and retroactive to February 7, 2001. TMs bill is in the
Assembly Energy Costs and A vailability Committee.
Impact on Chula Vista: This bill would affect any electricity customer not already covered by the
rate ceiling. In effect, this bill creates a potential future obligation owed by these customers to
SDG&E for the cost of power above the rate ceiling.
SBX1 62, Poochigian: SEN
TAXES: This bill would require any local utility user's tax (UUT), imposed on the consumption
of gas or electricity, or both, to be imposed on a per unit of usage basis. The UUT currently is
cost-based. This bill would benefit consumers, by potentially reducing their tax burden, but it
could also harm cities by resulting in lower tax revenues.
April 5,2001 11 MR W & Associates, Inc.
ASSESSMENT OF CHULA VISTA'S
ENERGY MANAGEMENT OPTIONS
CONFIDENTIAL FINAL REPORT
Prepared
for
City of Chula Vista
February23, 2001
Prepared by:
MRW & Associates, Inc.
1999 Harrison Street, Suite 1440
Oakland, CA 94612
510-834-1999
Confidential Final Repor~ Energy Management Options Assessment
TABLE OF CONTENTS
Page
EXECUTIVE SUMSL~RY 6
CHAPTER 1 INTRODUCTION 24
1.I Purpose of Study 24
1.2 Achieving Chula Vista's Goals 25
1.3 Organization of this Report 26
CHAPTER 2 OVERVIEW OF CALIFORNIA'S ENERGY INDUSTRY 27
AND CURRENT ISSUES
2.1 Background 27
2.2 Wholesale Market Structure 28
2.3 Wholesale Market Price Trends 30
2.4 Retail Electricity Rates 34
2.5 Ongoing Reforms to California's Market System 35
2.6 Southern California Natural Gas Transportation Capacity and 39
Prices
2.7 Market Outlook 41
2.8 Position of SDG&E Relative to Other Utilities 43
CHAPTER 3 ENERGY MANAGEMENT OPTIONS 45
3.1 Power Generation Options for Chula Vista 49
3.2 Renewable Energy and Energy Efficiency 62
3.3 Electric Commodity Procurement Strategies 69
3.4 Municipalization 76
3.5 Emissions Offset Trading 82
CHAPTER 4 CONCLUSIONS AND RECOMMENDATIONS 85
4.1 Recommended Actions 85
4.2 Next Steps 89
APPENDIX A Glossary of Terms 92
APPENDIX B Key Agencies and Organizations in California's Electric 96
Market
APPENDIX C Factors Effecting the Price of Electricity in California 101
APPENDIX D Regulatory Issues for Siting a Major Power Plant 103
February 23, 2001 2 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
LIST OF FIGURES
Page
Figure 2.1 PX Day Ahead Unconstrained Market Clearing Price 32
Figure 2.2 Average PX Unconstrained Market Clearing Price, 1999 vs. 2000 32
Figure 2.3 Map of Gas Transportation Pipelines in San Diego Region 39
Figure 2.4 Gas Price at California-Arizona Border for Delivery to Southern 40
California
Figure 3.1 Average Cost of Electricity and Gas in Chula Vista 45
February 23, 2001 3 MRW& Associates. Inc.
Confidential Final Report Energy Management Options Assessment
LIST OF TABLES
Page
Table 2.1 Existing Ga~ Transportation Capacity to the California Border 39
Table 3.1 Electricity and Natural Gas Consumption by Sector 45
Table 3.2 Comparison of Chula Vista's Energy Management Options 47
Table 3.3 Generic Resource Assumptions 50
Table 3.4 Production Cost Comparison for Large Power Plant 52
Table 3.5 Comparison of Selected Distributed Generation Technologies 58
Table 3.6 HypotheticaI Application of Distributed Generation 60
Table 3.7 SummaD- of Chula Vista's Major Efiergy Conservation Initiatives 64
and Financial Benefits
Table 3.8 Utility, State and Federal Energy Efficiency Grant or Financing 68
Programs
Table 3.9 Financial Hedging Options 71
Table 3.10 Number of Vehicles Needed to Generate 25 Tons Per Year of 83
Emission Reductions Credit in 1993
February 23,2001 4 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
ABBREVIATIONS
AFC Application for Certification
APPA American Public Power Association
CEC California Energy Commission
CPUC Califomia Public Utilities Commission
DENA Duke Energy North America
DWR Department of Water Resources
FERC Federal Energy Regulatory Commission
ISO Independent System Operator
kW kilowatt
kWh kilowatt-hour
LADW'P Los Angeles Department of Water and Power
LMUD Lassen Municipal Utility District
MCP market clearing price
MW megawatt
MWh megawatt-hour
PG&E Pacific Gas & Electric
PX Power Exchange
PV photovoltaic
SC scheduling coordinator
SCE Southern California Edison
SDG&E San Diego Gas & Electric
SMUD Sacramento Municipal Utility District
February 23, 2001 5 MRW & Associates. Inc.
Confidential Final Report Energy Management Options Assessment
CHAPTER 1
INTRODUCTION
What began as "summer price spikes" inflicting pain only on electricity customers in the San
Diego region last summer has since snowballed into a statewide power crisis that forced
Governor Davis to declare a state of emergency and has virtually brought the state's large
utilities to their knees. The power crisis was precipitated by large increases in electricity and
natural gas prices in the summer of 2000 and continuing on through the fall and winter. Natural
gas prices on average were more than double the prices of one year ago. The same is true of
wholesale electricity prices, which were significantly higher on average than prices experienced
during the summer of 1999. In addition to rising prices, California has experienced a number of
days when power reserves dipped to very low levels, threatening the reliability of the state's
electricity grid. The scarcity of power supplies this past fall and this winter is particularly
worrisome because autumn and winter typically are seasons of low demand for California.
There are many causes for the high costs of electricity and the scarcity of supply: high fuel costs
for power plants, strong growth in electricity demahd, limited generating supplies, unexpected
behavior in markets for power created under the California restructuring legislation, planned and
unplanned maintenance of power plants, and the hsing cost to some electriciD' producers of
emissions credits. In the natural gas sector high demand for natural gas during the summer
limited the amount of gas injected for storage to serve winter demands. Now that some regions
are experiencing early cold weather and consuming natural gas earlier than normal, the natural
gas markets are responding by pushing prices higher.
Although wholesale electricity prices were high across California and the western U.S., retail
consumers of electricity in only one area of California felt the full brunt of the high prices. Those
are the consumers residing in, or with businesses in, the service territory of San Diego Gas &
Electric (SDG&E). A legislatively mandated freeze on retail electricity rates ended for SDG&E
customers in July 1999, leaving all consumers in SDG&E's territory - including the City of
Chula Vista, which is located in SDG&E's service territory - to face the market fluctuations in
electricity prices. In response to unprecedented wholesale power prices, in August 2000 the state
Legislature passed AB 970, which imposed a 6.5 cents per kilowatt-hour (kWh) cap on the
energy component of residential and small commemial bills in the SDG&E service territory.
SDG&E customers may see their electricity rates rise even further if a CPUC-mandated
surcharge to cover SDG&E's mounting undercollections is imposed or to cover the state's costs
of procuring power on behalf of the utilities, or both.
1.1 Purpose of Study
The City of Chula Vista (the City) is concerned about the short- and long-term impacts on its
residents and businesses of unfair or unreasonable energy costs and any potential financial or
environmental impacts arising from current market conditions. The reliability of the regional
electric transmission system, the capacity and reliability of the natural gas distribution system,
and the environment are also concerns for the City. To address these concerns and develop a
cogent and beneficial response, the City Council directed City staff to examine potential
strategies for responding to this situation, with the goal of providing a recommended course of
action for improved management of energy supply and demand, system reliability, and market
February 23, 2001 24 MR}~'& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
leverage. MRW & Associates, Inc. (MRW) was asked to assist City staff and the City's team of
consultants in evaluating options and preparing a recommended energy strategy with specific
recommendations to present to the City Council.
This report provides an assessment of a number of options which will allow the City to gain a
measure of control over the City's supply and demand of energy as well as the financial costs of
the City's energy use. This report also recommends a portfolio of options for the near and long
term.
It is worth noting that the situation in California's electric market is still in a considerable state of
flux. Almost every day brings new developments on some front, and preparing an assessment of
energy management options under such fluid conditions has been very challenging. As a result,
the data used in the study and even the study's conclusions could easily be negated by new
developments. For example, between the time when MRW began to work on this report add the
end of January, the option to contract with an Energy Setwice Provider (ESP) for the City's
power needs became unavailable. Nevertheless, MRW made every effort to keep the facts in this
study updated through February 1,2001. '
1.2 Achieving Chula Vista's Objectives
The developments in California's power and natural gas markets during 2000 prompted the City
to consider a wide range of options that ultimately are intended to protect the City and its
businesses and residents from future unfavorable developments in the energy markets. To guide
this assessment of the range of options under consideration. MRW set the following three key
parameters, which xvere considered to be aligned with Chula Vista's objectives:
· Energy: Energy encompasses both electricity and natural gas. This report addresses primarily
options that will allow the City to manage electricity supply and demand and related issues.
Some options, such as conservation measures, can be tailored for natural gas use as well.
· Target grottps: The City can most easily deal with the energy supply, demand, and
consumption of its own facilities. But the City can also work to provide energy management
options for its citizens and businesses. Helping local businesses find solutions to the energy
crisis is particularly important as part of broader business development efforts. Thus, this
report addresses the needs of all three target groups: the City, its residents, and its business
community.
· Time Frame: Next summer is the most immediate concern for the City; however, some
options are long term in nature. The time frame for which options were considered was
defined as:
short term - the next six to twelve months,
medium term - the next one to three years, and
long term - from three to seven years out.
Although MRW did not explicitly set environmental benefits as a "parameter" for this study,
many of the options both address the energy situation and also achieve environmental or
February 23,2001 25 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
sustainable development goals. In addition, the relationship with the incumbent utility, SDG&E,
was considered in light of the City's existing arrangement for the distribution franchise and
because the electricity market (and with it, SDG&E's financial condition) is in flux.
1.3 Organization of this Report
There are a number of technical concepts and terms used throughout this report that may be
unfamiliar to the reader. Rather than attempting to explain each such concept or term as it is
encountered in the report, MRW prepared several appendices to provide additional explanation
and clarification for the reader.
· Appendix A contains a glossa~.' of technical terms used in this report.
· Appendix B provides an ove~-iew of the key agencies and o?ganizations that regulate or set
policy for California's electric market.
· Appendix C provides a brief overview of the factors that affect the price of electricity and the
ultimate cost of power to the consumer.
The rest of this report is organized into the following chapters.
· Chapter 2 provides an ovev,%w of California's deregulated market structure, a review of
recent wholesale and retail electric price trends, an outline of the key proposals for reforming
the market structure, and a look at what the future may hold for California's electric market.
· Chapter 3 is devoted to an assessment of the various options the City of Chula Vista could
pursue as part of an energy management plan.
· Chapter 4 offers MRW's conclusions and overall recommendations.
February 23,2001 26 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
CHAPTER 2
OVERVIEW OF CALIFORNIA'S ENERGY INDUSTRY AND CURRENT ISSUES
This chapter provides an overview of California's energy industry. The primary focus is on the
electricity industry: the current market structure, electricity price trends, and the future outlook for
the industry. There is also a discussion of the natural gas market in the San Diego region. This
chapter has the following sections:
· Section 2.1 Background
· Section 2.2 Wholesale Market Structure
· Section 2.3 Wholesale Market Price Trends
· Section 2.4 Retail Rates
· Section 2.5 Ongoing Reforms to California's Market System
· Section 2.6 Southern California Natural Gas Transportation Capacity and Prices
· Section 2.7 Market Outlook
· Section 2.8 Position of SDG&E Relative to Other Utilities
2.1 Background
On March 31, 1998, following a public process that began in 1993 and marked by the passage of AB
1890 in 1996, a new market structure for the sale and purchase of electricity was implemented in
California. Prior to deregulation, retail electricity customers purchased bundled transmission,
distribution, and generation services from monopoly utility companies. Under the deregulated
system, customers continued to purchase transmission and distribution services from the incumbent
utilities~, but could choose to purchase electricity from alternative providers. Customers that did not
choose an alternative provider continued to be served by their utility under default service.
"Customer choice" - allowing electricity customers to choose their own provider - has not been
successful in California. More than two years after the beginning of retail customer choice in
California, less than two percent of residential customers have chosen an alternative supplier.
Approximately 1 ~ percent of industrial customers have selected an alternative provider. Many of the
energy service providers that initially offered service to customers in California have since
withdrawn from the market, returning their customers to the incumbent utilities. As a final blow to
customer choice, the recently enacted AB 1X legislation contained a provision that suspends the
right of retail electricity customers to acquire services from other providers.
Under AB 1890 the Legislature directed the creation of several new institutions in Califomia's
electricity market.2 The California Independent System Operator (ISO) was authorized to operate
(but not own) the investor-owned utilities' transmission systems, ensuring that the utilities did not
charge competitors inequitable transmission rates. In addition, the California Power Exchange (PX)
was established to create a transparent spot market for power. The PX acted as one of several
~ The three incumbent utilities referred to in this paragraph are PG&E, SCE, and SDG&E. All three utilities are investor-
owned utilities (IOUs), which are distinct from irrigation districts and municipal utilities such as Los Angeles
Department of Water and Power (LADWP).
2 See Appendix B for a lengthier description of these new institutions and other agencies that play a critical role in
California's electric market.
February 23, 2001 27 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Scheduling Coordinators (SCs) that submitted balanced schedules of electricity demand and supply
to the ISO.
California's deregulated electricity market is now under fire, the result of price volatility in the
wholesale market, the rising costs of wholesale power, and the subsequent deterioration in the
financial condition of PG&E and SCE. Wholesale power prices rose dramatically in 2000: the
weighted average price of electricity traded on the PX between April 1, 1998 and March 31, 2000
(the first two years of operation) was $29 per MWh compared with an average price of $143 per
MWh for electricity traded on the PX between April 1, 2000 and December 31, 2000. In addition,
frequent instances of Stage I and Stage II emergencies occurred during the summer and late fall of
2000 and numerous Stage III emergencies were called in December 2000 and January 2001. The
ISO was forced to institute "rolling blackouts" three times in January because of inadequate power
?uppIies. Finally, the credit ratings of PG&E and SCE were downgraded to junk~ bond status after
their financial condition deteriorated almost to the point of bankruptcy. These events combined
prompted a re-examination of California's deregulated electricity market.
The Federal Energy Regulatory Commission (FERC), the Califomia Public Utilities Commission
(CPUC), and the California State Attorney General are now investigating the causes of these events,
participants' market behavior, and the structure of the market. Both FERC and the CPUC have taken
actions in an attempt to stabilize wholesale prices. The Legislature also recently voted to give the
Department of Water Resources (DWR) authority to buy poxver on behalf of the utilities, which have
been shut out of the markets as their financial situations worsened and leaving them unable to
procure power to serve their customers.
2.2 Wholesale MarketStructure
Between the beginning of California's restructured electricity market in 1998 and through the late
fall of 2000, the PX served as the primary wholesale spot market for California power. The PX
managed a series of competitive auctions that determined the price of electricity on un hourly basis,
according to demand and supply bids submitted by buyers and sellers of electricity in these markets.
The last generation bid accepted for meeting demand in a particular hour set the market clearing
price (MCP) in that hour for that market. (The last bid was typically the highest price, and all bidders
were paid the market cleating price regardless if they were willing to supply power at a lower price
than the market clearing price.) The PX operated three distinct power markets: Day-Ahead, Day-Of,
and Block Forwards. While most power was sold in the Day-Ahead market, the shift to buying and
selling energy in the ISO's real-time markets became a major concern because prices in the real-time
markets were the most expensive. In January, the PX suspended trading in the Day-Ahead and Day-
Of markets after trading volumes fell significantly.
February 23, 2001 28 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Under AB 1890, SDG&E, PG&E. and SCE were required to bid all their generation into the PX and
to procure all the power their customers needed from the PX. In 1999 the utilities were given
permission by the CPUC to participate in the PX forward markets, and in August and September
2000, the CPUC allowed the utilities to sign bilateral contracts with third parties for longer-term
power purchases. However, the failing financial conditions of PG&E and SCE severely limited their
ability to procure wholesale power tkrough bilateral contracts and on the open market. Energy
service providers faced no such limitations on how they could acquire the power they needed to
serve their customers.
The ISO is a non-profit public enti .ty responsible for operating the transmission system and ensuring
that transmission-owning utilities and their competitors have equal access to the system on
comparable terms and at comparable rates. In California, PG&E, SCE, and SDG&E have
relinquished operational contxol of their transmission facilities ,to the ISO, although most of the
municipal utilities such as the los Angeles Department of Water & Power (LADWP) and
Sacramento Municipal Utility. District (SMUD) have not. As a result, the ISO operates the
transmission system for most of California, with the exception of those facilities owned and operated
by municipal utilities and the federal Western Area Power Administration.
Part of the ISO function as the grid manager is to address imbalances on the system--when more
power is required than was scheduled for delivery or vice versa. The ISO set up what was supposed
to be a small market to address these imbalances, where bidders would supply additional power in
real-time. This is referred to as the ISO real time market. Another part of the ISO function is to
address "congestion." Congestion is the condition where generation is in one region and demand is
in another and the transmission lines cannot carry all the requested power from one region to the
other. In this case, the generators (and users) make "adjustment bids" in which they are willing to
pump more power into the grid where it is needed or less into the system where there is an excess. If
the/'e are not enough adjustment bids, the supply and demand curves in the congested regions are
shifted higher or lower until a region-specific market cleating price is set.
Electricity price caps in the ISO and (the now defunct) PX markets fluctuated over the last year and
were limited in their effectiveness in stabilizing electricity markets in California. Last summer the
ISO lowered its price cap in the real-time market from $750/MWh to $250/MWh. This meant that
the highest price the ISO would accept in the real-time market would be $250/MWh. Although this
price cap did not directly apply to the PX, buyers in the PX day-ahead market would generally refuse
to buy anything above the ISO cap knowing that they would be able to buy power in the real time
ISO market at no more than that cap. This effectively capped the PX market at that same $250/MWh
level. However, generators were reticent to sell into this capped market, and instead were selling
their power into out-of-state spot markets where the prices were not capped3. The ISO responded to
this situation in early December by easing the price cap in the real-time market, which caused prices
to skyrocket in both the ISO real-time and the PX day-ahead markets. However, since there was
congestion on the ISO system during the hours and a hard cap on congestion prices remained at
$250/MWh, no one actually paid these very high prices because congestion prices "trump"
unconstrained prices. Thus, on December 19, 2000 the ISO changed its $250/MWh hard cap on
3 There are a number of designated trading locations throughout the country for electricity spot market trades. In the
West these include the Palo Verde switchyard in Arizona, the California-Oregon border, and Mid-Columbia in the
Pacific Northwest.
February 23, 2001 29 MRW& Associates, Inc.
Confidential Final Report ]~nergy Management Options Assessment
adjustment bids to a price that allows bidders to receive up to $125/MWh above or below the
unconstrained market price. Although this move resulted in higher prices paid by the utilities and
other market participants, it kept generators from fleeing the California market like they did with the
hard $250/MWh cap.
In response to high electricity prices, on December 15, 2000 the FERC ordered (among other things)
a $150/MWh soft price cap in the PX day-ahead, day-of and ISO real-time markets (effective
January 1, 2001). Generators that bid above $150/MWh were to be paid their as-bid costs if called
upon but not be allowed to set the market clearing price. These generators would be subject to
reporting requirements and FERC monitoring. FERC thus far has been unwilling to order a hard
price cap for the ISO real-time market or on a regional basis for the western United States. The
FERC's soft cap order has not been implemented due to software changes needed at the ISO to allow
this kind of bidding and the belief by the PX and ISO that such a system will be subject to abuse.
The PX did not implement this order and shut doxx~ its trading operations effective on January 31,
2001.
By late December the utilities' financial condition had deteriorated significantly, leading to a credit
crunch for the utilities that seriously constrained their ability to continue buying power on behalf of
their customers. On February 1 Governor Davis and the Legislature' passed AB IX authorizing the
Department of Water Resources (DWR) to procure power on behalf of the state's utilities through
long-term contracts. The negotiation of the long-term contracts is ongoing.
2.3 Wholesale Market Price Trends
Prices in the PX ranged from a minimum of $0 per MWh - during off-peak hours when all demand
was met through must-take generation - to a maximum of $1,500 per MWh4 set in December 2000.
The unconstrained,s day-ahead market clearing price for power served as a reasonable guide to price
trends on the PX. Since trading began at the PX on April I, 1998, the average price for electricity
has been approximately $57.72 per MWh. The average price for 2000, however, was about $110 per
MWh. As Figure 2.1 shows, prices fluctuated bet~veen $0 and $75 per MWh in the majority of hours
during the first half of 2000, but in the second half of the year there were many more periods where
prices exceeded $75 per MWh.
At various times, wholesale electricity prices have differed markedly from one part of the state to
another. This is a reflection of transmission congestion and results in "zonal" prices. Hourly prices in
the Northern Zone have ranged from $135/MWh less than, to $125/MWh greater than, the
"unconstrained" market-clearing price. Hourly Southem Zone prices have ranged from $176 greater
than, to $184 less than, the unconstrained market-clearing price. While the average difference
between zonal and unconstrained prices is only a few percent, zonal pricing differences are an
important consideration during times of high congestion. North-to-South congestion occurs most
4 Due to market operations, actual transactions at this price never occurred.
s Unconstrained prices are those determined by the PX before making adjustments based on inter-zonal congestion.
Zonal market clearing prices capture the geographic variation in power market prices in California at those times when
the high-voltage transmission system is congested and energy cannot freely flow between pricing zones. The imposition
of charges resulting from transmission congestion can result in different prices from one zone to the next. The ISO is
responsible for imposing congestion management charges if transmission congestion cannot be relieved through
curtailments of demand or additional power purchases.
February 23,2001 30 MRW & Associates, Inc.
Confidential Final Report Energ? Management Options Assessment
during summer months ~vhen cooling needs are greater in Southern California, while South-to-North
congestion is prevalent in the winter when po~ver demands peak in the Pacific Northwest because of
higher heating demands during the cold weather.
Electricity prices in the western U.S. tend to be driven by seasonality. Electricity prices in
Washington and Oregon are lower in the summer when there is less heating demand and more
inexpensive hydro power available. Electricity prices in Arizona, New Mexico, and Nevada are
lo~ver in the winter when air conditioning demand is Iow. As electricity flo~vs from the northwest to
the southwest in the summer and from the southwest to the northwest in the winter, electricity prices
in California typically fall somewhere in bet~veen prices in the northwest and southwest.
2.3.1 Summer 2000
Wholesale electricity prices during the months of May through September 2000 increased'
dramatically in the PX and ISO markets. As Figure 2.2 illustrates, prices were higher overall in 2000
compared to 1999. In June 2000, prices ~vere 411% higher than in 1999.6 There also were several
periods when very high prices occurred. Price spikes.occurred over three days in Ma3' and again over
a number of periods and days in June. On June 28, 29, and 30 prices bumped up against the $750 per
MWh price cap in a number of hours. This prompted the ISO to lower the price cap from $750 per
MWh to $500 per MWh on July 1. When more high prices ensued in July, the price cap was lowered
again from $500 per MWh to $250 per MWh. As price caps were lowered throughout the summer,
however, the average price actually increased.
2.3.2 Fall/Winter 2000
After falling off from an average high in August, the monthly average PX price climbed steadily
through the remaining three months of 2000. The average price increased from just over $100/MWh
to $170/MWh in November and $377/MWh in December. Prices increased throughout these three
months as natural gas prices and unplanned outages at generating stations steadily increased and less
Block Forward deliveries and imports were available.
6 California Power Exchange, November 2000. Price Movements in California Po*t-er Exchange Markets: Analysis of
Price Activity: May-September 2000, page 12.
February 23,2001 31 MRI~' & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Figure 2.1
Figure 2.2
A, er~ge PX Unconstrained Market Clearing Price
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Confidential Final Report Energy Management Options Assessment
2.3.3 Causes of High Wholesale Prices
Numerous reasons have been suggested as to the underlying causes of the high wholesale power
prices experienced in 2000. Some of these reasons are outlined below:
· Generating capacity is inadequate to meet demand, and will be for the next few years.7
Electricity demand in California is surging by as much as 10% per year due to a robust economy.
In spite of increasing demand, California has not added significant amounts of new large-scale
generating capacity over the past ten )'ears. Also, over 61% of California's existing coal, natural
gas, and other fossil fuel-fired power plants are thirty-years old or older and are increasingly
prone to outages. Finally, California in the past relied on imports of electricity for 20-30% of its
energy needs, but load growth in both the Pacific Northwest and inland Southwest is now
limiting the supply of excess power available for export to California. ,
· SCE, SDG&E, and PG&E failed to take full advantage of the few hedging mechanisms available
to them to purchase power in forward markets, which likely would have mitigated price spikes.8
· End-users are not price-responsive because most consumers do not have the real-time meters or
other tools to receive real-time price signals from the market. Moreover, retail rates are frozen
temporarily in California. From July 1999 through September 2000, SDG&E passed along power
costs dollar for dollar to its bundled customers. In August 2000, the Legislature passed AB 970,
~vhich re-imposed a cap on the ener~' component of residential and small commercial bills
(6.5¢perkWh). The rate cap is retroactive to June 1, 2000 and expires on December 31, 2002.
· Market power may play a role in causing price spikes. Market power can be exercised where a
relatively small number of players control a significant portion of generating capacity. Although
"out-of-state" generators have been singled out for their role in the market place, SDG&E, SCE,
and PG&E still own and control a significant portion of the state's generation assets. (It is worth
noting that FERC, in its November 1 ruling, did not find that any individual generator had
exercised market power. FERC did state that there was clear evidence that marker structure and
rules provided sellers the opportunity to exercise market power when supply is tight. The issue of
market power is a controversial one, and not all parties agree that it does or does not exist in the
Califomia wholesale power market.)
· The underscheduling of loads and generation in the PX day-ahead and day-of markets resulted in
a large percentage of system needs being met in the ISO's real-time markets, which led to higher
prices since the ISO real-time market is the most expensive market.9 If a wholesale buyer
? Although a general scarcity of supply has contributed in part to California's high power prices, there have been claims
that some generators exercise market power even when there is not actually a physical scarcity of supply. This is
discussed in a report by Frank Wolak, James Bushnell, and Severin Borenstein, "Diagnosing Market Power in
California's Restructured Electricity Market," August 2000.
8 SDG&E, in particular, had few financial incentives this past summer to engage in forward markets for energy
purchases: it passed on to consumers its cost of doing business in the wholesale market because its retail rote freeze
under AB 1890 ended in July 1999.
9 The underscheduling of loads and generation occurred in 1998 and 1999, so this is not a new issue. What changed in
2000 is the extent to which loads and generation were underscheduled and the pattern of underscheduling. In general,
underscheduling increases as load increases so that when load reaches a certain level (of megawatts), underscheduling
will always occur. This is tree because underscheduling is a function of price and quantity; put another way,
Februa~ 23, 2001 33 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
underschedules load, demand on the system appears low but in actuality is higher. Therefore, at
the last moment the ISO has to call on more generation in the more expensive real-time market.
2.4 Retail Rates
AB 1890 contained two important provisions affecting the current level of retail electricity rates in
California. First, AB 1890 provided for a I0 percent reduction in rates for residential and small
commercial customers effective in January 1998. Second, retail electricity rates were frozen at June
1996 levels by law during California's transition to a restructured, market-based electricity industry.
The rate freeze implemented under AB 1890 is set to end no later than March 31, 2002. However,
the rate freeze can end earlier than that date, with an earlier end to the rate freeze dependent upon
each utility's collection of certain transition costs. This is why the rate freeze in SDG&E's service
territory ended in 1999 while the rate freeze has not officially ended in SCE's or PG&E's service
territory. In fact, SDG&E collected its authorized transition costs in only 18 months due in large part
to the greater-than-anticipated proceeds from the sale of several of the utility's power plants to
private investors (e.g. the South Bay plant).
Customers still pay SDG&E for distribution, transmission, nuclear decommissioning, and other costs
authorized by the CPUC at rates determined by the CPUC (see Appendix C for a more detailed
explanation of retail rate components).~° However, rates that customers paid from July 1999 through
September 2000 for the electricity "commodity" depended largely upon the market price and from
whom the customer chose to purchase the energy commodity.
When wholesale electricity prices soared in 2000, customers in SDG&E's service territory saw their
electricity bills increase substantially as a result of this design for retail rates. In response, the CPUC
put in place a rate stabilization plan to provide some relief to residential and small business
customers in SDG&E's service territory,n The plan caps the energy portion only (i.e., transmission
and distribution costs are not included in the cap) of rates at 6.5 cents per kWh for residential, small
commemial (less than 100 kW), and street lighting customers. The rate cap is retroactive to June 1,
2000 and expires on December 31, 2002, with the possibility of extending the rate cap another year
if it would serve the public interest. Larger customers can opt-in to the 6.5 cents per kWh rate, but
are subject to an end-of-the year true-up. The CPUC has the authority to raise the ceiling if this
would be in the public interest.
When wholesale prices are higher than the 6.5 cents per kwh SDG&E can charge these small retail
customers, SDG&E has a revenue shortfall, or undercollection.~2 SDG&E filed documents with the
CPUC which put the level of the undemollection at $447 million as of December 31, 2000. SDG&E
underscheduling is a function of where the demand and supply curves inters~t. Ihe slope of the supply curve becomes
very steep at a certain quantity ofmegawatts. Buyers of megawatts have an incentive to limit their demand for
megawatts at that point where the aggregate demand curve intersects the steep slope of the supply curve. Under the
market structure put in place for California's electricity markets, a major wa.'.' in which buyers could limit their demand
at these very high prices was to shift demand into real-time markets by underscheduling load in the day-ahead and day-of
markets.
~o In 2003 the CPUC is scheduled to review SDG&E's distribution rates.
n See Decision 00-09-040.
~2 Under the rate stabilization plan, SDG&E charges retail customers the lower of the actual electric commodity cost or
the ceiling price of 6.5 cents per kWh. As a result, the undemollection only increases. However, because DWR is now
procuring energy for delivery to SDG&E's customers, the growth in the undercollection should slow significantly.
February 23,2001 34 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
estimates that the undercollection could grow to more than $1 billion by the end of 2001. If the
CPUC finds that SDG&E's actual energy costs are "prudent and reasonable", SDG&E will be
allowed to recover those costs from electricity customers. SDG&E will bear the responsibility for
those costs deemed urrreasonable.
Under the recently passed legislation (AB 1X, see the discussion below) which authorized DWR to
procure energy on behalf of the utilities, the CPUC is required to determine the difference between
the utilities' cost of operation (not including the cost of buying power) and their actual revenues.
This difference is known as the California Procurement Adjustment (CPA). The CPUC will
determine what portion of the CPA is allocable to the power sold by DWR and this portion will be
payable by the utilities.
2.5 . Ongoing Reforms to. California's Market System
After the summer price spikes and continuing high prices through the fall and winter, parties from
consumer advocates to utility executives began questioning whether California's restructured power
market is working in the best interests of consumers and other players. Responding to the hue and
cry, various investigations at the FERC, California's Electricity Oversight Board, the State Attorney
General, and the CPUC were launched. FERC responded in December with an order directing
certain remedies be made in the wholesale market. In January the CPUC increased retail rates on an
interim basis for customers in SCE's and PG&E's service territories until further investigations
could be conducted. The Legislature passed new legislation intended to bring stability to wholesale
power prices.
2.5.1 FERC's Reforms for California
FERC is the federal agency in charge of monitoring and regulating interstate transactions in the
*vholesale power markets. Given this mandate, this past summer FERC began investigating the high
prices in western power markets, including the California market. Based on the results of this
investigation, on December 15, 2000 FERC ordered several measures to reduce price volatility,
provide a stable environment to develop new generation resources, and ensure reasonable rates.
Importantly, the measures do not abandon a competitive market for electricity; rather, the measures
are intended to improve the way the market functions and ensure that electricity prices are fair and
reasonable. However, events in late December and January rendered some of FERC's reforms moot.
FERC ordered the following specific remedies:
· The requirement that California's three utilities buy and sell all of their power through the PX
was eliminated. This change was intended to allow the utilities to buy power in the open market
to hedge their price risk by signing contracts with a variety of suppliers. (The utilities had limited
authority to buy power outside of the PX market prior to FERC's order.) It also allowed the
utilities to use their retained nuclear and hydroelectric generation to directly serve their own
customers, rather than selling the power into the PX and then buying it back. Trading volume on
the PX declined dramatically as a result of this order. Ultimately, the PX market became illiquid
and trading was ended altogether at the end of January.
February 23, 2001 35 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
· Generators were required to schedule 95% of their transactions in the day-ahead market or face
penalties. This provision was intended to reduce the amount of trading of power taking place in
real-time markets, where prices are more expensive. Prior to FERC's order, more than one-fourth
of California's required daily power was being traded in real-time markets. This provision is now
moot in light of the end of trading on the PX.
· Wholesale electric prices are capped at $150 per MWh for the next two years, except on a case-
by-case basis (this is being referred to as a "soft cap"). Suppliers bidding above $150 per MWh
must file weekly reports with FERC justifying their bids.
· FERC ordered the PX and ISO governing boards be disbanded and two separate, independent
non-stakeholder governing boards be established. This provision is in conflict with new state
legislation that ordered the ISO board be replaced by a five-member board appointed by
Governor Davis.
FERC also ordered a number of technical, market redesign measures, including congestion
management and interconnection procedures. It called on California policy makers to help expand
generation and transmission capacity, implement demand response programs, and allow load-serving
entities (e.g., utilities) to participate in forward markets. Notably, FERC did not order refunds from
power marketers to utilities forced to purchase power at the very high prices this summer and fall.
As a result, the utilities are now billions of dollars in debt and nearly bankrupt, and the state must
determine how (or whether) to assist the utilities.
2.5.2 CPUC Actions
In August the CPUC opened an investigation into the functioning of the wholesale electric market.
and the associated impact on retail rates in the service area of SDG&E. The CPUC also has taken a
strong position on the issue of refunds (fi.om the power marketers who profited fi.om high wholesale
prices for their electricity in the summer), reflecting in part their mandate to protect the ratepayers in
California. Their power to force such refunds, however, is questionable.
After supporting the move to competitive electricity markets for the past few years, the CPUC is
now struggling to find ways to mitigate the adverse impacts of an unregulated market on ratepayers.
This could include a return in some fashion to greater regulation of the electricity market. The
erosion of support for competitive electricity markets is related in part to the new tenures of
Commissioner Loretta Lynch and Commissioner Carl Wood, who were named to the Commission
by the Davis administration, and the retirement of Josiah Neeper, a Wilson appointee. (Governor
Davis appointed Geoffrey Brown to replace Josiah Neeper.)
In January the CPUC approved a decision that allows PG&E and SCE to increase their retail rates on
an interim basis by one cent per kwh to all customers. PG&E's retail rate is now approximately 6.5
cents per kWh, the same as SDG&E's; SCE's retail rate is higher at approximately 7.2 cents per
kWh. The decision was made in response to the utilities' warnings of impending bankruptcy if they
were not allowed to begin passing on to customers a portion of the high costs of purchasing power in
the wholesale market. (PG&E and SCE are prevented by the retail rate freeze from charging the full
cost of power.) The increase is a temporary surcharge, giving the CPUC time to investigate the
utilities' financial situation in more depth.
February 23, 2001 36 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
The CPUC is also working to develop benchmarks for the utilities' purchases of electricity through
medium-term contracts. Such contracts, extending for up to five years, will help the utilities meet
their customers' electricity demand at a lower cost than purchases of electricity in the spot markets.
However, the utilities want some assurance from the Commission as to what will constitute
"reasonable", and thus not subject to the risk that the co,-ts would be disallowed in the future by the
CPUC. The Commission proposed to set a price benchmark for a 5-year bilateral forward flat
contract of $0.05 per kWh or $50 per MWh? Not all contracts must meet the criteria; rather a
utility's portfolio as a whole should be reasonable.
2.5.3 Recently Adopted Legislation
On February 1, 2001 Governor Davis signed Assembly Bill No. 1. AB IX authorizes the Department
of Water Resources to enter into contracts for the purchase of electricity and to sell power to retail
end-use customers and to local publicly owned electric utilities. DWR can enter into contracts until
January 2, 2003. The three utilities will distribute the power and provide billing and collection
services for DWR.
· California Procurement Adjustment (CPA): The utilities will be required to pay to DWR a
percentage of the amount each retail end-use cu~omer currently is charged for electric energy.
This amount will be determined by the CPUC and is equal to the difference between the utilities'
retail generation rate and the sum of the costs of the utilities' own generation, QF contracts,
existing bilateral contracts and ancillary services.
· Retail rate increases: AB 1X prohibits the CPUC from increasing the electricity charges in
effect for residential customers for electricity consumption up to 130% of the existing baseline
quantities. The baseline varies by region, with a higher baseline allowed for desert regions and a
lower baseline in areas with milder climates. The baseline also factors in whether a consumer
uses both electricity and natural gas, or only electricity.. What remains unclear is what rates will
be charged on the portion of electricity consumed above the 130% baseline threshold.
· Direct access: The right of retail end-use customers to acquire service from alternative energy
providers is suspended until DWR no longer supplies power under the terms of AB 1X. The
provision is intended to prevent customers from bypassing any possible rate surcharges that may
result from DWR's procurement of energy. Strictly interpreted, the provision spells the end of
customer choice for the foreseeable future.
· DWR may sell power it acquires to local publicly owned electric utilities, and it must sell the
power at no more than DWR's costs of procuring the power. However, DWR may not sell power
to a local publicly owned electric utility that is a net seller of power.
In advance of the passage of AB IX, DWR held a blind auction on January 23 and January 24 to
solicit bids from generators to supply power under long-term contracts that could extend for six
months, one year, three years, five years, and ten years respectively. The state received 39 bids
averaging $69 per MWh, although this price did not include bids for summer and winter super peak
This benchmark price has not been formally approved by the CPUC at this time. The criteria are still being debated in
proceeding before the Commission.
February 23,2001 37 MR kg & ~tssociates, Inc.
Confidential Final Report Energy Management Options Assessment
periods and the final terms of the contracts still had to be negotiated. Power is typically most
expensive during super peak periods, so the true average cost to the state of power bought under
these long-term contracts is likely higher.
Governor Davis signed into law three additional bills passed by the Legislature in a special session.
· SB 7X authorized the Department of Water Resources to step into the wholesale market and
purchase power over approximately two weeks to prevent further rolling blackouts (as
occurred in mid-January) and to provide a source of power for the major utilities, which are
hampered in buying power because of their failing credit situations.
· AB 5X requires the formation of a new five-member independent governing board of directors
to replace the existing governing board at the ISO. The Governor was given the authority to
appoint the new board of directors and has already used this new authority to appoint a new
governing board.
· AB 6X prevents PG&E, SCE, and SDG&E from selling their remaining generating facilities.
Instead, the three utilities are required to hold these assets until the CPUC authorizes the
utilities to dispose of the facilities and until at least January 1, 2006.
There are numerous additional bills currently pending in the Legislature's special session that
address one facet or another of the current power crisis. Additional bills to be discussed during the
Legislature's regular session have also been proposed. These bills advocate speeding up the power
plant siting process (AB 20X), boosting conservation incentives (SB 5X), eliminating charges on
distributed generation users hooked into the transmission grid, and tax credits for solar energy
equipment, fuel cells, and microturbines (SB 1X, SB 17X), among other things.
2.5.4 CEC Six-Month Fast Track Siting Process
The need to build new generating plants to meet California's increasing demand for electricity is
frequently noted as a solution to California's power troubles. Under the traditional power plant siting
process, a developer typically must go through a twelve-month review of various issues before the
California Energy Commission (CEC) grants the permit to proceed with developing a power plant.
Pursuant to AB 970, the CEC developed emergency regulations for a six-month, fast-track siting
process for proposed power plants that present no significant environmental impact. The rules
require that developers submit substantial evidence upfront showing compliance with various
standards, laws, and regulations. Under the standard siting process such evidence may be submitted
subsequent to an initial application. The emergency regulations were adopted by the CEC on
November 15, 2000.
To date, no developers have proposed a project that would be eligible for review under the six-
month fast-track process and also be located in the Chula Vista area. However, Ramco, Inc.
currently is developing a 49 MW peaking project in Chula Vista. Because the project is less than 50
MW, it does not need to go through the CEC permitting process. However, the company will have to
obtain air permits from the local air pollution control district.
February 23, 2001 38 MRW& Associates. Inc.
Confidential Final Report Energy Management Options Assessment
2.6 Southern California Natural Gas Transportation Capacity and Prices
The market for natural gas in southern California is increasingly facing tight supply as demand rises.
The emergence of natural gas as the fuel of choice
Table 2.1 for electric generation is a primary contributor to
Existing Gas Transportation Capacity to the tightness of the natural gas markets. This
the CaliforniaBorder section provides a summary overview of the
Pipeline Capacity, million transportation capacity serving the greater San
cubic feetperday Diego region and recent trends in natural gas
El Paso 3,530 prices.
Transwestern 950
PG&E GT-NW 1,800 2.6.1 Transportation Capacity
Kern River 700 Four interstate pipelines bring gas from the supply
In-State production 766 basins to the California-Arizona border. E1 Paso
TOTAL 7,746 and Transwestern bring gas in from the southwest
Source: Natural Gas Market Outlook, California anct~ primarily serve southern California. PG&E
Energy Commission, June 1998. GT-NW brings in Canadian gas at the region
border and generally serves northern California.
Kern River brings in gas from the Rocky Mountain states, and serves central and southern
California.
Gas serving the San Diego area generally comes from production areas in the Southwest and is
transported over E1 Paso or Transwestern interstate pipelines. Within California, the gas is then
shipped on Southern California Gas' 'SoCal Gas) system to SDG&E's system (both Sempra
companies) and finally distributed toxx Figure2.3
end-users in the greater San Diego
area (see Figure 2.3).
Pipeline capacity in general into
southern California, and into San
Diego in particular, is becoming _ ~~__ ~
increasingly tight. The SoCalGas and
SDG&E system was initially designed
to be able to provide gas to its core
customers - residential and
commercial - during the coldest days.~ -- _
General gas load growth in the region
due to increased housing starts, new
businesses, the use of natural gas
vehicles, growth in gas demand for
electric generation, and the start of
delivering natural gas to Mexico in
June 2000 has placed a strain on the
delivery system, to the point where
during the week of November 13, SDG&E began curtailing gas supplies to the three power plants
served by SDG&E and several other industrial customers because of high demand. All three plants
February 23, 2001 39 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
were able to switch to an alternate fuel, and burned fuel oil to make up for the gas curtailments.
Another major pipeline to serve the San Diego area is planned to run from Arizona through
southeastern California to Mexico, interconnecting with the Rosarito Pipeline near Tijuana. The
pipeline is not expected to be flowing gas for another two years.
2.6.2 Commodity Prices
Beginning in the summer of 2000, gas prices took an unprecedented upswing from around $2.00 per
million Btu (MMBtu) to over $6.00 per MMBtu for pre-arranged large packages delivered at the
border and has remained well above $5.00 per MMBtu since. Spot prices for gas at the border have
been even higher, reaching into the upper teens per MMBtu from late November through January.
Figure 2.4 below shows the price of gas at the Arizona-California border since July 1999.
Much of this price increase is being felt nationally; however, it appears to be ~cute in California. The
increased prices are being attributed to an increase in summer demand for gas for electric generation
competing with gas for injection into storage, which would then be available to serve winter
demand. Since less gas was injected into storage over the summer, prices entering the winter have
remained high, as gas utilities and others try to make up for low storage at the same time as meeting
early cold snaps.
Although future prices for gas beyond the winter of 2000/2001 are below $6.00 per MMBtu, they
remain well above the historical average of $2.00 to $3.00 per MMBtu dollars seen over the past few
years.
Figure 2.4
Gas Price at California-Arizona Border
for Delivery to Southern California
$18
$16
$14 _
$12 _
$10
$6
$4
$0
February 23, 2001 40 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
2.7 Market Outlook
2.7.1 Short Term (1-12 months)
There is a confluence of events currently gripping California's electricity industry that has never
been seen before in the United States. PG&E and SCE continue to assert that they are within weeks,
if not days, of bankruptcy if additional relief is not provided. At the same time, federal regulators
and state regulators and politicians do not agree on what remedies to pursue in California and which
agencies have jurisdiction. Rating analysts downgraded the credit ratings of PG&E and SCE, calling
into question their ability to pay power marketers for the electricity they buy, or any other debts for
that matter. Finally, several lawsuits have been filed, moving the debate on California's electricity
crisis into federal courts and adding another dimension to the uncertainty. As a result, predicting
what the next t~velve months hold for Californians is .next to impossible. ,
The outlook for wholesale electricity prices in the short term also is extremely uncertain. General
market fundamentals point toward continued high and volatile prices during this time frame. Some
of these market fundamentals are:
· Some 2,368 MW of new generation located in California is scheduled to come on line by the end
of 2001,~4 but whether it will be sufficient to fend off shortages, particularly during the summer,
is unknown. It is unlikely to exert much downward pressure on prices.
· Natural gas prices are expected to remain relatively high (although not in the extremely high
range currently being experienced), which also would contribute to upward pressure on power
prices.
· This situation could be exacerbated if dryer than normal conditions resulting from reduced snow
pack or lower-than-average rainfall prevail in the Pacific Northwest or California, limiting
hydroelectric production in the summer of 2001. Hotter than normal temperatures this summer
would also exacerbate the supply-demand situation and push power prices higher.
The current efforts by DWR to secure power through long-term contracts at fixed prices may help to
reduce the average cost of wholesale electricity. The full impact, however, is difficult to estimate.
Retail electricity rates are likely to rise for all California consumers. SDG&E filed an application~s
in late January with the CPUC for authority both to impose a surcharge of 2.3 cents per kWh on the
bills of its customers as well as to convert the rate stabilization plan to a rate freeze (i.e., customers
subject to the rate suabilization plan would always pay 6.5 cents per kWh, regardless of the actual
cost of the power, which at times could be lower than 6.5 cents per kWh). The surcharge is intended
to help SDG&E pay down (or keep from rising) the undercollections of costs of purchasing
electricity for its customers (because of the rate ceiling in place for its customers). The CPUC has
~4 California Energy Commission. "Update on Energy Commission's Review of California Power Projects," January 25,
2001. See the CEC website at www.energy.ca.gov/sitingcases.
~5 See "Application of San Diego Gas & Electric Company (U 902-E) for Authority to Implement an Electric Rate
Surcharge to Manage the Balance in the Energy Rate Ceiling Revenue Shortfall Account", Application 01-01-044 filed
on January 24, 2001.
February 23, 2001 41 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
not yet acted on this request. Retail rates may also rise in order for the state to recover its costs of
purchasing power through DWR on behalf of the utilities.
Below are a set of potential outcomes to the current regulatory investigations. There are a myriad of
paths to any of these outcomes, which we will not attempt to predict.
· Utility bankruptcy: It is possible that one or more of California's utilities will declare
bankruptcy because of their inability to pay for generation purchases. A bankruptcy judge could
then take any number of actions, including raising rates or reducing payments to generators or
other creditors. This would address the short-term problems of existing debt but not the longer
term issues of market reform.
· Full re-regulation of electric generation: There is some - albeit limited - debate about returning
t6 the traditional cost-of-service based regulation. In this case, the future cost of retail power
would be a function of the cost to generate power, with the more stable costs of nuclear, coal and
hydroelectric power and longer-term power purchase agreements dampening the volatile cost of
electricity generated with natural gas. There are a number of factors which suggest that re-
regulation would be difficult.
· Significantly greater state participation in the power market: This option encompasses a range of
possibilities. The state has already taken on one role by giving DWR the authority to act as a
power middle-man, using the state's good credit to purchase power which it then resells to
utilities. The state could also require the utilities to turn over some of their assets (generation or
transmission assets) in return for alleviating their debts.
· Market reforms: This, in combination with some elements of greater state participation, is the
most likely outcome. Potential market reforms include some form of regional price-caps (which
would have to be implemented at the federal level by FERC) or mandated purchase portfolios for
the utilities, thereby forcing the utilities to enter into long-term contracts at stable prices for a
majority of their retail obligations (an action which they are inclined to do anyway).
· Unfettered market: This option is the opposite extreme from full re-regulation: allowing the
wholesale market to continue to operate as it has, with full pass4hrough of all generation costs to
retail consumers. Given the recent action of the FERC, CPUC, Governor Davis and the
Legislature, this is a highly unlikely option.
2.7.2 Medium Term (12-36 Months)
· Prices for power acquired by SDG&E will be more stable, but will very likely be higher than
those seen prior to the summer of 2000. This is due in part to prices that will be locked in now
under long-term contracts at higher than historic prices, higher natural gas prices increasing the
cost to generate power, and fundamental market forces, with generation supply having not
caught up with demand.
· Limits on natural gas pipeline and storage capacity in the San Diego area may lead to curtailment
of gas supply to electric generators on days of very high demand. This could exacerbate the
February 23, 2001 42 MRW & Associates. b~c.
Confidential Final Report Energy Management Options Assessment
electricity supply and demand imbalance by forcing electric generators to shut down or limit
production of electricity until natural gas service is resumed.
· SDG&E customers may be in for a potential rate shock as a result of the accrual of large amounts
of deferred power costs by SDG&E. SDG&E's rate stabilization plan is set to end in 2002. It is
not clear what the CPUC will decide to do if SDG&E has an uncollected balance of purchased
power costs at the end of the freeze.
· SDG&E's regulated distribution rates are set to come up for review in 2003. This could be yet
another source of increases in electricity rates.
2.7.3 Long Term (3 to 7 years)
· Wholesale electricity prices should further stabilize and begin declining as new sources of
electricity supply come on line.
· But transmission constraints in the San Diego area could dampen benefits to the region of new
sources of electricity supply.16 SDG&E estimates there will be a need for new transmission
capacity in the region by 2007 if the status quo in terms of power supply is maintained and even
if the proposed Valley-Rainbow 500 kV transmission line is built.
· Constraints on the natural gas distribution system also could pose a challenge for the region, as
noted above.
2.8 Position of SDG&E Relative to Other Utilities
Versus PG&E and SCE: All three utilities are facing mounting debts due to undercollections of
procurement costs and the very real possibility of rate increases or surcharges to pay off those debts.
Because SDG&E's undercollection is less than PG&E's and SCE's, SDG&E customers may face
lower surcharges,l? In the longer term there should generally be pariu' among the three utilities, with
PG&E being at a slight disadvantage with its more sparsely populated service area requiring more
transmission and distribution investment per customer. SDG&E v,511 face short-and medium-term
gas supply problems but in the long term have parity with its northern neighbors.
Versus Munis/Irrigation Districts: In the short and medium term SDG&E will be at a distinct
disadvantage to neighboring municipal utilities and irrigation districts. In the long term, SDG&E's
disadvantage is likely to lessen. However, because of the munis' and irrigation district's access to
power from depreciated federal dams as well as their own depreciated generation assets, SDG&E
~* The San Diego area contains 2,143 MW of generation and experiences a peak demand of roughly 4,000 MW. The
area currently has a simultaneous import capacity of 2,700 MW, which is used to meet the difference between demand
and supply. For reliability reasons and to meet futura demand, both additional generation and import transmission
capacity are planned. (Note that even though it is within San Diego County and within SDG&E's service area, San
Onofre Nuclear Generating Station is not considered within the region's transmission planning area.)
17 SDG&E's undercollection is less than SCE's or PG&E's in part due to differences in customer base and in part due to
the different circumstances of the rate ceiling in SDG&E territory and the rate freeze in PG&E's and SCE's territory.
SDG&E is able to pass through to its large customers its full cost of acquiring power in the wholesale markets while
PG&E and SCE are not because of the retail rate freeze still in effect in their territories. Thus, SDG&E's undercollection
has not reached the proportions of the other two utilities' undercollections.
February 23,2001 43 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
will continue to be at a price disadvantage even in the long term.
Versus Out-of-State: In the short and medium term, SDG&E will be at a price disadvantage to most
out-of-state utilities. However, the power shortage is regional, and other western states will also
likely face some supply difficulties. SDG&E should in the long term have parity with southwestern
states, but continue to be at a price disadvantage x~ith respect to states in the Pacific Northwest due
to their large hydropower resources.
February 23,2001 44 MR}V & Associates, Inc.
Confidential Final Report Enemy Management Options Assessment
CHAPTER 3
ENERGY MANAGEMENT OPTIONS
In 1999 the Chula Vista City government consumed 13.3 million kwh~s of electricity at a cost of just
over $1 million. Its gas consumption was much less, totaling 255,000 therms, at a cost of
approximately $138,000. When combined with the energy use of its citizens and businesses, the city
and its residents consumed about $62 million of electricity (700 million kWh) and about $24 million
of gas (150 million therms). About two-thirds of the gas consumption is attributed to Duke's South
Bay Generating Station. Table 3.1 shows the breakdown of electricity and natural gas consumption
by sector for Chula Vista. These are
full retail costs and not simply the
Table 3.1 commodity costs~9.
Electricity and Natural Gas Consumption
By Sector Electricity and gas costs will be higl~er
Millions of '000 of for 2000 and will likely be higher still
kWh Therms in 2001. Because of the rate freeze for
Municipal Government 13 256 small commercial and residential
Industrial 101 8,043 customers, total electricity costs for
Residential 288 7,067 these sectors will escalate only
Commercial 291 21,214 moderately. However, with no price
Electric Generation 110,667 ceiling on natural gas, the total cost for
Total 693 147,246 that fuel could increase by a factor of
two or more.
Figure 3.1
Average Cost of Electricity in Chula Vista (1999) Average Cost of Gas in Chula Vista (1999)
12.0 70
100 68
.~ 62
~s In electric utility convention, retail electricity is expressed in kilowatt-hours (kWh) while wholesale electricity is
expressed in megawatt-hours (MWh). This report follows that convention. There are 1,000 kilowatt-hours in a
megawatt-hour.
~9 For both natural gas and electricity, typically about 50% of the retail rate (¢ per therm or kwh) is covers the cost of
building and maintaining the transmission and distribution system and miscellaneous administrative functions. The
remainder is supposed to cover the "commodity cost"--the actual wholesale cost of the gas or power to SDG&E.
February 23, 2001 45 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
This chapter presents an overview of ten options the City could pursue as part of its efforts to
manage its energy supply and demand, to reduce its exposure to escalating electricity and natural gas
prices, and to help ensure the reliability of transmission and distribution systems serving the City.
The options are grouped in broad categories, as follows:
· Section 3.1 Power Generation Options for Chula Vista
Option 1 - City Finances, Owns, and Operates Large-Scale Power Plant
- Option 2 - City Partners with Third Party to Build and Operate Plant
Option 3 - Install Distributed Generation to Serve City Load
· Section 3.2 Renewable Energy And Energy Conservation Options
Option 4 - Promote Energy Efficiency in City Buildings
Option 5 - Implement Conservation Programs for Business and Residents and Promote
Community Education
· Section 3.3 Electric Commodity Procurement Strategies
Option 6 - Contract with an ESP
Option 7 - Pursue a Bilateral Agreement for Power Supply
Option 8 - Municipal Aggregation
Option 8a - Other Aggregation Options
· Section 3.4 Municipalization
Option 9: Form a Vertically Integrated Municipal Utility
Option 9a: Form A Municipal "Distribution-Only" Utility
Option 9b: Form A "Muni-Lite" Utility
Option 9c: Form A Municipal "Generation-Only" Utility
Option 9d: Declare the Formation of a Municipal Utility
· Section 3.5 Emissions Offset Trading (Option 10)
The ten options discussed in this chapter address both the supply side and the demand side. In other
words, the City can choose to address its energy situation by targeting the supply of electricity (or
natural gas), by targeting the demand and consumption of electricity (or natural gas), or both. The
various options are also both short- and long-term in nature. In general, the supply-side options are
longer term ones, whereas the City could have a more immediate impact on the demand side..
Finally, some options may require a substantial investment while other options can be considered
low-cost. Table 3.2 provides a side-by-side comparison of all the options in terms of implementation
time frame, level of initial capital investment required, to whom the benefits will accrue, and
whether the option targets the supply or demand side.
February 23, 2001 46 MRtV& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
3.1 Power Generation Options For Chula Vista
The options discussed in this section directly relate to the level of self-sufficiency Chula Vista can
gain in the area of power purchases and requirements from SDG&E and the broader electric
markets. By becoming less reliant on either SDG&E or the broader electric markets for its power
supplies, Chula Vista gains some protection against unfavorable energy market conditions.
Option 1: City Finances, Owns, and Operates Large-Scale Power Plant
The City has the option to reduce its overall exposure to wholesale electricity prices and reliability
risk by constructing and o~vning its own generation plant. A new plant could meet a portion of the
City's load, reducing (but probably not eliminating) purchases from SDG&E, including during
periods of extreme high prices. When the rate freeze in SDG&E's service territory ends, price
volatility may again become a factor to consider in assessing local generation. For example, rather
than sizing a power plant to meet a certain level of average demand, it may be more advantageous
to size the plant to meet peak demand and to sell incremental power to the grid when demand is
less than the plant's capacity. This could dampen the impact of price spikes during peak demand
periods, provide significant additional revenues, and improve local electric reliability.
The following discussion applies primarily to a large-scale, fossil fuel-fired power plant. Small-
scale plants and renewable energy are discussed under Option 3.
Cost/Pricing Issues
The economics of generation typically are site-specific because they are a function of electric
demand, thermal load, rate schedules, and other factors. While investments in self-generation are
typically pursued by larger industrial customers, a municipality can also benefit from this option.
The City could expect to incur the following types of costs in owning and operating a large-scale
power plant:
· fuel costs,
· labor costs for plant operators,
· other operations and maintenance costs,
· costs for acquiring emission offsets on an annual basis, and
· payments to SDG&E for any wheeling of power that is necessary (i.e., the City would
likely need to use SDG&E power lines to transmit the power from the generator to city
end-users such as city offices, for which Chula Vista will have to pay a fee).
Table 3.3 below presents cost assumptions for two generic power plants to illustrate the potential
costs involved in building and operating a power plant. As discussed below in the pre-feasibility
assessment section, the City could expect to make an investment of approximately $60 million to
$90 million just for the initial capital investment.
February 23, 2001 49 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Ass~sment
Table 3.3
Generic Resource Assumptions
Category Combined- Combustion
Cycle Turbine
Capacity (MW) 500 ! 50
Capital Cost (S/kW) $600 $360
Variable O&M ($/MWh) $2.00 $3.00
Fixed O&M ($/kW-yr) $10 $5
Source: California Energy Commission, Market Clearing Prices Under
Alternative Resource Scenarios 2000-2010, February 2000.
Regulatory Issues
The regulatory process and administrative requirements for building and operating a power plant
are discussed in detail in Appendix D. In brief, the following are the major regulatory issues that
would need to be addressed in developing a large-scale power plant:
· Siting. California has relatively strict rules concerning the siting of new power plants, designed
to minimize environmental impacts and disruption to local communities. Any entity xxishing to
construct a new thermal (i.e., coal or gas-fired) power plant rated at 50 MW or more must be
certified by the CEC. The CEC grants certification only to projects whose applicants
demonstrate that adverse impacts are minimal or can be sufficiently mitigated. Construction on
a new plant can only begin after .certification is complete, usually more than a year after an
application is filed. Preparing the application requires many months. Among the issues the
CEC considers are project costs, electric system reliability impacts, community quality of life
impacts, health and safety impacts, socioeconomic impacts (including environmental justice),
and environmental impacts.
The CEC has exclusive jurisdiction to certify thermal power plants of 50 MW or more in
capacity and all related facilities such as transmission lines and can use this jurisdiction to
override the decisions of other local, regional or state agencies if certain conditions are met?
However, the CEC is directed, by statute, to consult with other responsible local, regional, or
state agencies and to make a finding whether a proposed project complies with all applicable
laws and ordinances. If a project does not comply with an applicable law (e.g., land use
determinations), the CEC is required to make two findings before it can override the authority
of another agency: that there is a public need for the project and that there is no reasonable
alternative to the project.21
A particularly important issue in the San Diego area is the access to natural gas. As the City is
probably aware, natural gas service to Duke's South Bay plant has been curtailed on a number
20 California Energy Commission. Energy Facility Licensing Process: Developers Guide of Practices and Procedures.
Dra~ Report, November 2000, p. 12.
2~ The CEC has rarely used its override authority to approve a project that another agency has ruled against. However,
in the few cases where a party pursued an appeal ora CEC decision to the State Supreme Court, the final legal avenue
for appeal, the CEC's decisions have been upheld in all cases.
February 23, 2001 50 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Agsessment
of occasions recently, and the issue of fuel has slowed down the development of the proposed
power plant at Otay Mesa.
· Operating and scheduling activities. Beyond the technical expertise needed to run a power
plant, any agent selling power through the ISO controlled power grid must have a "Scheduling
Coordinator" who interfaces with the ISO. Becoming a certified Scheduling Coordinator
requires submitting an application to the ISO, completing various contractual agreements,
meeting various technical requirements related to data transmission, and undergoing training
and testing. It is not uncommon for generators to outsource Scheduling Coordinator functions.
Case Studies
There are numerous examples of municipalities (with no municipal utility) owning and operating
small cogeneration or generation facilities, such as those discussed under Option 3 (see below).
Those facilities that are not cogenerati6n are most frequently small hydroelectric plants (one
megawatt or less) located in or near the city. Local examples of this include the City of San
Diego's Point Loma hydroelectic plant (1.35 MW) and the City of Oceanside's peaking
hydroelectic plant (0.35 MW).
The only example of a non-utility, municipality-owned and operated large-scale power generating
facility in California is the City and County of San Francisco's Hetch Hetchy reservoir system.
The power from Hetch Hetchy's turbines serves San Francisco's city government's electricity
needs ~ith excess power sold to Turlock and Modesto Irrigation Districts. (The federal law that
allowed the construction of the Hetch Hetchy dam stipulated that San Francisco sell any excess
power from Hetch Hetchy to public agencies.)
There are many examples of municipal utilities building and operating both gas-fired and
hydroelectric power. One of these is discussed in Section 3.4.
Pre-Feasibility Assessment
The optimal size of a power plant for Chula Vista would depend upon numerous factors. For
example, assuming (hypothetically) that Chula Vista formed a municipal utility and acquired
distribution assets22, a power plant sized to meet the current peak load of the City's government,
residents, businesses and industry would have to be able to generate roughly 100 to 150 MW.23
During non-peak times, excess power could be sold in wholesale markets or through other
agreements. To meet the current average load of the city government, residents, businesses and
industry would require an output of about 80 MW. In this case, contracts or other resources (such
as solar energy) would be required to make up the difference during peak demand periods.
Altematively, the City could build one or more 49 MW facilities, and thus bypass much of the
complex CEC siting issues imposed upon plants rated at 50 MW or more. Determining the optimal
size of a plant to serve Chula Vista, whether the City formed a municipal utility or not, should be
addressed as part of detailed engineering and financial risk studies.
Meeting orfly th~ city government's needs requires about 3 MW during times of peak demand or
about 1.5 MW on average. Because this load is much less than the output of a major power plant,
22 Municipalization is discussed in Section 3.4. Owning generation is not necessary for municipaliziation.
23 For reference, Duke's South Bay plant generates about 700 MW.
Februar). 23.2001 51 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
the size of a major plant would depend upon the city's strategy for marketing the excess
generation. (Meeting this load alone is discussed in the distributed generation section.)
At $600 per installed kilowatt of capacity for a natural gas combined-cycle--the generation
technology of choice--a new power plant would require a capital outlay of approximately $50
million (for an 80 MW plant) to $90 million (for a 150 MW plant). Such a plant could have
generated power at 3 to 4 cents per kWh at historical natural gas prices. Given current high gas
prices, the production cost would be 10 to 12 cents per kWh. All of these values are below current
wholesale market prices, but there would be no guarantee that this would continue or that a
sufficient margin could be generated to pay offthe capital cost of the plant. Furthermore, the long
range contracts recently solicited by the state already are reported to average 6.9 cents per kWh, at
which price gas would need to be at most $6 to $7 per million BTU for the a plant to cover its
operating costs and fixed debt obligations.
Table 3.4
Production Cost Comparison for Large Power Plant
Investment Production Cost, C/kWhz
Plant Purpose If Municipalized~ Size (MW) Technology (Millions) Current Historic
Gas Costa Gas Cost4
Meet City's current peak demand; sell150 Combined $90 10.8 3.1
any excess generation Cycle
Combined
Meet City's current average demand 80 Cycle $48 10,8 3.1
Peaker: Minimize exposure to high 49 Combustion $20 15.2 4.2
)rices during peak demand periods Turbine
1. Otherwise, these all would be merchant plants selling into the wholesale market_
2. Variable cost only--does not include capital recovery costs.
3. $15/MMBtu at the burnertip
4. $4/MMBtu at the burnertip
Constructing a large-scale power plant will only provide benefits to the City in the long term,
given the long lead time required to develop and construct such a plant~ The City would need to
weigh the benefits of this approach against the numerous regulatory hurdles involved in permitting
and siting a new power plant and the administrative requirements for operating the plant and
bidding generation into power markets.
Future Outlook
The financial viability of a power plant depends in large part on the price of power in the
wholesale market and the price and availability of natural gas. Wholesale power prices in
California and the western U.S. recently have been quite high. However, the City must consider
the long-term forecast for power prices in. evaluating this option, understanding that in the long
term power prices may return to lower levels.
The overall supply of generating capacity relative to demand will have the greatest long-term
impact on power prices in California. Over-capacity would depress power prices by foming more-
efficient generating units to the margin (i.e., to set the market-cleating price), while prolonged
February 23, 2001 52 MR~V& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
under-capacity would increase power prices by forcing less efficient generators to run ~eater
numbers of hours (factoring in the relative cost of fuel to power the less efficient plants). Seasonal
variations in electricity demand and unit availability can increase or decrease the relationship
between capacity supply and prices.
The CEC and others are predicting tight capacity for the next two years, followed by a period of
relative over-capacity. Currently, various developers have plans to build more than 15,000 MW of
new capacity to serve the California market. Of this amount, the developers of over 10,000 MW of
new capacity have already started their efforts to obtain siting approval from the CEC. In a CEC
report on future power prices, the CEC staff assumed that 2,840 MW of new capacity x~ill be
added by 2002, with another 6,400 MW being added between 2003 and 2010, depending on
whether developers pursue a cautious or an aggressive development approach. It should be noted
that under either scenario, the CEC believes that owners of new power plants cannot fully recover
their costs and earn a fair return on equity given the power prices predicted by the CEC. It is also
worth mentioning that no parties believe that anywhere near all of the 15,000 MW of proposed
power projects will be built over the next ten years. However, even if no more generating capacity
than is assumed to be constructed in the CEC repori actually gets built, commodity power prices
will likely decline relative to current levels by 2003.
Recommended Action
MRW considers this option to be one of the more risky options available to the City for a number
of reasons. First, developing a power plant requires a large capital investment and significant
financial risks which are beyond that which municipalities commonly accept. Second, siting,
developing, operating and selling the output from a major power plant requires very specialized
expertise that the City does not currently have. Third, natural gas deliverability is currently
severely constrained into the San Diego region, and although new pipeline capacity is expected to
be built to serve the region, other large gas users such as the Otay Mesa power plant are also
expected to add to demand. Fourth, because the rules and structure of California's power market
~vill have changed by the time a large-scale power plant can be sited, developed, and constructed,
this option should be undertaken only after a careful assessment of the potential risks and the
financial viability of a power plant.
N~rt Steps
MRW does not present any additional action items related to this option at this time. If the City
decides to investigate this option in the future, the City's first step should be a pre-feasibility
analysis that could evaluate different size and system configurations, potential sites, and capital
requirements.
Option 2: City Partners with Third Party to Build and Operate Plant
This option differs from the above option primarily in terms of which party assumes responsibility
and risk for the construction and operation of the plant. Under this option the City avoids the need
to hire the necessary personnel to operate a power plant. In addition, by contracting with a third
party to build and operate the plant, the City is able to shift much of the risk to the operator,
including fuel procurement risk and other services that may not be readily available to the City. In
February 23,2001 53 MR W & Associates, Inc.
Confidential Final Report . Energy Management Options Assessment
doing so, the City may end up with a less advantageous power supply arrangement or higher costs,
but at greatly reduced risk.
Partnering can take a myriad of different forms, depending upon the interests of the City and the
developer and the creativity of the negotiators. Some of the potential partnering options include:
Equity stake in power plant. The risks and benefits of this option would be similar to that of
full city ownership, except the total capital outlay would likely be less and the developing
parmer would presumably bring expertise in siting, building, and operating a power plant
and in procuring fuel. In return, the City would have rights to a portion of the plant's output
for city government use, to serve as a source of power for a municipal utility or a municipal
ag~egation program, or to be sold onto the open market to the benefit of the City.
· Assist in financing the power plant. The City. could partner with the developer by providing
municipal, tax-free financing for the City's capital requirements. The developer would be
responsible for building and operating the plant, with the City receiving the fights to a
portion of the plant's output.
· Lamt lease. The City could lease to the developer the land upon which the power plant is
built. The City could receive lease payments or some other kind of remuneration (e.g.
power) for the use of its land.
· Sen'ices for power agreements. The developer of a power plant will need to work with a
host city on numerous issues, such as rights of way for gas pipelines to serve the plant as
well as transmission lines to the grid, land use determinations, numerous permits and
zoning variances, and property tax assessments, to name a few. The local government has
the authority to make determinations on a plant's compliance with local laws and
ordinances, and the CEC is bound by statute to take these determinations into consideration
when certifying a power plant. This places the City in a good position to work with the
developer to facilitate the siting and certification process in exchange for the developer
addressing issues important to the City and its residents,
· Over-the-fence agreements. An over-the-fence agreement is when a power or cogeneration
plant is built adjacent to a large energy user such as a manufacturing facility or office park.
The power from the plant, or in the case of cogeneration, steam, is sent "over-the-fence"
and used, sometimes exclusively, by the neighboring user. This allows for a party other
than the energy user to own the power or cogeneration plant. An over-the-fence
arrangement also avoids using SDG&E's transmission and distribution system (and hence
the payment of wheeling charges). The City itself could partner with an industrial user,
either already existing in Chula Vista or one contemplating relocation there, to approach a
developer to build a power or cogeneration plant for over-the-fence sales to the industrial
user. Even within this framework, any of the above ownership options would be available.
Cost/Pricing Issues
The actual costs to the City of pursuing a partnership agreement with a developer will vary
depending upon the type of arrangement the City enters into with the developer. The costs will
February 23. 2001 54 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
also depend on the City's cost of capital, the availability of land zoned for this type of use, the
value of land and any associated tax revenues or credits.
Regulatory Issues
In general, the regulatory issues are the same as those outlined in Option 1, with the fundamental
difference being that the third party partner would very likely address the filing and other
regulatory requirements.
Case Study
The City of Redding's Redding Electric Utility (REU) has long-term power purchase agreements
with the Western Area Power Administration (WAPA) that end on December 31, 2004. This
contract is being replaced by a new long-term contract with WAPA. However, less power will be
available through WAPA as portions of expiring contracts are set aside for new WAPA customers.
Because of this, REU xx511 not have enough power to meet the needs of Redding's citizens unless
additional resources are added.
To meet a portion of this shortfall, and to meet the needs of projected demand growth, REU is
planning to install a 43 MW combustion turbine (CT) at the existing Redding Power Plant site.
The CT would burn natural gas and will be capable of producing enough steam to generate an
additional 11 MW in the steam-powered generator already in operation at the Redding Power
Plant, improving overall efficiency. The addition of the CT will make approximately 140 MW of
generating capacity available at Redding Power Plant (54 MW new plus 96 MW existing) - 45
percent of REU's total power supply needs. REU currently anticipates the CT to be on-line and
operable by the summer of 2002. REU currently estimates that the CT will cost approximately $40
million. Most, if not all, of this amount will be financed by REU.24
Pre-Feasibility Assessment
Given the range of partnership arrangements and site-specific nature of over-the-fence agreements,
MRW did not conduct a pre-feasibility assessment of this option. Nevertheless, the City has
potential leverage in pursuing a favorable partnership if it can offer a developer the following:
· an attractive load profile
· strong creditworthiness as an end-use buyer of the plant's output
· a guaranteed source of demand for the plant
· local support for siting a power plant in the City (although CEC approval of power plants - if
necessary - is not contingent on local approval).
Future Outlook
The City's proximity to DENA's South Bay Generating Station provides an excellent partnering
opportunity that the CiD' is already investigating. South Bay is a 706 MW facility acquired from
SDG&E and now owned by the Port of San Diego and operated under lease by DENA. Under the
24 Further details as to the operating costs (e.g., capacity factor, expected heat rate, fuel costs, etc.) of this addition are
not available, so MRW is unable to provide an estimate of the cost of energy the CT will produce. Assuming the $40
million project cost is the project's initial capital investment requirement, the 40 MW CT would have an installed cost
of about $930 per kW. As noted above under Option 1, an efficient combined cycle gas turbine typically has an
installed cost of $600 per kW.
February 23, 2001 55 MRW& Associates. Inc.
Confidential Final Report Energy Management Options Assessment
terms of the lease, DENA has committed to modernize South Bay, replacing the aging facility with
state of the art combined cycle units and increasing its generating capacity and loxvefing its
emissions by 2009. When the modernization is completed, South Bay will produce at least 700
MW of cleaner generation for the San Diego load center. DENA hopes to accomplish this
modernization well in advance of this date.
As discussed here, partnering can take a myriad of different forms, depending upon the interests of
the City, the developer, as well as the creativity of the negotiators.
Recommended Action
The City should be open to DENA as they make plans to modernize the South Bay power plant or
to other developers that may be seeking to locate a power plant within City limits. The City can
leverage its opportunities for partnering with DENA or another developer by remaining engaged
on the broader effort to modernize the South Bay plant and seeking opportunities for the City to
become proactively, and positively, involved in the development. This approach should pave the
way for the City to negotiate preferential terms such, as providing attractively priced power to the
City and making attractively priced poWer available to city residents and businesses.
In terms of other partnering opportunities, MRW recommends that the City explore opportunities
to tie in over-the-fence projects of less than 50 MW with new business or industrial developments
in the City. While the City itself need not get financially involved in such projects, acting as an
information source and assisting in brokering deals between potential power and real estate
developers would benefit the City.
Next Steps
The City should continue to proactively approach and work with DENA. The City should take
steps to integrate energy into on-going and future business development activities. This may mean
hiring someone whose primary responsibility is fostering energy projects for the City. and
supporting energy aspects of business development. Pan of this person's responsibility could
include assisting real estate and power developers to put together over-the-fence agreements and/or
look for opportunities.
Option 3: Install Distributed Generation to Serve City Load
An alternative to traditional, large-scale, centralized power plants is decentralized or "distributed"
energy generation. Distributed generation refers to small power generation units (generally a few
kilowatts to a few megawatts) that are located near consumers or targeted load centers.25 They are
sized to meet the power needs of the user on whose property the generator is located. Office
buildings or light industry are typical hosts for distributed generators. Distributed generation has
the advantage of not requiring CEC approval, ISO "load scheduling" nor emissions permits.
25 There is no set definition for the capacity range of distributed generation equipment. In general, distributed
generation resources are relatively small--a few kilowatts up to a few megawatts, are located at or very near the
consumer's site, and provide power primarily for that customer rather than for sale on the grid. Also, distributed
generation resources typically are interconnected with the local distribution system (up to 12,000 volts, but generally
below) or directly connected to the customer's site. Larger-capacity generation plants that provide wholesale power
generally connect into the grid at a transmission level (69,000 volts or above).
February 23, 2001 56 MRW & Associates. Inc.
Confidential Final Report Energy Management Options Assessment
Distributed generation offers the potential for reduced electricity costs through enhanced
distribution efficiency. Other benefits that distributed generation could potentially provide,
depending on the technology, include reduced emissions, utilization of ~vaste heat, improved
po~ver quality and reliability, and deferral of transmission or distribution upgrades. Distributed
generation technologies include combustion turbines, fuel cells, microturbines, and photovoltaics,
among others.
There are many factors that today are driving a rene~ved interest in distributed generation,
including the environmental challenges of siting a large power plant and technological
developments that have improved the cost and performance of small, modular generating units.
Distributed generation also offers many benefits, which make it an attractive option in certain
situations.
· Peak power typically is the highest cost power to acquire. Using distributed generation as a
source of electricity during peak periods rather than pumhasing power from SDG&E may
allow the City to reduce its overall costs for electricity by offsetting the high cost of peak
power with self-generated (and potentially less e~pensive) power.
· Distributed generation can be a source of voltage and frequency support for the regional grid,
improving the overall reliability of the electric system. The City, and more importantly its
high-tech businesses, benefit from a more reliable electricity system.
· The City can reduce its vulnerability to utility power outages through the use of distributed
generation.
Cost/Pricing Issues
The two main costs of distributed generation are the capital costs of the technology and the
operating costs. These costs will vary. by technology type. The discussion below provides a brief
overview of cost issues for four types of distributed generation technology, and Table 3.5 outlines
some of the fundamental characteristics of these technologies.
Simple cycle gas turbines are the most mature technologically; therefore, there are numerous
suppliers (including Solar Turbines in San Diego), purchase costs are lower, and their performance
is proven. However, they are not particularly efficient, making them more sensitive to fuel costs,
and somewhat more polluting than the other distributed generation technologies discussed here.
Microturbines are similar to simple cycle gas turbines, but differ in both size and complexity.
They are a factor of ten or more smaller than standard gas turbines, and contain only one moving
part: the turbine, compressor, and generator are on a single shaft. They also use air bearings and
need no lubricating oil. While generally not as efficient as the larger simple cycle gas turbines,
their small size and reduced maintenance resulting from their simple design make them
particularly attractive for distributed generation applications.
Fuel cells are an environmentally clean, quiet, and highly efficient method for generating
electricity and heat from natural gas and other fuels. They are vastly different from other power
systems. A fuel cell is an electrochemical device that converts the chemical energy of a fuel
directly to usable energy ~ electricity and heat - without combustion. The current high cost of fuel
February 23, 2001 57 MRW & Associates, Inc.
Confidential Final Report Energy Manage ~ment Options Assessment
cells makes them best suited for environmentally sensitive areas and for customers with power
quality concerns. However, significant fuel cell research and development efforts are underway,
which could reduce the technology's cost to the lower end of that shown in Table 3.5.
Photovoltaics (PVs) are solid state devices that directly convert solar radiation into direct current
electricity. Photovoltaics, or solar cells, are modular, with small cells grouped together and
mounted on a single plant to make up a PV module. A typical commercial module has about one-
half square meter of surface area {about 5 square feet) and can produce about 50 watts. To meet
the peak power needs of a D'pical home would require about 2 kW or 200 square feet of
photovoltaics.
Table 3.5
Comparison of Selected Distributed Generatign Technologies
Simple Cycle Gas
Turbine Microturbine Fuel Cell Photovoltaics
Product Rollout Already . Just reaching Commercially Already commercial
commercial commercial markets available over next
10 years
Size Range (kW) 1,000+ 30-200 50-t,000+ 1+
Efficiency (%) 21-40 25-30 35-54 n.a.
Package Cost ($~3~W) 300-600 350-750 1,500-3,000 n.a.
Turnkey Cost ($~2~xh) 650-900 600-1,100 1,900-3,500 5,000-10,000'
O&M Costs (S/kWh) 0.003-0.008 0.005-0.010 0.005-0.010 0.001-0.004
Source: Gas Research Institute
Regulatory Issues
There axe numerous regulatory issues currently being addressed at the CPUC that will have short-
and long-term impacts on how distributed generation in California will be implemented and what it
will cost.26 The key issues relevant to the City that are currently being addressed by the CPUC are:
· Stranded Costs: The utilities argue that distributed generation causes stranded distribution
costs (a loss of revenue because fewer kilowatt-hours are being distributed) and that they
should be permitted to recover these "stranded" costs. Other intervenors argue that distributed
generation is effectively like conservation, and that no costs are stranded.
· Standby Charges: Should distributed generation customers pay standby charges and if so,
how much?
· Interconnection Costs: Sometimes the host utility must alter or upgrade some components of
the local distribution grid adjacent to the distributed generation host. The primary area of
controversy relates to who should be responsible for the cost of those system upgrades. (In
December 2000 the CPUC adopted Decision 00-12-037 directing the utilities to replace their
26 Order Instituting Rulemaking Into Dism'buted Generation, Rulemaking 99-10-025
February 23,2001 58 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
interconnection tariffs with a Model Tariff intended to standardize the interconnection process
throughout the state.)
· Distribution-Only Wheeling Rates: "Distribution-only" wheeling occurs when the generation
source and user are close to each other but still must utilize SDG&E distribution lines to move
the power from the distributed generator to the load. Various proposals are on the board as to
whether a distribution-only wheeling rate is appropriate, with positions ranging from the
distributed generation customer paying existing full tariff wheeling rates to setting the rate at
the "incremental" costs of providing service to no wheeling charge at all. This could be an
important issue for the City if it were to install a small generator in one location (e.g.. a
maintenance yard) and want to use its output in another (e.g., city offices).
· Independent Clean Energy Tariff.' Some intervenors propose that solar, wind, fuel cell, and
possibly other renewable energy projects be exempted from standlSy and interconnection
charges.
Aside from the decision rendered on interconnection.costs (noted above), the CPUC has not issued
decisions settling the other outstanding matters in this proceeding. The CPUC is expected to render
a decision on many of these issues in 2001. How it addresses these issues will have a large impact
on the viability of distributed generation for' the City.
Pre-Feasibility Assessment
MRW conducted an order-of-magnitude estimate of the economics of three distributed generation
technologies applied to the Chula Vista Police Department building: a microturbine, a fuel cell
assembly, and photovoltaics. The simple cycle turbine was not considered because its generation
capacity was significantly greater than the power needs of the building being studied. As Table 3.6
indicates, any of the three technologies may or may not be cost-effective relative to continued
purchases through SDG&E. When higher cost, lower efficiency assumptions are used, the three
technologies are estimated to produce power at about 15 to 17 cents per kilowatt-hour. When the
lower cost, higher efficiency assumptions are used, the three technologies are estimated to produce
power at about seven to eight cents per kilowatt-hour. Not included in this analysis is the costs and
benefits of waste heat recovery from the microturbine or fuel cell for water heating.
The last line on Table 3.6 shows the "avoided cost." The avoided cost is the average price of the
power displaced by the distributed generation system. When a distributed generation system can
generate power at an average cost less than the price of the power it is displacing, it is cost-
effective. Thus, if the average cost of power from a microturbine or fuel cell is less than about
11.2C/kwh, or less than 13.2C/kwh for the photovoltaic system, then the distributed generation
alternative would be .cost-effective. These are based on the Police Station's current SDG&E tariff,
AL-TOU. Avoided costs for the microturbine and fuel cell are lower than for photovoltaic system
because they operate nearly 100% of the time, displacing the less costly off-peak power as well as
the more expensive peak power. The photovoltaic system generates electricity primarily during
bright, warm days and hence tends to displace only the costly peak power.
In the case at hand, the avoided costs fall within the range of the possible average costs of each of
the distributed generation technologies considered. Therefore, depending upon the actual costs,
particularly the installed equipment cost, and for the microturbine and fuel cell the cost of natural
February 23, 2001 59 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
gas, the distributed generation alternative may or may not be cost effective. A more detailed
engineering study would be required to better match the technology to the application and provide
more precise cost and performance estimates. Sensitivity analysis for the assumptions would also
illustrate what factors could potentially affect viability of a distributed generation project at this
location. Nonetheless, the preliminary numbers are promising.
Table 3.6
Hypothetical Application of Distributed Generation
Chula Vista Police Department
Annual Usage, kWh 1,370,400
Peak Demand, kW 238
Microturbine Fuel Cell Photovoltaice
Potential for hot water? yes yes no
System Capaci~, kW 200 200 100
Energy, kWh/year 1,329,288 1,329,288 369,002
% of Energy Needs Met 97% 97% 27%
Investment
High $220,000 $700,000 $500,000
Low $120,000 $380,000 $250,000
Fuel Cost, ¢lkWh
High ($10/mmBtu) 13.7 9.8
Low ($5/mmBtu) 5.7 3.4
Operating and Maintenance, ¢lkWh
High 1.0 1.0 0.4
Low 0.5 0.5 0.1
Investment Recovery (15 years, 7% nominal discount rate), C/kWh
High 1.8 5.8 17.5
Low 1.0 3.1 7.4
Average Cost, ¢lkWh
High 16.5 16.5 15.3
Low 7.1 7.1 7.5
Estimated Avoided Cost
11.2 11.2 13.2
(price to beat), C/kWh
February 23, 2001 60 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Notes and Sources:
Po[ice Station demand and annual energy use provided by City
Selemed distributed generation capacities are not optimized and are based on the judgement of MRW
"% Energy needs met" by distributed generation technologies for microturbine and fuel cell are based on the
judgement of MRW; photovoltaic based on average solar insulation in San Diego and a cell efficiency of 12%.
Investment is based on the high and Iow from Gas Research Institute. Solar includes 50% co-payment from the
California Energy Commission.
High and Iow fuel prices are based on the judgement of MRW. Conversion efficiencies based on the high and
Iow from Gas Research Institute
Operating costs from the high and Iow from Gas Research Institute. and include both fixed and variable O&M.
Investment recovered over 15 years at a 7% nominal discount rate.
Estimated Avoided cost based on SDG&E Schedule AL-TOU and 6c/kWh winter and 10¢/kVVh summer energy
charges. Avoided costs for the microturbine and fuel cell cases are lower than for PV because they avoid less
costly, off-peak power as well as peak power; PV tends to avoid primarily costly peak power.
February 23, 2001 61 MRW& Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Case Studies
· Portland (fuel cell). In 1999 the Columbia Boulevard wastewa~er treatment plant located
in Portland, Oregon installed a fuel cell that runs on wastewater digester gas, one of only
several such systems in the United States. A processor inside the fuel cell extracts
hydrogen from the digester gas, and the hydrogen then is used by the fuel ceil in generating
power. The power from the fuel cell is fed into the local electricity grid and is bought by
Portland General Electric. The fuel cell has a capacity of about 170 kW and generates up to
1,500 MWh per year (or enough energy to power more than 125 homes). Portland saves
approximately $60,000 per year in energy costs. The total cost of the system was $1.3
million. With the help of grants and subsidies, the City of Portland's out-of-pocket costs
were about US$750,000.27
· Los Angeles (fuel cell). The Los Angeles Department of Water and Power (LADWP)
plans to install a 250 kW fuel cell power plant at its downtown office building in early
2001 to test the technology's reliability and operating characteristics. This information will
enable LADWP to identify and implement .future fuel cell applications at both customer
sites and LADWP facilities. Detailed performance data are not available.
Los Angeles (photovoltaic). The Los Angeles Convention Center is now generating its
own power with solar panels designed to produce power on-site during peak demand
periods. The first phase of the project, a 120-kW system, was installed in time to provide
power for the Democratic National Convention. The system, which is comprised of more
than 2000 panels, is designed to blend with the Convention Center's architecture. Detailed
performance data are not available.
The Los Angeles Department of Water and Power designed the support structure and
installed the power system as part of a 1.8-MW contract with AstroPower. When the next
phase is completed, the Los Angeles Convention Center will be the largest solar-powered
facility in North America.
· San ,lose (small ¢ogen). As part of the city's Energy Management Program, the San Jose
Convention Center's 1500-kilowatt cogeneration facility went on-line in June 1990. The
facility supplies electricity, heat, and chilled water to the convention center and the
adjacent main library, and heat and chilled water to the adjacent 350-room Hilton Hotel.
The cogeneration system consists of a single natural-gas-fueled reciprocating engine-
generator, a 31 O-ton absorption chiller, and a heat exchanger for heating water.
On an annual basis, the cogeneration system saves approximately $480,000 in utility bills,
compared to the previous heating, ventilating, and air-conditioning system. It sells excess
electricity to PG&E during off-peak hours, producing additional revenue. The cogeneration
system paid for itself in 2.5 years, producing an attractive 40% return on investment.
Detailed performance data are not available.
27 See the ICLEI website for more information at www.iclei.org/mia98-99/portland.htm and the Oregon Office of
Energy website at www.energy.state.or.usPoiomass/FuelCell.htm.
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Future Outlook
Similar to Option 1 (building and operating a power plant), the future viability of a distributed
generation option depends in part on future power and gas prices because it is the differential
between purchasing power from SDG&E and generating power with distributed generation that
will determine the operating revenues for distributed generation. The use of solar photovoltaics
lessens this risk, as the cost of natural gas would no longer be a variable.
Legislative initiatives, both recently approved and proposed, could make significant amounts of
funding available for distributed generation projects in California. SB 5X, currently under
discussion, will make available $58.4 million for distributed generation projects. This spring the
CEC is expected to launch the "Solar Energy and Distributed Generation Grants Program" to
provide financial assistance for the development of distributed generation projects and to make
such projects cost-competitive with other generation resources.
Recommended Action
MRW recommends that the City monitor the distributed generation docket before the CPUC. In
the interim, the City can craft an RFP for scopin~ a distributed generator at city facilities to
determine a site with the best potential, considering over-the-fence, cogeneration, and renewable
energy opportunities. The RFP should not request detailed engineering specifications, but instead
should request firms to identify good candidate sites and technologies and provide estimates of
costs and benefits. Based on the work product resulting from the RFP and the outcome of the
CPUC's distributed generation proceeding, the City could then consider crafting an RFP to
actually install a distributed generation technology.
N~rt Steps
The City should monitor the distributed generation proceeding at the CPUC to know when a
decision is reached. The City should develop an RFP to release to potential candidate firms for a
scoping study on distributed generation. Finally, the Ci,ty should monitor program developments at
the CEC and CPUC to be prepared to take advantage of any funding or technical assistance that
may be made available as a result of legislation. This spring the CEC is expected to launch the
"Solar Energy and Distributed Generation Grants Program". No additional information on the
program is available from the CEC at this time.28
3.2 Renewable Energy and Energy Efficiency
Renewable energy and energy efficiency can play an important role in managing energy costs,
while also delivering environmental benefits such as reduced air pollution or lower carbon dioxide
emissions. Energy efficiency or "demand side" options differ from the supply side options
discussed elsewhere in this report in a number of ways. First, there is the fundamental difference
that these options reduce demand - either the City government's or the businesses'Residents' -
2s The City may wish to sign up for the CEC's Renewable Energy List Server to stay abreast of announcements related
to this grant program. See the CEC website at www.energy.ca.gov/renewables/sb 1345/index.html. In addition, the
CEC maintains a section on its website to post announcements and application guidelines for requests for
qualifications, funding programs, solicitations, and contract requests as these items are released (i.e., when an
announcement regarding the Solar Energy and Distributed Generations Grants Program is released, it will appear on
this page). See www.energy.ca.gov/contracts/index.html.
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rather than supplying power. This makes energy efficiency options generally less risky. They
provide a good hedge against volatile energy prices and do not rely upon state or federal policies
for their cost-effectiveness. While the benefits of energy efficiency would decrease with lower
power prices, many measures are cost-effective even at pre-summer 2000 electricity prices.
They are also different in that the savings associated with energy efficiency are diffuse and more
difficult to measure than the benefits (or costs) of generation supply options. For example,
increasing the energy efficiency of lighting throughout the City results in many kilowatt-hours of
savings, but those savings would be spread across numerous SDG&E accounts, which cover the
costs of electricity for uses other than lighting. Thus, identifying the savings requires more
engineering work and a certain amount of statistical analysis, rather than simply measuring the
output of a generator.
Energy efficiency policies can also take numerous forms, both internal t'o the City, addressing
municipal electricity use, and external, through zoning or other policies that encourage or mandate
certain energy efficiency measures or standards in non-municipal buildings within the City. This
section discusses the option of energy efficiency for city buildings and then energy efficiency
options for the broader Chula Vista community. Renewable electric generation sources, such as
photovoltaics, were discussed previously in the distributed generation section. Other rene~vable
energy options are discussed below in the context of energy efficiency.
Option 4: Promote Energy Efficiency in City Buildings
Regardless of what options the City chooses to pursue with respect to electric supply, it makes
good economic sense to pursue energy efficiency options wherever it is viable. The City can more
easily develop and implement energy efficiency programs for facilities it owns and operates than
any other option being presented in this report.
Cost/Pricing Issues
· Reduced energy bills. No matter what supply side option the City chooses, installing energy
efficiency technologies and processes will reduce energy bills. Depending upon how much has
already been saved through energy efficiency, upon the age of the major equipment stock in
city buildings, and the city's financial payback requirements, Chula Vista could save
potentially 10 percent ($100,000 per year) in electricity costs through energy efficiency.
· Reduced price risk. Consuming less energy, through investing in energy efficiency projects
effectively shifts costs from volatile utili .ty bills to up-front capital costs. As long as the project
is cost-effective at expected or lower-than-expected energy prices, energy efficiency provides a
simple and effective price hedge.
· Environmental benefits. Although all of the environmental benefits may not be experienced
locally in the City, reduced energy consumption -- natural gas as well as electricity -- will
result in less pollution from power plants. This also provides good public relations and sets a
good example for city businesses and industry.
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Case Studies
The City of Chula Vista already has its own history of implementing energy conservation projects
in city-owned and -operated facilities. For example, in response to the power price spikes this past
summer, the City Manager directed staff to implement energy conservation practices, such as
setting the thermostat to 74 degrees (as opposed to the standard 68 degrees) and turning off
equipment when not in use.
In addition, the City has been pursuing energy efficiency since long before this past summer's
power crisis and continues to work with SDG&E to evaluate energy efficiency opportunities for
city facilities and for the community. The ongoing efforts include evaluation of changing out
additional traffic signal lights from standard incandescent light bulbs to LEDs and participation in
SDG&E's "Savings by Design" program for new city facilities such as the new corporate yard. In
19.95 and 1996 the City replaced or retrofit all existing light fixtures in the Police Department, City
Hall, PSB, Fire Station #1, NIC, Parkway Community Center, the Civic Center Library, and other
city facilities with energy-efficient fixtures, lamps, ballasts, and sensors. In 1997 the City replaced
an existing 134-ton chiller with two 60-ton energy-efficient units. In 1998 the City replaced an
existing 500-gallon electric water heater and pump'with a small natural gas fired boiler system.
The project saves the City over $3,000 per year, based on pre-price spike electricity pfices.
The impact of the major City energy efficiency efforts are summarized in the table below. Over the
past eight years, the City has invested nearly $900,000 in energy efficiency, saving over two
million kilowatt-hours per year and having already recouped its initial investment.
Table 3.'7
Summary of Chula Vista's Major Energy Conservation Initiatives and Financial Benefits
Annual Savin.qs Year Savin,qs to Date
Project Cost (a) kWh Do ars (b) Installed kWh Dollars
Civic Center Library Chiller $290,000 321,000 $19,000 I 1993 I 2,568,000 $152,000
Project
Police Dept. Lighting Retrofit$8,429 92,569 $4,500 I 1993 I 740,552 $36,000
Lighting Retrofit Phase I $167,784 1,022,328 $103,508 1995 I 6,133,988 $621,048
Lighting Retrofit Phase II $67,334 352,044 $34,889 1996 1,760,220 $174,445
Police Dept. Chiller $126,886 487,467 $26,570 I 1997 1,949,868 $106,280
Replacement
Police Dept. Water Heater $12,000 18,000 $3,200 1998 54,000 $9,600
Replacement (c)
Retrofit Red Traffic Lights $206,065 (d) $120,000 I 1998 $360,000
TOTAL $878,498 2,293,408 $311,667 I 113,206,808 $1,459,373
Notes:
(a) Net cost to City, including incentives from SDG&E
(b) Savings based on pre-spike electricity costs
(c) Excludes the cost of incremental gas use.
(d) Savings not reported
Source:
Memorandum "Energy Savings* Report", Rick Matkin to David D. Rowlands, August 11, 2000.
The City of Portland provides another good example of the type of savings and other benefits a
city can achieve simply by targeting energy conservation in city facilities. Beginning in 1990,
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Portland implemented the "City Energy Challenge" program which had as its goal to cut annual
city electric bills by $1 million within ten years. By 1999, Portland was saving $1.1 million
annually as a result of energy conservation projects implemented throughout all departments and
facilities of the city government.
Pre-Feasibility Assessment
As noted in the case study section, Chula Vista has already made major investments in energy
efficiency. The feasibility of additional cost-effective energy efficiency projects depends upon the
remaining efficiency opportunities, which undoubtedly exist, as well as the financial cost-
effectiveness criteria used by the City to assess energy efficiency investments. Given the broad
nature of this report, MRW is not in a position to recommend specific projects. Nonetheless, the
following are potential areas to improve the City's energy efficiency:
· The construction of new buildings, major refurbishment, and the replacement of energy-
consuming equipment are the best times to invest in energy efficiency. As such, energy
efficiency should be part of the specifications in any request for bids on these items. For
example, bid specifications should:
require all equipment meet certain energy-efficiency standards such as being EnergyStar
compliant.
specify that the project exceed state energy codes by some reasonable amount, such as that
recommended in SDG&E's "Savings by Design" program.
have energy efficiency be part of the base bid, and not an add-on which can be cut without
thought of the long-term operating cost consequences.
· To maximize the savings from energy efficiency, the City budgeting process must be flexible
enough to allow for the tradeoff of capital expenditures with utility operating costs. Frequently,
projects that cost more to build, but cost significantly less to operate, are rejected because the
capital and operating budgets are strictly segregated.
· Data provided by the City indicates that street lighting is responsible for over 40% of the City
government's electricity usage and almost 30% of the City government's electricity bills. The
City should review its lighting strategies--when the lights are turned on and off, as well as
identifying where more efficient lamps (low pressure sodium) could be used.
· Chula Vista should continue to take advant~e of SDG&E's technical assistance and rebate
programs. This includes participating in the Standard Performance Contract program with an
Energy Service Provider. The ESP will scope out and install energy- and money-saving
measures, often at no cost to the city, in exchange for the utility rebate money.
· The City could consider specifying certain energy efficiency projects as part of an electricity
supply RFP. This will make it much more attractive, as the margins on energy efficiency
services are higher than commodity energy, eliciting more bids.
· Investigate installing energy management software systems in the major city buildings (e,g.,
police station, 361 F street, 389 Orange Street, 276 4t~ Avenue).
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Future Outloolt
Energy efficiency options generally are less risky than other supply-side energy investments. They
provide a good hedge against volatile energy prices and do not rely upon state or federal policies
for their cost-effectiveness. While the benefits of energy efficiency would decrease with lower
power prices, many measures are cost-effective even at pre-summer 2000 electricity prices.
Recommended Action
MRW recommends that the City aggressively pursue energy efficiency opportunities over the next
few months as the very best hedge against any potential crises this coming summer. One state
program the City may wish to investigate for financial assistance is the CEC's Energy Efficiency
Financing Program (EEFP). This program provides financing for the installation of energy-
efficiency measures, renewable technologies, and related feasibility studies. Local governments
can access up to $2 million per loan at the current interest rate of6%. A project must have a simple
pay back of seven years to qualify. The City also should hire a qualified engineering firm to
conduct a full energy audit of the City's facilities.
Next Steps
To ensure that maximum attention is given to implementing energy efficiency projects, the City
should designate a City employee as the person to coordinate all energy-related activities. This
person's responsibilities would be split between scoping and planning City projects and assisting
the economic development office in helping new businesses and home developments become more
energy efficient. Over the next several months this person could develop a City energy plan along
the lines of that developed by Portland, Oregon.
The City should also retain a qualified engineering firm to conduct a full energy audit of the City's
facilities. This can be done prior to the hiring or designating of a city energy efficiency
coordinator, or it could be the first task of the coordinator.
Option 5: Implement Conservation Programs for Businesses and Residents and Promote
Community Education
Because the initial capital outlay for energy efficiency and renewable energy projects is often a
barrier to investment, the City may wish to consider various options for facilitating investments in
energy efficiency and renewable energy. This section provides a brief overview of a number of
avenues the City can explore to increase private investment in this area, including:
· providing information to city residents and businesses
· providing added leverage to existing rebate, grant, or loan programs
· obtaining funding for new projects or programs
· identifying and using alternative financing vehicles
The City is already working in two ways to bring energy efficiency benefits to its residents and
businesses. First, it is working with developers to build energy-efficient homes by encouraging
them to participate in SDG&E programs such as "Comfortwise." The City is also reaching out
directly to its residents by preparing and distributing education materials for green power
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Confidential Final Repor~ Energy Management Options Assessment
purchasing, and by developing a near-term plan to distribute compact fluorescent bulbs and energy
conservation information to its residents.
The benefits to the City of supporting - financially and otherwise - these types of efforts include
the following:
· Residents and businesses have easier access to solutions for rising energy costs. Such
assistance may be a critical factor in convincing businesses where energy costs are a large
component of an operating budget to remain located within Chula Vista's limits.
· Energy efficiency efforts may lead to lower levels of air pollution and carbon dioxide
emissions over time as less electricity is generated to meet the City's needs.
· For businesses, energy efficiency may become a critical component of efforts to remain
competitive with businesses located in other states not facing soaring electricity or natural gas
costs.
Cost/Pricing Issues
The financial costs to the City of supporting energy efficiency measures outside of city facilities
will depend on the extent the City decides to fund such efforts. The costs of such programs may
seem more difficult to justify because energy efficiency assistance costs the city funds but delivers
the benefits to the residents. In other words, there is an outflow of funds with no corresponding
inflow of revenues or decline in operating budgets. However, it would be more appropriate to
consider the costs along side the benefits such programs provide. For example, if energy efficiency
assistance to a manufacturer made it possible for that firm to remain located in Chula Vista, the
City should consider the tax revenue associated with that firm as a benefit derived from its energy
efficiency expenditures.
In order to maximize the benefits of city participation, Chula Vista should:
· Build upon the existing SDG&E programs and leverage their effort. Possibilities include
offering small co-rebates and assisting in publicity.
· Publicize the City's own energy efficiency accomplishments. Publicizing the City's energy
efficiency and renewable projects provides a good example and shows skeptical building and
homeowners that energy-saving technologies work.
· Encourage or mandate higher-than-code energy-efficiency in new construction, via zoning
ordinances or by cooperative encouragement.
In addition to SDG&E's programs, both the federal and California state governments offer
incentive programs for businesses or individuals to invest in energy efficiency and renewable
generation technologies. The type and level of funding available depends on the program. Broadly
speaking, funding may be available in the form of rebates (for individual energy-saving
appliances), grants (used to subsidize appliance purchases, fund research, or spur investments in
efficiency projects), low-interest loans (to subsidize purchases and projects), or tax incentives.
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The City can leverage the funding from such state and federal programs by providing additional
subsidies. The City could, for example, provide matching funds for grant or rebate programs, or
further subsidize or capitalize loan programs (e.g., by establishing a separate revolving fund).
A limitation to this approach is that direct rebate, grant, and loan programs are relatively rare at the
state and federal level. (One exception is the California Small Business Energy Loan Program
administered by the California Energy Commission). Federal and state subsidies more often take
the form of tax incentives, with additional funds channeled toward assisting local governments or
utilities to administer locally-designed rebate, grant, and loan programs.
Table 3.8
Selected Utility, State and Federal Energy Efficiency Grant or Financing Programs
Sponsor I Program Description
SDG&E Savings By Design Offers design assistance and financial rebates for energy-
efficient new construction.
SDG&E Standard Performance Offers inceotives based on measurai~ie, verifiable kwh saved
Contracts basis. There are separate programs for large and small
commerciaI customers. The energy-efficiency project developer
need not be the site owner. In fact, third party, "Energy Service
Companies" implement the project and share the savings and
incentives with the cite owner.
SDG&E Residential Contractor Provides incentives to residential contractors to install energy-
Program efficient equipment in homes.
SDG&E Small Commercial For customers with one meter on SDG&E's Rate Schedule A
Turnkey Program (demand less than 20 kW). The pro~,-am promotes the
installation of multiple energy efficient measures by providing
an increase in rebate levels if more ~an one type of measure is
installed. Rebate levels are designed to discount a significant
portion of the cost of energy efficiency improvements.
California Energy Emerging Renewables The state has authorized $54 million to help install "emerging
Commission Buy-Down Program renewable technologies". Eligible technologies are:
· Small wind turbines of lO kilowatts or less
· fuel cells that convert renewable fuels such as landfill gas
into electricity
· solar electric power.
The Buy-Down Program will initiaiIy pay the lesser of fifty
percent of the system's cost or three dollars per watt for the
installation of equipment.
To receive the buy-down, systems must:
· primarily offset some or all of~e electricity used by the
consumer;
· have a full, five-year guarantee: and
· be installed by a licensed contractor, and
· be connected to local power lines.
Remote, self-contained systems that are not grid-connected do
not qualify.
The U.S. Urban Consortium Energy Provides both funding and technical assistance for initiatives
Department of Task Force (UCETF) that promote efficient energy use
Energy
California Energy California Small Business Provides low-interest loans to small businesses to install energy-
Commission Energy Loan Program efficient equipment
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Case Studies
Again, the City of Portland provides a good example of a city that is not a municipal utility
aggressively supporting the energy efficiency of its residents and businesses. In 1990 Portland set
the goal of increasing the energy efficiency of all the sectors in the city by 10%. The Portland
Energy Office involved numerous partners in working towards this goal, which eventually
involved over 30,000 households, businesses and non-profit organizations.
Portland significantly leveraged its funds. For ever?.' dollar the city spent, about $2.50 was raised
through agreements with state, federal and regional agencies or private corporations. Furthermore,
every dollar spent by the city resulted in more than $10 of phvate investment for improvements in
housing and small businesses.
Some of the highlights of the Portland effort include:
· Technical and financial assistance resulting in energy efficiency improvements in over 40
million square feet of commercial and industrial space.
· Nine percent reduction in per capita household energy use.
· Installation of a waste methane (landfill gas) fuel cell.
Future Outlook
Energy efficiency options generally are less risky than other supply-side energy investments. They
provide a good hedge against volatile energy prices and do not rely upon state or federal policies
for their cost-effectiveness. While the benefits of energy efficiency would decrease with lower
power prices, many measures are cost-effective even at pre-summer 2000 electricity prices.
Recommended Action
MRW recommends the City approach this option in two phases. In the first phase the City can
target low budget efforts aimed at providing the necessary assistance to help residents and
businesses manage their energy costs through this summer. In a second phase the City could
implement more aggressive programs that may require a larger budget commitment, more due
diligence, or a longer lead time for implementation.
Next Steps
If the City chooses to designate a "City energy manager'' to coordinate various energy-related
initiatives, this person should be made available as a resource to the business community. Other
steps to take now in preparation for a second phase include identifying and researching state and
federal assistance programs, and possibly contacting counterparts in Portland or other cities that
have successfully implemented financial assistance programs for energy conservation.
3.3 Electric Commodity Procurement Strategies
One of the key provisions of Assembly Bill 1890 is the ability of electricity users to purchase
power from entities other than their local utility. (Municipal utilities, irrigation districts or co-ops
were not required to allow their customers to purchase power from other entities but could choose
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Confidential Final Report Energy Management Options Assessment
tO do so voluntarily). This section discusses the options available to the City to purchase power
from parties other than SDG&E while avoiding the burdens of owning or operating its own power
plant. As will be discussed, in some circumstances this independent power procurement can extend
beyond the city government to include Chula Vista residents and businesses. The City does not
need to form a municipal utility to pursue the options discussed in this section.
Note: At the time that MRW was finalizing this report, the state Legislature passed AB IX and
Governor Davis signed the bill into law. AB 1X contains a provision that suspends retail choice
for California consumers. The provision states that the suspension will remain in effect until DWR
no longer supplies power under the terms of AB 1;( However, a bill (SB 2729 to amend this
provision is already in the works. The ability of the City to pursue this option will depend on the
outcome and language of the new bill.
Option 6i Contract with an ESP
An energy service provider (ESP) is an unregulated entity that sells electricity and other services to
end-users. An ESP typically purchases electricity, from power suppliers, rather than owning
generation plants. There are significant differences in the ways various ESPs are organizing and
positioning themselves in the marketplace, but most ESPs offer some combination of the following
services: energy commodity supply, load profiling, risk management, bill auditing and
consolidation, load aggregation, and energy use management.
The potential benefits of receiving power through an ESP include:
· Hedging market price risk. Many ESPs offer a specified rate for power rather than a price
linked to an index (previously, linked to the PX). This insulates the City from the volatility of
spot markets while allowing for more accurate budgeting. However. such an arrangement also
precludes the City from benefiting from prices falling below the contracted rate.
· Buying power more cheaply titan SDG&E: An ESP may be able to procure power more
cheaply than the prevailing wholesale market price and pass a portion of the savings on to the
City. An ESP may be able to achieve lower cost supplies by executing favorable long-term
deals with power suppliers or through superior purchasing transactions in the forward markets.
· Green power: Many consumers have sought out contracts with an ESP because of their desire
to be a consumer of environmentally friendly power, or "green" power. A contract with an ESP
can stipulate the resource mix underlying the supply of electricity. Given current tax
advantages granted to renewable power developers, green power can actually be slightly
cheaper than standard power, but this is not always the case.
· Improved metering technologies to increase price responsiveness. ESPs have the option, but
not obligation, to provide metering services along with commodity electricity. Potential meter
services that can be provided include "real-time" meters, whereby city engineers can see,
instantaneously, what the city's demand is and make adjustments according to the current
price. This would allow the city to reduce load (such as by cycling off chillers or electric water
heaters) at times of greatest prices.
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· Behind-the-meter technologies/improvements. Because the profit margins for ESPs tend to be
very small for the provision of commodity power, ESPs frequently also offer "behind-the-
meter" services to reduce or improve the customer's use of electricity. This includes not only
the improved metering technologies just mentioned, but also energy-efficiency services, such
as free audits and technical consulting.
Cost/Pricing Issues
ESPs will price their services in a variety of ways, with the goal of matching the pricing to the risk
profile and other needs of the customer. For example, an ESP may offer a price per kilowatt-hour
of electricity that is tied to a publicly available electricity price index. An ESP might also offer a
price that can float between a ceiling and a floor (this is known as a "collar"). Yet another pricing
option is a simple fixed price over the term of the contract.
In addition to ~onsidering the price structure of a contract with an ESP, the City must consider the
terms and conditions of any agreement. Penalties are a good example of how the consumer must
understand the terms of an agreement. The City should understand clearly the consequences of
using more or less power as compared to a baselin~ level. If the City wants the option of taking
20% more or 20% less power than stated in the agreement, then the ESP bears more risk and will
"charge" the City for that.
Financial Hedges. Hedging on energy purchases is an important tool for limiting risk and
exposure to high prices, no matter how power is purchased. Under California's current market
structure, the City can hedge on energy pumhases for city facilities by contracting with an ESP. If
the City chose to establish a municipal utility, then it should explore hedging options on behalf of
its customers. Either way, the City must tmderstand the hedging options available to it. The
following table lists and defines various types of financial hedging options.
Table 3.9
Financial Hedging Options
Fixed Pricing The buyer is guaranteed a unit price regardless of market fluctuations
Index Pricing ' The buyer is guaranteed transactions will occur at a level relative to
market prices
Pr[ce Cap The agreed unit price cannot exceed a predetermined limit, so the
buyer is protected against price spikes. The buyer pays market pr[ce
plus a small premium when the market price is below the
predetermined cap.
Price Floor This is usually bought by an energy producer, and guarantees that
the unit price cannot fall below a predetermined limit.
Index Minus Buyers receive a discount off market price in exchange for accepting
a price floor. When prices are above the floor, the buyer pays market
price less a discount. If prices drop below the floor, the buyer pays
the floor price.
Price Collar The customer benefits from a ceiling on the maximum hourly price,
but also accepts a floor on the minimum hourly price. The buyer is
protected against price spikes but cannot benefit from pdces that
drop below the floor.
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The terms and prices offered under hedging contracts will of course depend on market conditions.
From a buyer's perspective, an "index minus" contract makes little sense given current high prices
and volatility: a half a cent per kwh (a typical savings from an index) off of a very high price is
still a very high price. At the same time, "price cap" arrangements are unlikely given that caps
already exist for wholesale markers and prices have consistently run up against these caps. The
most promising types of hedges from Chula Vista's perspective would most likely involve fixed
price or price collar contracts, which sacrifice some downside risk for protection against upside
risk.
Despite the current volatility in California electricity markets, there may still be some downside
risk to hedging agreements. While high prices prevail now, most analysts believe they will decline
over the next few years as more generation comes online. Before signing a hedging agreement,
Chula Vista should carefully scrutinize terms relating to price and'contract length.
Pre-Feasibility Assessment
According to information provided by the City, about 45% of Chula Vista city government's
power purchases are subject to the current 6.5 cents per kwh energy component rate freeze
(primarily Rate Schedules A and street lighting), with the remaining 55% paying market prices via
SDG&E Schedule PX. At its worst in January 2001, the energy component of the City's power bill
will be on the order of $200,000 or about 18 cents per kWh. The current grave uncertainty in the
California power market makes it inadvisable to enter into a contract of any significant duration.
Future Outlook
The future outlook of this option hinges on the language and passage of SB 27X or a similar bill.
Having said that, ESPs have found it difficult to compete in California's restructured market,
primarily because they cannot beat the price of electricity offered to consumers by the incumbent
utility, and as a result most ESPs have exited the California market. The consumers that have
benefited from the emergence of £SPs in California are mostly large customers where the ESP can
secure a large-volume customer and possibly combine the service of providing electricity with
other "value-added" services. The city government's load from all of its meters should be large
enough to interest ESPs, if they return to the market and new legislation makes retail choice
possible again.
Recommended Action
MRW recommends that the City take a wait-and-see approach for this option. There is
considerable uncertainty in the short term in California's electricity market. Depending on the
outcome of various legislative initiatives currently under discussion, the City could then better
evaluate the risks and benefits of this option. The City should also monitor the progress of SB
27X.
Next Steps
The City may wish to hold some preliminary discussions with ESPs to get a better understanding
of the types of deals ESPs are willing to make given current market conditions.
February 23,2001 73 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Option 7: Pursue a Bilateral Agreement for Power Supply
An alternative to receiving power through an ESP as a retail customer would be to purchase power
directly. The City. could in theory become a scheduling coordinator and purchase power on the
open market, or somewhat more realistically, it could contract to purchase power directly with a
generator or a wholesale marketer. This type of arrangement is known as a bilateral contract or
agreement. The city need not form a municipa! utility to pursue this option, and it potentially offers
some of the price benefits of purchasing power through an ESP but without the value added
services. Bilateral agreements are more common among ve~' large industrial users with high load
factors and predictable loads.
Recommended Action
MRW recommends that the City take a ~wait-and-see approach for this option. There is
considerable uncertainty in the short term in California's electricity market. If the state Legislature
passes emergency power legislation, the City could then better evaluate the short term effects of
the legislation on the market. At that point, the City can evaluate the benefit of entering into a
bilateral agreement for power supplies.
N~rt Steps
The City should be open to discussions with power generators, such as owners of QFs, to
understand what types of agreements power generators may be willing to offer. Some power
generators ma)' be seeking long-term supply contracts to replace contracts they had with SCE or
PG&E, which are now withholding payments from suppliers.
Option 8: Municipal Aggregation
In the context of electricity markets, aggregation means consolidating or pooling numerous
individual purchasers of electricity into a single, large purchasing pool, thereby allowing the total
pool to be able to purchase energy on more favorable terms through competitive wholesale
markets than the individuals in the pool could on their own. Aggregation is one facet of energy
deregulation and basically permits someone other than the existing utility to perform the function
of buying power at wholesale and redistributing it at retail. The city need not form a municipal
utility to serve as an aggregator.
Municipal aggregation allows a municipality to procure electric power and related services on
behalf of the residents and businesses of their community. With a municipal aggregation program,
the city does not need to own any physical infrastructure that would be necessary for the
generation and distribution of electricity: SDG&E would be required to provide these services at
tariffed rates.
In general, a municipality can structure an aggregation program either on an "opt-out" basis,
wherein consumers are automatically enrolled in the program until they choose not to participate,
or an "opt-in" basis, whereby they choose to participate in the aggregation. However, AB 1890
instituted Section 366(d) of the Public Utilities Code to explicitly limit aggregation programs to
"opt-in." Since this requires written permission from every aggregation participant, it would be
difficult to achieve significant participation and may not be successful. Moreover, a competitive
February 23, 2001 74 MRW& Associates, Inc.
Confidential Final Report Energ.~ Management Options Assessment
supplier may decide the risks of supplying a municipality that may not deliver a large pool of
customers are too great. Thus, the municipality will attract fewer potential providers.
Even so, there are many potential benefits of municipal aggregation, most of which are related to
the increased buying power a large group has compared with many small, individual customers.
· Lower electricity costs. In general, an aggregation program should yield lower electricity costs
for the participants because as a group, the pool is more attractive to competitive suppliers. The
competitive supplier gets a larger volume "customer" that is concentrated in one geographic
area, that may contract for a longer period of time, and that offers a more attractive pattem of
usage (i.e., the load shape).
· Improvements in service and quality. Participants may benefit fi.om improved electric service
or customer service through an aggregation program because of the competitive pressures ~/
market brings to bear on the competing suppliers.
· Other non-price benefits. One of the most typic~l non-price benefits of aggregation programs
is an environmental benefit. A municipality has the option in setting the parameters of an
aggregation program to identify local preferences and build these into the aggregation
program. In the case of environmental preferences, the municipality could dete,'-:nine that
citizens desire access to green power and therefore stipulate that green power be a component
of the power supplied under the aggregation program.
· Reduced transaction costs. The costs to small consumers of seeking out and understanding the
available information on competitive electricity suppliers ma3' be too high and outweigh any
price or service benefits a competitive supplier can offer. As a municipal aggregator, the City
can reduce the transaction costs to small consumers by sorting through the available
information and making an informed choice on their behalf.
Cost/Pricing Issues
The primary cost of this option will be the expenses of implementation, such as issuing an RFP
and negotiating a contract with a supplier, and ongoing administrative management of a municipal
aggregation program.
Case Study
With the failure of its attempt to form a "muni-lite" in 199829, the City of Palm Springs entered
into a municipal aggregation program under the name of Palm Springs Energy Services. Palm
Springs first entered into a contract to provide retail electric service to the residents with First
Point Solutions, a subsidiary of Portland General Electric, which subsequently became a subsidiary
of Houston-based Enron Corp. Em:on subsequently opted to leave the program in May 1999, and
New West Energy, a subsidiary of Salt River Project of Phoenix, Arizona, then stepped in and
provided the back-office support to manage the program.
City of Palm Springs Energy Services saved customers nearly $88,000 in less than two years,
offering a two percent savings from that offered by the native utility, Southem California Edison.
29 See Option 9b.
February 23,2001 75 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
At its peak, Palm Springs Energy Services had signed up 1,358 residential customers (out of an
estimated 10,000 to 15,000 eligible customers). Unfortunately, as of Janua.D- 2001 Palm Springs
Energy Services suspended energy sales to its residential customers and transitioned them back to
Southern California Edison. The move to suspend sales was reported to be in response to recent
regulatory changes that make it impossible to bring customers any saxSngs, as New West
Energy/Palm Springs Energy Services' costs were significantly higher than the current SCE rate.
Future Outlook
Changes to the current regulatory structure are needed to make this option more attractive. It is
possible that as part of a power crisis settlement municipalities will be allowed to structure
programs on an opt-out basis. If this were the case, then this option would be much more
attractive.
Recommended Action
Considering the current "opt-in" requirements, which are too difficult to meet to justify the effort
needed to sign up customers one at a time, MRW believes this option to be something to consider
for the long term, or, if pursued now, a risky choi[e in terms of the cost'benefit trade-offs. As
illustrated in the Palm Springs attempt at municipal aggregation, if the retail rates become too far
out of line xvith the current market conditions, then the aggregation is likely to fall apart. If the
rates are too low, it would be difficult to acquire (and keep) a supplier. If the rates are too high, or
volatile, the customers would simply opt out and return to SDG&E service or an ESP.
If, however, the Legislature includes an "opt-out" municipal aggregation clause as part of a power
crisis bill or in separate legislation, then this option is worth investigation. It provides some of the
benefits of establishing a municipal utility, such as local decision-making and control, without the
financial risk to and outlay by the city.
Next Steps
One step the City could consider taking immediately is to lobby local representatives to allow
municipal aggregation programs with an "opt-out" structure. If such legislation were enacted, then
the City's next step would be to explore options with suppliers.
Option 8a: Other Aggregation Options
The City need not necessarily serve as the aggregator in order for its citizens or businesses to
benefit from aggregation. An alternative is "private" aggregation programs, whereby the
aggregation may be run by or through trade groups, membership organizations, chambers of
commerce, cooperatively owned businesses or by companies for their employees. While the City's
role in such an aggregation program would be minimal, it could assist in facilitating any
appropriate aggregation.
The City itself could join an aggregation group. SANDAG attempted to form an aggregation group
in 1998, and while the effort failed, the breakdown does not speak to the concept of aggregation in
general or preclude a successful aggregation with other area municipalities in the future.
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Confidential Final Report Energy Management Options Assessment
Case Study
Unlike SANDAG, which had a rocky experience as an aggregator, the Association of Bay Area
Govemments (ABAG) has been more successful. ABAG Power, the ABAG agency created to
aggregate Bay Area cities' loads, purchases energy on behalf of the ABAG members who have
opted into the program. For most of the last fiscal year (through October 2000), ABAG Power
would call energy providers monthly to commit power for the following month depending on
prices being offered. In most cases, prices quoted by the various generation providers were about
equal to the Califomia PX price plus the providers' administrative fee.
In July and August of 2000 ABAG Power entered into short-term agreements to purchase power
from Alameda Power and Telecom and the City of Palo Alto, two northem California municipal
utilities. At the end of August ABAG Power signed a contract to purchase electricity from Calpine
Corporation starting in September. This contract calls for power to be purchased at the fixed price
of $81.00/MWh through December 2001.
ABAG Power charges its members a fee to cover program expenses such as scheduling
coordination services, billing services, ABAG adm~mstratmn, etc. Dunng the first half of 1999, the
fee rate was set at 8% of the value of the purchases made; however, starting in December 1999 the
rate was lowered to 4%, with the intent of having an annual rate close to 6%.
Recommended Action
The City should review carefully any proposals for future aggregation such as that attempted by
SkNDAG or that successfully operated by ABAG.
IV~rt Steps
If the City is approached by a credible party attempting to form a municipal aggregation group, it
may be worth pursuing talks to further explore this option. Initiating a program itself should be
approached carefully, given the SANDAG experience.
3.4 Municipalization
The term "municipalization" or "municipal utility" may be applied to several different operating
structures or configurations. Each structure or configuration has its attendant benefits and burdens.
The most comprehensive structure will be addressed first, followed by the more narrowly focused
structures.
Option 9: Form a Vertically Integrated Municipal Utility
A vertically integrated municipal utility owns (or has contract rights to control) the physical plant
and facilities that (i) generate the electricity; (ii) transmit the electricity over transmission lines;
and (iii) distribute electricity over distribution lines. This type of municipal utility typically
provides electricity on an exclusive basis to the residents and businesses located in its jurisdiction.
Forming a vertically integrated municipal utility entails the greatest amount of capital and risk,
while providing the maximum flexibility and control over the operation and design of the entire
spectrum of electric services as well as the level of electricity rates.
February 23,2001 77 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
With regard to generating plants, the options available to the City are addressed in greater detail
elsewhere in the study. In summary, the City could ti) finance and own its own large-scale power
plant; (ii) partner with a third party to build and operate a power plant; or (iii) enter into long-term
contracts with a third party to obtain a source of generation.
Historically, a vertically integrated utility owned or controlled sufficient transmission assets to
deliver energy to its distribution system. With the advent of independent transmission system
operators (e.g., the ISO) and open and nondiscriminatory access to transmission lines under the
Federal Power Act, the need to construct, own and operate (or control through long-term contracts)
transmission facilities does not appear to be as compelling as it once was. On the other hand,
construction of additional transmission capacity, particularly to serve the San Diego area, has not
been accomplished under the ISO regime. Pending the outcome of the current special legislative
session to address the energy crisis, the need or wisdom of building and owning nece.ssary amounts
of transmission capacity may need to be revisited.
The heart of any vertically integrated utility is the distribution system. Chula Vista essentially has
two options with respect to an electric distribution system. One option is to build a new
distribution system that duplicates the existing system owned and operated by SDG&E under its
franchise agreement with the City. The second option is to purchase through a negotiated
agreement or obtain through condemnation the existing distribution system and associated
facilities. The first option would likely be prohibitively costly, while the second option raises the
potential for a protracted legal dispute with SDG&E. Depending upon developments in the
legislative arena and energy markets, there may, however, be incentive for SDG&E to enter into
some form of voluntary disposition or partnership with the City regarding the distribution system.
If condemnation did become necessary, there may be some advantage in condemning the
distribution system upon the expiration of the City's current franchise agreement with SDG&E
when the attendant value of that franchise may be diminished.
Cost/Price and Regulatory Issues
American Public Power Association (APPA), the non-profit trade group of municipal and co-
operative utilities, identifies the following as the steps needed to create a municipal utility3°:
1. Authorization by the local city council of a feagibility study by an engineering firm to
determine the extent and cost of building a new system or acquiring the facilities of the utility
that is currently serving the community. Such a study would take an estimated six months to
one year or more to complete. This study must be comprehensive and defensible, as it will
serve as the basis for how much the City would have to compensate SDG&E for the takeover
of their assets in Chula Vista, and will likely be a point of litigation between the City and
SDG&E. As such, Chula Vista could first conduct a rough estimate for purposes of advising
the City Council and administrator, to be followed, as appropriate, with the full study.
Although not likely to be a point of litigation, this study would also have to include for the
information of the City not only the cost of the distribution facilities but also vehicles,
equipment, and other supplies needed to run the utility.
3o The basic list is from APPA, with discussion from MRW.
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Confidential Final Report Energy Management Options Assessment
2. Analysis by the local government's attorney or special legal counsel of local, state and federal
laws pertaining to the creation of a new municipal utility. This effort could occur in parallel
with the engineering study.
3. Financial analysis of alternative methods of acquiring the present facilities or building new
ones. Some of this analysis could occur in parallel with the engineering and legal studies, but
could not be completed until both the engineering estimate of the acquisition co~ as well as the
regulatory issues are understood.
4. Communicating with consumers about the public ownership option, and organ/z/rig public and
political support. Forming a municipal utility to provide the full range of services requires the
support of the City's constituents. Their support cannot be taken for granted, particularly if
SDG&E opposes the municipalization and undertakes a public relations campaign oppgsing
the action.
5. Holding an election to determine if voters want a community-owned utility is mandatory in
some jurisdictions and optional in others. Under'state law. a charter city author/zed to provide
utility services is not required to subject the creation of municipal utility to a vote of the
people. However, some debt structures may require a vote of the people. In addition, any local
voting requirements under the City Charter would need to be satisfied. The City Attorney
advised MRW that the Chula Vista City Charter would allow the formation and operation of a
municipal utility without a public vote.
6. Issuance of bonds to permit the acquisition of present facilities or the construction of new ones.
Furthermore, the following would then be necessary for operation as a utility:
7. Using the bond proceeds to acquire the present facilities and construct any necessary new ones.
8. Hire and/or train the necessary personnel to operate as a utility, and acquire equipment to
maintain and operate the utility.
9. Acquire power to serve the utility. A municipal utility can either own its o~tn generation or
contract for power. The fundamental issues of owning generation are discussed in Options 1
and 2. The fundamental issues of acquiring wholesale power contracts are similar to those
discussed in Option 6. Vertically integrated pubic utilities are eligible for preferential access to
power generated at facilities owned by the federal govermnent.31 Note that a utility's
preference for lower cost federal power does not guarantee its availability, only that it is higher
on the queue for such power than for-profit entities.
In addition to these costs, the City must consider the financial ramifications of losing revenues
~ssociated with the franchise agreement and any property tax revenues associated with utility
facilities. All of these costs must be compared with the level of projected revenues the City can
realistically expect to earn by operating a vertically integrated municipal utility.
3~ The extent to which preference povJer is available to other configurations of municipal utility systems will be
addressed by legal counsel in a separate memorandum.
February 23, 2001 79 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
Municipal utilities enjoy certain advantages over the traditional investor-owned utility. For
example, they have preferential access to cheap federal hydropower, do not pay federal income
taxes, and can use lower-cost, tax-exempt bonds to pay for capital projects. On the other hand,
many municipal utilities have much higher debt levels than private utilities. Moreover, they are
often managed through city bodies that, because they must consider the communities' desires and
needs, react slowly to change. Finally, competitive markets are a risky environment: a municipal
utility that makes the ~wong decision, or is simply outsmarted by a competitor, will lose money.
Case Studies
According to APPA, during the last decade thirteen public power utilities were sold and nine new
ones were formed. On a base of more than 3,200 utilities nationwide, this does not represent much
movement in either direction. However, there has been an increase in the number of customers
served by public power because the new Long Island Power Authority (LIPA) is one of the lar. gest
public power utilities in the nation. Formed in 1986 as vehicle for coping with the liabilities
incurred by the failed Shoreham nuclear project, LIPA acquired distribution and generation
facilities and began full service at lowered rates to millions of Long Island customers in 1998.
Most of the municipal utilities in California were formed at the begirming of the 20th century to
provide electricity to cities not yet served by a private company. The most recent example in
California of a municipal utility being formed by a city previously served by a privately held
power company is Sacramento. Although the voters created SMUD in 1923, the District could start
operations only when it acquired funding and bought the distribution system from the then current
owner, PG&E. From 1923 to 1945, the "Sacramento Municipal Utility District" consisted of four
employees in offices at City Hall working to finance the District's operations and to acquire the
distribution system from PG&E. A series of bond sales in the 1930s accomplished the funding, but
PG&E did not want to sell its distribution system for the price set by the state regulators. In April,
1946, after 12 years of litigation, and 23 years from the time SMUD was "created," a California
Superior Court judge ordered PG&E to transfer title of Sacramento's electric distribution system to
SMUD for $13 million, and SMUD was in business. While this timeline was particularly long due
to the 12 years of litigation and the bond sales occurring during the Depression, it does illustrate
the dedication needed to form a vertically integrated municipal utility.
For the past ten years SMUD has been able to hold its electricity rates constant. SMUD's
residential customers currently pay 7.4 cents per kWh for the f'n'st 1,100 kWh consumed during the
winter season and 8.1 cents per kWh for the first 700 kWh consumed during the summer season.32
The recent high power prices and rising natural gas prices, however, have forced SMUD to
consider a rate increase. SMUD estimates it will need to increase rates by 16% to meet its revenue
requirements but that even after such a rate increase, SMUD customers will be paying 15% less
than PG&E customers.
Pre-Feasibility Assessment
A critical issue for Chula Vista and any other Califomia municipality considering forming a
vertically integrated utility is sources of power. Although municipal and other publicly owned
utilities typically have preferential access to lower cost federal power, its availability is not
n SMUD's average electricity rate (averaged across all customer classes) in 1999 was 8.4 cents per kWh. By
comparison, LADWP electricity consumers pay about 11 cents per kWh.
February 23,2001 80 MRW & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
guaranteed. Moreover, power from federal facilities are reallocated on a periodic basis. For
example, two of the nearest federal generating facilities are the Hoover Dam project and the
Parker-Davis project. The power from these facilities will be reallocated in 2014 and 2008,
respectively. Thus, it is possible that a new municipal utility ~vould be in a similar purchasing
situation as the investor-owned utility, with the large disadvantage of being inexperienced in
acquiring electricity contracts and resources.
The current activity in the Legislature could change this outlook. A major component of the
proposed electricity reform bill currently being considered is the formation of a state-owned
generation authority. The exact responsibility and powers of this agency have not been determined.
However, it is possible that newly formed municipalities could be granted preferential access to
whatever lower-cost power this agency might acquire.
Recommended A ~tion
MRW recommends that the City consider conducting a pre-feasibility study on the approximate
cost to acquire or construct the necessary facilities and resources and identify and address legal
and regulatory obstacles that would need to be resolved if full-scale municipalization were to be
pursued.
Nert Steps
An immediate step the City should take is to lobby state representatives on the issue of granting
newly formed municipal utilities preferential access to any power moved through a state Power
Authority, if one is created as part of the Davis administration's initiatives on the state power
crisis. If the City wants to pursue creation of a vertically integrated municipal utility as an option,
the City should authorize and issue an RFP to conduct pre-feasibility studies on the rough cost to
acquire the necessary facilities and resources and the legal and regulatory challenges associated
with such an plan.
Option 9a: Form A Municipal "Distribution-Only" Utility
By forming a municipal distribution-only utility, the City could implement a slightly less
comprehensive version of a municipal utility, while preserving many of the benefits of a vertically
integrated utility. Such a plan would require the City to acquire or construct its own distribution
system. The benefits and burdens of establishing its own distribution system are discussed above.
A municipal "distribution-only" utility would be eligible to procure wholesale power on the open
market through either long- or short-term contracts, thereby obviating the need to construct and
own generating facilities. It would also have the fight to use the ISO transmission system similar to
that of other utilities (e.g., SDI3&E). If power was purchased outside the state, a municipal
"distribution-only" utility could utilize any existing surplus transmission capacity to deliver power
purchased by the municipal "distribution-only" utility.
Case Studies
Two examples of recently-formed municipal distribution utilities are the Lassen Municipal
Utilities District (LMUD) and the Pittsburg Power Company formed by the City of Pittsburg.
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Confidential Final Repor~ Energy Management Options Assessment
Headquartered in Susanville, a small city north of Lake Tahoe, LMUD services I0,000 generally
rural customers in northwestern California. Its constituents voted for its formation in November
1986, and the utility was formed in 1988 when it purchased the local assets of CP National. The
utility has relied on a long-term contract with PG&E for power supply until last year. Since then,
rising wholesale power costs have led to significant rate increases for LMUD customers,
demonstrating the importance of cost-effective supply arrangements for this type of distribution-
only utility.
Similarly, the City of Pittsburg formed the Pittsburg Power Company to handle distribution of
power to the former defense facility at Mare Island. Operation of the Mare Island facilities has
been contracted out to a unit of Sempra Energy, reducing the administrative burden on PPC. With
acquisition of the Mare Island facilities, PPC also obtained a small allocation of.federal WAPA
power earmarked for Department of Defense facilities, assuring a base supply o,f low-cost power
that continues to make the Mare Island operation self-sufficient.
Option 9b: Form A "Muni-Lite' Utility
Chula Vista may not need to acquire all of SDG&E's distribution equipment within the City in
order to avail itself of many of the benefits of a municipal distribution utility. Federal law may
permit a city to acquire substantially less than an entire distribution system and yet be eligible for
certain federal rights and privileges. If allowable, this would permit the City to receive some of the
major purchasing and transmission advantages of being a municipal utility without the full outlay
of capital needed to acquire SDG&E's distribution assets and without having to develop the
expertise needed to maintain the assets.
Case Study
In 1996, the City of Palm Springs submitted to FERC (who regulates wholesale power
transactions) a "muni-lite" proposal. The Palm Springs proposal was rejected by FERC on the
grounds that it violated the National Energy Policy Act of 1992 as well as conflicts with the
CPUC's effort to deregulate power markets. More recently, the Laguna Irrigation District
submitted a "muni-lite" proposal not significantly greater in scope and cost than that proposed by
Palm Springs. Although Laguna Irrigation District obtained an initial ruling by FERC that was
favorable, investor-owned utilities requested that FERC reconsider its decision. To date, FERC has
not made any final ruling on the case.
Option 9c: Form A Municipal "Generation-Only" Utility
Another structure of a municipal utility could entail the acquisition of generating assets to provide
power to the City's residents and businesses. The City could (i) finance and own its own large-
scale power plant; (ii) partner with a third party to build and operate a power plant; or (iii) enter
into long-term contracts with a third party to obtain a source of generation. Under this structure of
a municipal utility, the City need not acquire transmission or distribution assets. In essence, the
City's municipal "generation-only" utility would become an ESP that could provide power to retail
customers under the retail competition regime of AB1890. Recent changes in the law (AB 1X)
suspending the ability of retail customers to select alternative ESPs would prevent the City from
pursuing this option until retail competition is restored.
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Confidential Final Report Energy Management Options Assessment
The presence of the South Bay facility may make a generation-only municipal utility option more
attractive or feasible for Chula Vista. However, current state law prevents the city from reselling
power and may in fact prevent use of the power directly by the City. Since retail access is currently
under consideration in the legislative special session, action beyond preliminary discussions with
the South Bay operator should await legislative action.
Option 9d: Declare the Formation of a Municipal Utiliv,.'
The least-cost alternative of creating a municipal utility is to declare the creation of a municipal
utility without investing in any capital assets or entering into any power-related contracts. Such a
course of action may have limited, if any, tangible benefits under current law. On the other hand,
such a declaration is the logical and political first step to creating any of the more substantive
forms of a municipal utility as described above. Moreover, declaring the creation of a municipal
utility would enable the City to argue that any benefits or programs made available to mufiicipal
utilities under subsequent State or federal legislation should be afforded to the City. The success of
such a position would involve the definition of a "municipal utility" under any relevant legislation.
The City of San Marcos, California, has announced the establishment of a municipal utility, but
has yet to take any additional steps. San Francisco, California. has publicly announced that it is
investigating forming a municipal utility.
3.5 Emissions Offsets Trading (Option 10)
Emission reduction credits are created when reductions in emissions from stationary or mobile
sources exceed the reductions required by local, state and federal laws. These emission reduction
credits can be used to offset emission increases by power plants or various industries. Typically
emission reduction credits have been obtained from stationary industrial sources. However,
obtaining emission reduction credits from mobile sources has become more common and funding
to do so is also available. Since the CiD' does not have a major stationary source of pollution from
which to derive emission reduction credits, looking at mobile sources is a more viable option.
Emission Reduction Credit Programs
In 1993 the California Air Resources Board (ARB) developed guidelines for the development and
implementation of mobile source emission reduction credit programs. The ARB lists six different
programs to obtain mobile source emission reduction credits:
· accelerated retirement of vehicles
· purchase of low-emission transit buses
· purchase of zero-emission vehicles
· low-emission retrofit of light and medium-duty vehicles
· low-emission retrofit ofheaw-duty vehicles
· purchase of new reduced-emission heavy-duty vehicles.
Table 3.7 lists the cost and expected life of credits ass,ociated with the programs mentioned above.
However, if Chula Vista would like to use the emission reduction credits to offset an emission
increase at a stationary source such as new power plant, it would have to obtain emission reduction
credits for the life of the power plant. As can be seen by Table 1, the expected life of emission
February 23,2001 83 MR W & Associates, Inc.
Confidential Final Report Energy Management Options Assessment
reduction credits from these programs ranges from 3 to 12 years. The life of a power plant is 30
years.
Table 3.10
Number of Vehicles Needed to Generate 25 Tons per Year of Emission Reduction
Credits in 1993
Approximate Number of
Emission Reduction Vehicles Needed Approximate Cost Expected Life
Credit Program I of Credits
ROGI NOx
Accelerated 440 $350,000
Retirement of Old 3 Years
CarsB 1,700 $1.3 Million
Low-emission $1.9 Million to
Transit Buses NCc ' 50 $3.5 Million^'° 12 Years
(Methanol M 100)
Low-emission $400,000 to
Transit Buses NCc 50 $2.2 Million^'° 12 Years
(CNG)
Electric Transit NCc 25 NC~ 18 Years
Buses
Zero-emission 3,800 3,800 NCr 10 Years
Vehicles~
Light- and Medium- Duty 4,200u 4,200}~ NC[ 10 Yearsn
Retrofitu
Heavy-Duty Retrofit~ I NC}~ 58 NC~ 3
Yearsj
The San Diego Air Pollution Control District in conjunction with the Environmental Protection
Agency and ARB has developed an alternative program that extends the life of emission reduction
credits that became effective September 8, 2000. The program is called Alternative Mobile
Emission Reduction Credits for Medium and Heavy-Duty Diesel Powered Vehicles and
Repowering of Marine Vessels Under Rule 27 (C 16). This program extends the life of an emission
reduction credit by discounting it over a 30-year period. For example, instead of obtaining an
emission reduction credit of 3 tons for 10 years, a 1 ton credit for 30 years can be obtained. This
program applies to replacing refuse vehicles that will utilize natural gas and trucks that will utilize
low emission diesel or natural gas and repowering marine vessels with low emission diesel. An
example of this program is described in the case study below. San Diego Air Pollution Control
District is open to establishing other alternative programs, but they must meet all local, state and
federal requirements.
Case Study
In September 2000 PG&E National Energy Group (PG&E NEG) and Waste Management Inc.
announced a groundbreaking program to manage air pollution in San Diego County. Under the
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agreement Waste Management will replace 120 of its diesel-fueled refuse collection trucks with
natural-gas burning trucks. The use of natural gas vehicles instead of diesel trucks will cut
emissions of nitrogen oxide by more than half for the Waste Management fleet. The emissions
credits resulting from the lower emissions will be used by PG&E NEG as an offset to emissions
from its proposed power plant at Otay Mesa. This program is one of the first in the United States to
use emission reduction credits from a mobile source to offset emissions from a stationary source.
Funding
The Governor's budget has allocated $50 million to the Carl Moyer Program through the 2000-
2001 fiscal year which gives incentives for cleaner heavy-duty engines. This program gives grants
to cover the incremental cost of cleaner on-road, off-road, marine, locomotive and stationary.
agricultural pump engines, as well as forklifts and airport ground support equipment. For example,
a company may ~be able to buy a new truck for $100,000, which meets the state's minimum
emission standards, or buy a lower-emission truck for $125,000. The offsetting cost ($25,000) is
available through the Moyer Program in order to 'buy the lower-emission truck. The funding
allocation for San Diego Air Pollution Control District for 2000/2001 is $1,850,344. Over the past
two years the amount of funding requested in this' program has been exceeded. The RFPs are
issued biennially and usually in May of even-numbered years.
Recommended Action
MRW is not familiar with the types of vehicles currently owned and operated by the City, but this
could be a promising option to pursue as an environmental program. The City will need to weigh
the costs and benefits of any program that could lead to increased natural gas consumption.
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CHAPTER 4
CONCLUSIONS AND RECOMMENDATIONS
Assessing options in an environment as fluid as today's Califomia electric indu~-a-y is
challegning. Near-daily announcements by various agencies of new initiatives and proposals and
the numerous other electricity market twists and tums Californians have encountered in just the
two months, not to mention in the past year, are unprecedented in this formerly staid
past
industry. This challenge, however, illustrates perhaps one of the most important conclusions of
this study: Chula Vista would be prudent to pursue some options, which will likely provide
benefits under a wide range of future developments, while taking a go-slow approach to other
options until the market situation settles down.
4.1 Recommended Actions
4.1.1 Highly Recommended Options to Pursue
Clearly, the City needs to respond to the immediate situation of escalating energy costs, which
threaten the local business community and residents. For this reason, MRW recommends the
City pursue three options we have identified as providing immediate benefits and which are low-
cost, low-risk choices:
Highly Recommended Energy conser~'ation projects in city. facilities will
provide the best and most immediate protection
· Pursue energy efficiency against unreasonable energy prices, particularly as
projects in city facilities the summer season approaches.
· Encourage energy efficiency · Because energy efficiency projects will provide
programs for businesses and benefits to the City regardless of the outcome of
residents and promote market reforms and other state or federal actions,
community education
this is a low risk option to pursue.
· Contract with an ESP for City
needs as permitted by law · Current high prices of electrici~' make the pavbacks
on energy, efficiency projects very attractive, so
capital investments face minimal risk and v,511 have
short paybacks.
· Legislative initiatives will make millions of dollars of funding available to lower the
financial costs of energy conservation. Again, funding assistance reduces the City's risk of
pursuing energy efficiency options.
The City should continue its efforts to promote conservation programs for businesses and
residents.
· Making information on the power crisis readily available and supporting energy conservation
or other energy management efforts may be a critical factor in convincing businesses where
energy costs are a large component of an operating budget to remain located in Chula Vista
and will help businesses remain competitive over the short run. However, the benefits of such
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programs may be difficult to measure in strict cost-benefit terms. Moreover, although the
administration of business-related support programs can probably be folded into current
business development efforts, there will still be some additional costs to the City without an
immediate financial benefit to the City's budget. In the long term, there could be a beneficial
impact on City tax revenues if businesses remain or expand in Chula Vista.
· As part of the state response to current electricity market problems, increased funding for
promotion of conservation options is likely to become available. The City should assist
residents in availing themselves of these opportunities as they become available and existing
programs as they are accelerated. Similar to business-related efforts, the financial benefits to
the City of such efforts will be difficult to measure vis-h-vis the direct costs.
Chula Vista should lobby elected officials to enact SB 27X or similar legislation to lift the
suspension on retail customer chbice.
· About 55% of the City government's power purchases are bought at market rates, which
could produce a bill for January service of as much as $200,000. A contract with an ESP
might provide electricity more cheaply than taking service from SDG&E. There is some risk
that if market conditions improve in the next 1-3 years, a long-term commitment to an ESP
~iI1 burden the City with higher cost electricity.
· The City should monitor legislation related .to retail choice and seek changes that provide
benefits to public agencies such as the City.
4.1.2 Promising Options to Consider
MRW characterizes a second group of options as those that could provide significant benefits but
wb2ch require additional evaluation. The City should avoid committing itself to an option that
entails more risk than the three above options without further analysis. In addition, the outcome
of some regulatory proceedings and legislation
currently under consideration could change the Promising
outlook for some of these options. These options also
typically require a longer lead time for preparation · Install distributed generation to
and thus cannot offer'the City immediate benefits, serve City load
· Partner with third party to build
The City should explore installing distributed
generation to serve a portion of the City's load. and operate plant
· Facilitate investment in energy
· Because distributed generation can be efficiency and renewable energy
accomplished with a low capital investment · Pursue bilateraI agreement for
relative to large-scale power plants, the financial
risk to the City of this option is more manageable power supply, possibly in
than pursuing the development of a City-financed cooperation with state efforts
power plant. · Develop and trade emissions
offsets
· Current and proposed funding and incentive
programs that are available for distributed
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generation projects enhance the attractiveness of this option vis-h-vis other options. In
particular, the Legislature's Special Session could lead to new funding for distributed
generation and potentially an easing of regulatory and market ban'iers to distributed
generation.
· In terms of downside risk, there is some risk the CPUC will rule in favor of the utilities'
position on distribution stranded costs or other issues which could limit the financial
attractiveness of distributed generation.
Chula Vista could pursue a bilateral agreement for power supply.
· The City could choose to purchase power directly from a power supplier, taking on the role
of ESP as an alternative to contracting with a third-party ESP. However, pursuing this option
at this time could lead to the City locking itself into a power supply contract at a price that
will be above market prices in a more stable electricity market. In addition, the City may be
able to pursue other options, such as forming a municipal utility, which would give it access
to lower-cost power from DWR. -
Chula Vista could opt to partner with a third party to build and operate a power plant.
· A partnership can be structured in numerous ways to share the risks and benefits of
development and operation and to leverage what each party brings to the table.
· Proposed legislation may expedite the licensing and permitting process for new power plants
(primarily peaking plants) and for the repowefing of existing power plants. Because this
legislation ~11 likely have sunset provisions (i.e., dates upon which they expire), the next
one to three 3'ears may provide an ideal window to push through the development and siting
of a power plant.
· At the same time, other legislation may reduce the attractiveness of owning or sharing in the
development of a power plant. For example, legislation, if passed, may require the owner of a
power plant to sell its electricity only to in-state customers, limiting the potential market for
the plant's output. A more draconian measure proposed in new legislation would make any
owner of a power generation facility a public utility subject to the jurisdiction of the CPUC
(although the legal validity of such legislation is uncertain).
· Finally, California's electricity market structure is still in a state of flux and there is
considerable uncertainty as to how the market will operate in the future. This regulatory
uncertainty is significant.
As an extension of current efforts in this area, the City may wish to explore programs and
policies to facilitate additional private investment in energy efficiency and renewable
energy.
· This option may include providing matching funds for grant or rebate programs or
subsidizing or capitalizing loan programs by establishing a revolving fund.
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The City should investigate trading emissions credits if it plans a major capital investment
in its vehicle fleet.
· The City should determine the extent to which DENA may need assistance in acquiring
emissions offsets for an upgraded South Bay plant. If the City plans a major capital
investment in its vehicle fleet and is willing to consider alternative fuel vehicles, it may be
able to leverage that investment by creating an emissions offset partnership with'DENA. This
option targets a very specific niche opportunity, so its viability and potential payback to the
City require additional evaluation before this option is pursued.
4.1.3 Higher Risk Options
Finally, MRW identified three higher risk options the City may wish to pursue. These options are
characterized by the greater level of risk associated with each option and the financi'al,
regulatory, technical, and administrative requirements the
Higher Risk City would have to undertake to pursue these options.
The City will, need to tmdertake substantial due diligence
· Finance, own, and operate
large-scale power plant on any one of these efforts before going forward.
Never~heless, options in this category could provide
· Form a municipal utility substantial benefits, pozticularly if market conditions
· Pursue municipal warrant taking aggressive action. In addition, there may
aggregation as permitted by be low-cost or low-risk first steps that can be taken now
law to pursue these options.
The City could finance, own, and operate a large-scale
power plant to meet a portion of the City's demand for electricity. As mentioned above,
there are both potential upsides and downsides to this option depending on what legislation
is passed by the Legislature. The difference between this option and the option of
partnering with a developer to build a power plant is that the City is'the sole entity bearing
all of the risk.
· The City gains some protection from high wholesale electricity prices, a potential source of
revenues if excess power is sold into the open market, and improved local electric reliability.
· The high initial capital investment - estin~ated to range from $50 to $90 million - makes this
a fairly risky option. Moreover, a gas-fired plant would generate electricity for 10 to 12 cents
per kWh at current natural gas prices, higher than the 6.9 cents per kWh at which DWR is
seeking to purchase power.
· There are almost no examples of a municipal-owned large-scale power plant if the
municipality does not have a municipal utilits,, another indication of the risk involved in this
option.
· Siting, building, and operating a large-scale power plant requires specialized expertise and
the negotiation of numerous regulatory hurdles.
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· A long-term market outlook suggest wholesale power prices will decline; this would put at
risk the plant's financial viability.
The City could form a municipal utility.. As discussed in Section 3.4, there are several
different forms the municipal utility could take. A vertically integrated utility, is the highest
risk approach, but it provides the CIV.- with the greatest degree of control. A distribution-
only municipal utility or a munMite approach involve less risk with some trade-offs in
terms of operational control and flexibility and potential benefits to residents, businesses,
and the City itself.
· Because a municipal utility has preferential access to cheap federal hydropower, it may have
a cost advantage over an investor-oxx-ned utility in terms of costs of energy. However, federal
sources of power are not guaranteed to be available. A new state power authorit?', or DWR,
may be a new source of lower~cost energy, but these sources of power may not e.'dst over the
very long term. Thus, how a City municipal utility sources its power is a key component to
the likely success of a municipal utili~-.
· A municipal utility may also enjoy cost advantages over traditional utilites because it does
not pay federal income taxes and it has access to low-cost financing for capital projects.
· A municipal utility, may be able to provide distribution services at a lower cost than the
incumbent utility. However, distribution costs are not driving retail electric bill increases.
· The structure of California's electricity market is in flux, making the long-term outlook for a
municipal utility uncertain.
Chula Vista could procure electriciV.' on behalf of the residents and businesses under a
municipal aggregation program.
· To the extent that current law preventing a city from administering a municipal aggregation
on an opt-out basis remains in force, this option is likely to entail administrative and financial
risks to the City with the potential for only minimal returns. Currently, municipal aggregation
programs in California must be done on an "opt-in" basis, a regulatory requirement that has
limited the effectiveness of such progams.
· However, there is legislation currently under discussion to change this provision and allow
municipal aggregation programs to be done on an "opt-out" basis. If there is a change in the
law, this option is more promising in terms of the potential benefits such a program could
provide to Chula Vista's residents and businesses.
4.2 Next Steps
MRW compiled the following list of next steps to guide the City in its implementation of the
various options discussed in this report.
1. Develop a City Energy Plan that integrates energy management objectives into business
development activities, residential programs, community education efforts, arid the planning
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and operation activities related to city facilities. This could best be accomplished by hiring or
designating a city employee to coordinate energy management planning and activities.
· The designated energy manager could scope out energy conservation projects and serve
as a resource to the local business community.
· The designated energy manager could coordinate with other city offices that serve the
residential community and with representatives of SDG&E and the CEC to ensure that
Chula Vista's residents are made aware of their energy conservation options and the
financial assistance programs that exist to assist them.
· The designated energy manager could advocate for larger energy projects such as an
over-the-fence generation project in conjunction with an industrial development project.
· The designated energy manager should have the responsibility to interact with the CFC
on as needed basis to track the development of incentive programs and to manage the
City's participation in such programs.
2. Develop a legislative strategy that embodies the City's goals in such key areas as
environmental protection, electricity supply costs, transmission reliability, natural gas supply
and availability, and power plant siting. Lobby state legislators and monitor regulatory policy
developments at the CPUC.
· Monitor outcome of the distributed generation proceeding currently before the CPUC.
· Lobby elected officials to repeaI the provision in AB 1X that suspends customer choice
and to pass a favorable bill for customer choice (SB 27X, AB 48X, or similar one). This
effort could also advocate legislative language to make municipal aggregation programs
available on an "opt-out" basis.
· Work with local legislators to shape state policies affecting the structure of the state
electricity market, including mechanisms allowing public agencies such as the CiD' to
participate in state power supply programs.
3. Issue an RFP for a distributed generation feasibility study.
· The RFP should request bidders to identify favorable sites and preferred technologies as
well as cost estimates.
· Track the expected release of a distributed generation grant program from the CEC in the
spring.
4. Continue to explore opportunities associated with DENA and the South Bay power plant
modernization.
5. Consider conducting a feasibility study on the approximate cost and legal and regulatory
requirements of various forms of municipalization. As_a first step, the City could create a
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municipal utility as a separate administrative entity. This entity then could oversee the
process for completing a feasibility study as its first order of business.
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APPENDIX A
GLOSSARY OF TERMS
Aggregator: An agent or broker that organizes customers into a group to purchase natural gas or
electricity services on the group's behalf. It purchases the natural gas or electricity as a single customer
for the group. By grouping many customers into one large customer, the aggregator typicalIy has more
bargaining power to secure a lower rate for the group.
Ancillary Services: The services provided from generation resources, other than scheduled energy'
production, which are required to maintain system reliabili¢' and meet WSCC/NERC operating criteria.
Such services include spinning reserves, non-spinning reserves, replacement reserves, regulation
(automatic generation control or "AGC"), and voltage control and black start capability. These services.
and any additional energy associated with them, can be self-provided by Load Serving Entities (LSE) on
behalf of their customers.
Bilateral Transaction: A transaction between two willing parties xvho reach an agreement under
negotiated or standardized terms. For example, the sale, gl electricity from a merchant power plant or
power marketer to a utility, a direct access retail customer, or other large wholesale customer often takes
the form of a bilateral transaction.
British thermal unit (Btu): Equal to the amount of heat required to raise the temperature of one pound of
water by one degree Fahrenheit at sea level. This term is used to compare the heating values of different
fuels.
Capacity.: An amount of electricity that would be available from a generating unit, utility, or system or
the transportation volume of natural gas pipelines. Capacity is valued in units of energy such as
megawatts for electrical power or cubic feet for natural gas.
Collar: A contract with a price collar specifies a maximum and minimum price for the commodity being
traded. A collar guarantees the buyer will not have to pay more than the maximum price and the seller is
assured of receiving a price no less than the minimum price.
CPUC: California Public Utilities Commission, the regulatory arm of the State of Califomia which
oversees the retail operations of public utilities as defined by law.
Day-Ahead Market: The forward markets operated for the supply of electrical power and Ancillary
Services at least 24 hours before delivery to wholesale buyers and/or retail consumers.
Demand Side Management (DSM): Measures or programs undertaken by a utility or consumer designed
to influence the level or timing of energy consumption in order to optimize the use of available suppl.,-
resources, thus allowing suppliers to defer the purchase of additional power.
Direct Access: Customer choice in the area of power supply. California's Direct Access program allows'
customers to purchase power from entities other than the traditional public utility (thus ending the
monopoly provision of energy) but maintains monopoly transmission and distribution services from the
public utilities.
Distribution: The delivery of electricity and natural gas to homes and businesses through the necessary
wires and pipeline systems. This segment of the electric and natural gas utility industry has not been
opened to competition and continues to be regulated by state governments.
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Energy Service Providers (ESPs): A business that provides services such as installing energy-efficient
products and other demand-side management measures in facilities, faciliD management, project
management, billing services, and also energy commodity buying services to retail customers. A company
offering specialized or customized energy seFvices by providing advice and products to reduce customer
consumption and bills.
FERC: Federal Energy Regulatory Commission, a regulatory arm of the federal government which
oversees transmission services and sales of power for resale as part of interstate commerce.
Generation: The process of converting various forms of energy into electricity. The amount of energy
produced is expressed in watt-hours. Generation is the only part of the electric industry that has been
opened to competition.
Hour-Ahead Market: The market is operated to provide energy and/or Ancilla.D. Services for scheduling
with the ISO l-hour before delivery.
Independent Power Producer (IPP): A generic term to describe non-utility owned power producers.
The term is synonymous ~vith merchant generators, cogenerator, non-utility generator, private po~ver
producer, Qualifying Facility (QF), and exempt wholesale generator (EWG).
California Independent System Operator (CAISO): A non-profit entity es:ablished by AB I890 to
operate the transmission system in a safe reliable manner. The CAISO does not own the transmission
system, but was established to eliminate the possibility that the utility owners would discriminate in
access to the transmission system in favor of retained generation or affiliated companies.
Interconnection: The point at which the generation facility connects to the transmission or distribution
lines, lnterconnection facilities are typically constructed to the utility's specifications at the expense of the
generator or customer.
Investor-Owned Utility (IOU): A public utility entity providing retail services whose assets are owned
by investors. Examples include Pacific Gas & Electric Company ("PG&E"), Southern California Edison
Company ("SCE") and San Diego Gas & Electric Company ("SDG&E"). IOUs are distinct from other
forms of utility companies such as irrigation districts and municipal utilities. IOU retail services are
regulated by the CPUC.
Kilowatt (kW): A measure of electric energy during a preset time. A kilowatt equals 1,000 watts.
Kilowatt-hour (kWh): The standard unit of measure for electricity consumption. One kilowatt-hour is
equivalent to using 1,000 watts of power over a one-hour period.
Load: A generic term typically describing an operating machine or other source of power consumption.
Interconnected load imposes demand on the electric system when it operates.
Load Serving Entities (LSE): Public utilities, electric service providers, marketers or aggregators who
provide electric power to consumers.
Local Publicly Owned Electric Utilities: A municipal corporation, a mfinicipal utility district, an
irrigation district, an electric cooperative or a joint power authority (which can include one or more of the
agencies listed above) furnishing electric services over its own transmission or distribution facilities.
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Long-Term Fixed Price Contract: A bilateral transaction xvith a term that often extends for a significant
period at a predetermined price. For example, a long-term fixed price contract may run for 1 year, 5 years,
or 10 years and could provide power in all hours of the day or some portion of the day. Long-term fixed
price contracts provide ~eater pricing and supply stability, as compared with reliance on the last-minute
"spot" markets.
Market-Clearing Price: A price for energy or ancillary services established through a competitive
process by demand and supply bids. The market clearing price is established by the point of intersection
between the cumulative demand bid curve and the supply bid curve for the applicable hour.
Megawatt (MW): One megawart equals 1,000 kilowatts.
Must-Take Resources: Generation resources owned or controlled by the IOUs that do not directly
participate in the competitive marketplace, but which are included as part of the utility's supply portfolio.
Such resources were secured by the utilities prior to ~estructuring and include QF generating units,
nuclear units, and pre-existing power purchase contracts with minimum energy take requirements. Certain
assets were provided must-take status to avoid a host of issues associated with contract abrogatio? or
similar ratemaking problems.
NERC: North American Electric Reliability Council. a voluntary association established to develop
standards for the reliable operation of interconnected utility control areas.
Obligation to Serve: A traditional regulatory obligation associated with the granting of a monopoly
service franchise which requires a utility to provide electric services for all customers and to assure
adequate supply of electricity now and in the future. California's industry restructuring efforts have
modified the IOUs' obligation to serve as to power supplies, but has maintained that obligation as to
distribution (wires) services.
Outage: The loss of operating ability ora resource, either as part ora planned maintenance program, or
due to an unplanned ("forced") event.
California Power Exchange (Cai PX): A non-profit corporation responsible for conducting a
competitive power auction for "spot" and "forward" supplies. The California Power Exchange was
responsible for scheduling generation in its scheduling (e.g., day-ahead, hour-ahead) markets, for
determining hourly market clearing prices for its market, and for settlement and billing for suppliers and
UDCs using its market
Qualified Facilities (QFs): Cogeneration and small power production facilities, such as renewable
resources, operated consistent with Federal Law (the Public Utility Regulatory Policies Act of 1978 or
"PURPA"). QFs were some of the first non-utility generation assets constructed and operated by private
capital. QFs typically provide energy and capacity to IOUs under long-term contracts approved by the
CPUC. Most new generation capacity constructed in California in the decade prior to industry
restructuring has come from QFs.
Real-Time Market: The competitive market operated by the CAISO for the purposes of securing last-
minute (realtime) imbalance power necessary when load serving entities fail to schedule adequate
supplies.
Reliability: The degree of performance of the elements of the bulk electric system that results in
electricity being delivered to customers within accepted standards and in the amount desired. May be
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measured by the frequency, duration, and magnitude of adverse events ("contingencies") on the electric
system.
Renewable Power: An alternate energy source to oil, gas, or coal used to produce electricity that is
capable of being replaced naturally. Renewable sources of power include solar photovoltaic energy, solar
thermal energy, wind power, small hydro, geothermal energy, landfill and mine-based methane gas, and
energy from waste (blomass).
Reserve Margin: The amount of reserve capacity on a regional transmission grid. The reserve margin is
a specified amount of capacity above the grid's peak requirements.
Scheduling Coordinator: An entity authorized to interact with the CAISO through the submission of
balanced schedules and related energy or Ancillary Service bids on behalf generators and loads.
Spot Market: A generic term referring to markets near the time' of delivery.
Stranded Costs: Costs that a utility has an obligation to pay for but may not be able to recover from a
customer because the customer no longer uses the utility's, service.
Transmission congestion: Congestion occurs when scheduled power transfers over transmission lines
exceeds the capacity of those lines. Transmission congestion occurs both across congestion zones (i.e.,
interzonal congestion) and within congestion zones (i.e., intrazonal congestion).
Unbnndle: The process of separating an integrated utility's generation, transmission and distribution
functions into their individual elements for ratemaking purposes. Unbundling is a necessary step when
transforming a monopoly market structuring into a competitive structure.
Unbundled Services: The separation and identification of individual rate components on a customer's
bill to correspond with the various individual service functions such as generation (or commodity),
transmission, distribution, public purpose programs and stranded cost recovery. By providing unbundled
rates for unbundled services, regulators provide customers with some of the information needed when
exercising customer choice among service options.
Utility Distribution Company (UDC): A regulated public utility with distribution (xvires) assets needed
to deliver power to retail customers. UDCs own, control and operate the lower voltage distribution
systems which are local in nature.
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APPENDIX B
KEY AGENCIES AND ORGANIZATIONS IN CALIFORNIA'S ELECTRIC MARKET
California Electricity Oversight Board (EOB)
The EOB was created by AB 1890 as a new state agency charged with overseeing the ISO and
PX. The EOB monitors, evaluates, and represents the state's interests concerning the operating
and reliability of the transmission system and the markets for electric energy. The EOB has the
right to approve the procedures of and the appointments to the governing boards of the ISO and
PX. There are three voting members appointed to the EOB by the Governor and two non-voting
members appointed by the California House and Senate.
California Energy Commission (CEC)
In 1974 California passed the Warren-Alquist State Energy Resources Conservation and
Development Act. This Act established the California Energy Commission (CEC). The mandate
of the CEC is to ensure a reliable and affordable SUlSply of energy for the state; as such, it is the
state's primary energy planning agency. The CEC is responsible for five major tasks:
· development and implementation of energy policy
· forecasting state energy needs and development of resource plans
· siting and licensing of power plants
· promoting energy conservation and renewable energy
· planning and directing the state's response to energy emergencies.
Five commissioners, appointed by the governor and approved by the state Senate, oversee the
work of the CEC. Each commissioner is appointed to a five-year term and fills a specific area of
expertise. The areas of expertise that must be filled are economics, law, environmental
protection, public at large, and engineering/science. The terms of the five commissioners are
staggered. The CEC is funded by an electric consumption surcharge.
California Independent System Operator
The ISO is a non-profit public entity responsible for operating the transmission system and
ensuring that transmission owning utilities and their competitors have equal access to the system
on comparable terms and at comparable rates. In California, PG&E, Southern California Edison
(SCE), and San Diego Gas & Electric (SDG&E) have relinquished operational control of their
transmission facilities to the ISO, although most of the municipal utilities such as the Los
Angeles Department of Water & Power (LADWP) and Sacramento Municipal Utility District
(SMUD) have not. As a result, the ISO operates the transmission system for most of California,
with the exception of those facilities owned and operated by municipal utilities and the federal
Western Area Power Administration.
The ISO has taken over transmission functions and responsibilities previously performed by the
utilities. Specifically, the ISO is responsible for:
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· Ensuring that sufficient generation capacity is available to maintain the system. The ISO
must make sure that enough generators are online and producing electricity to maintain
voltage levels and reliably meet demand. As part of this responsibility, the ISO arranges for
some power plants to operate continuously on a "must-mn" basis.
· Accepting balanced schedules and adjustment bids from Scheduling Coordinators.
Scheduling Coordinators (SC) are firms set up to coordinate the supply of electricity between
generators and end-users. They may operate as exchanges (like the PX), or may simply
coordinate demand and supply between a small number of generators and specific customers.
They submit schedules of electricity needs and transmission routes to the ISO, along with
"adjustment bids" in case power line congestion prevents the scheduled electricity from
being delivered.
· Managing transmission ~ongestion. Congestion occu~:s when the amount of power scheduled
for delivery across transmission lines exceeds their capacity. The ISO is responsible for
alleviating congestion by applying the SCs' adjustment bids (essentially offers to curtail
demand, or buy or sell additional power) until scheduled generation is in line with
transmission capacity. If adjustment bids are insufficient, the ISO imposes congestion
management charges to further curtail demand over congested lines. To this end, the ISO has
created "congestion zones" based on the transmission paths that most frequently experience
congestion in which these price adjustments take place.
· Dispatching the system in real-time. After receiving supply and demand schedules from SCs
and making adjustments for congestion, the ISO is responsible for operating the transmission
system and dispatching generation to meet actual demand. As part of this responsibility, the
ISO must:
· Administer real-time markets for imbalance energy. At any given moment, actual
energy use will deviate from what is scheduled. The ISO administers a spot
market (called the "Real-Time Imbalance Market") to either pay SCs for extra
generation they supply or bill them for extra consumption. Balances are settled
subsequent to the final delivery of electricity.
· Procure ancillary services to meet real-time demand and maintain system
reliability. "Ancillary services" are provided by generators who agree to make
power available on a stand-by basis to meet real-time demand and prevent voltage
fluctuations and outages. Separate markets exist for four "types" of ancillary
service (defined in terms of how quickly stand-by generation can be brought
online).
California Power Exchange*
The PX is designed to be the physical spot market in which suppliers sell their power at
transparent, real-time prices. The PX serves as the central clearinghouse for the majority of
power bought and sold in California. California's investor-owned utilities (IOUs) are required to
bid all their generation into the PX, with all power procured for customers on behalf of the utility
purchased via the PX. Other power suppliers can voluntarily participate in the PX.
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*This overview describes the PX as it'operated from April 1, 1998 until it ended trading operations on
January 31, 2001.
The PX operates Day-Ahead, Day-Of, and Daily .Market Activity Sequence
Block Forwards markets for electricity.
One Day Before Operation
· The Day-Ahead market determines · Participants bid in the Day-Ahead market and
price and quantity of electricity the PX determines the day-ahead market
delivered during each hour of the clearing prices (MCPs).
· The PX submits initial preferred schedules to
following day. Auctions for all 24 tbelSO.
hours are conducted at 7 a.m. each day · The ISO manages for potential over-
and market cleating prices become generation.
publicly available at 9 a.m. At 3 p.m., · Participants submit unit schedules to the PX.
the PX provides zonal ~ pricing · If the scheduled power flow across zones dres
information for Day-Ahead delivery if not exceed the transmission capacity, as
there is transmission system congestion determined by the ISO, the MCP identified by
(see below), the PX ~vill be final.
· If inter-zonal congestion management is
· The Day-Of market is similar to the necessal% a zonal PX MCP is determined
based on the day-ahead market adjustment
Day-Ahead market, consisting of three
bids.
daily auction periods that allow for
· The ISO determines the final day ahead
trading of electricity closer to its hour schedule.
of delivery. The Day-Of market gives
participants an opportunity to make On theDayofOperation
adjustments based on their Day-Ahead · Participants may submit supplemental energy
schedules so they can minimize real- bids to the PX at any time up to 40 minutes
time imbalances, before the beginning of a settlement period.
· Three sequential auctions throughout the day
· The Block Forwards market trades determine the schedules for each "Day-Of"
standardized contracts for "on-peak" settlement period (l lam to 4pm, 5pm to
blocks of power at fixed prices up to 12am, and lam to 10am).
· The PX forwards supplemental energy bids to
six months in advance. Each contract is
the ISO 30 minutes before the beginning of
based on a specific future month at a the settlement period.
certain quantity for the 16-hour period
(from 6 a.m. to 10 p.m.) when During the Settlement Period
electricity use is greatest (i.e., "on · Real-time operations are managed by the ISO,
peak"). Participants are billed or paid which also determines the real-time market
based on their net position in the Block price.
Forwards market compared to the
average Day-Ahead prices for a given
month.
For the Day-Ahead and Day-Of markets, the PX aggregates supply and demand bids into energy
supply and demand curves. The PX then determines market clearing prices based on the
intersection of these curves. In addition, generators can submit adjustment bids to the PX, which
are used by the ISO to alleviate congestion and by the PX to determine zonal prices. Because of
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transmission congestion and other factors, zonal prices can vary, with differing market clearing
prices in the Northern and Southern .Zones and at ISO tie points.
Generators can also submit bids through the PX to provide ancillary services and supplemental
energy to the ISO for balancing loads and resources in real time. These bids are submitted in
conjunction with bids for the Day-Ahead mai'ket, but actual dispatch and clearing prices for
ancillary services are determined in the "real-time imbalance market- conducted by the ISO.
The California PX is one of several Scheduling Coordinators that submit generation and load
schedules to the ISO. The PX, however, is by far the largest Scheduling Coordinator, accounting
for between 80 and 90 percent of electricity managed by the ISO.33 Tl'fis dominance is due to the
requirement that California's incumbent utilities sell and purchase power solely through the PX;
the IOU share of electricity demand in Day-Ahead markets remains close to 85 percent?
California Public Utilities Commission
The California Public Utilities Commission evolved from the Railroad Commission of
California, which was established in 1879. The Public Utilities Act of 1911 expanded the
Commission's authority to include its current sectors of regulation: electric, natural gas,
telecommunications, water, and transportation companies. Presently, the CPUC regulates the
retail rates, standards of service, and safety for these industries. The CPUC regulates privately
owned electric utilities but does not regulate municipal electric utilities.
The CPUC is responsible for implementing direct retail access as pan of California's electric
industry restructuring. The Commission also is responsible for evaluating the economic need for
new electric transmission capacity, regulating electric distribution operation and reliability,
examining the market behavior of utilities and their affiliates, and providing consumer protection
and education.
The Commission consists of five Commissioners appointed by the Governor and approved by
the Senate. Each Commissioner serves for a term of six years. The Commissioners' terms are
staggered to assure that experienced members are always present on the panel. One of the five is
elected annually to serve as president of the Commission. The president chairs the decision-
making meetings and other formal sessions and assigns cases among the members. The five
Commissioners as a whole make all final decisions on policy and procedures. Currently, there is
one vacancy for a Commissioner at the CPUC. Governor Da~Ss has yet to announce his
candidate for the vacancy.
33 Sladoje, G. Presentation to Independent Energy producers 18th Annual Meetin~ September 26-29, 1999.
34 Sladoje, op cit.
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Current Commissioners of the PUC
Commissioner Term
Loretta Lynch, President March 2000 - January 2005
Carl Wood 1999 - December 2004
Richard Bilas January 1997 - December 2002
Henry Duque December 1996 - 2002
Geoffrey Brown January 2001 - 2007
Federal Energy Regulatory Commission
FERC is the principal federal regulatory agency responsible for regulating the transmission and
sale for resale of natural gas in interstate commerce and the transmission and wholesale sales of
electricity in interstate commerce in the United States. The Commission is made up of five
members who serve staggered five-year terms and are appointed by the President and confirmed
by the Senate.
FERC regulates the rates and terms and conditions governing the sale and transmission of
wholesale electricity, ensuring that rates are just and reasonable. FERC's authority encompasses
the operation and structure of independent system operators, including the California ISO.
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APPENDIX C
FACTORS AFFECTING THE PRICE OF ELECTRICITY IN CALIFORNIA
This appendix discusses the factors affecting the price of electricity for SDG&E customers.
Many components of SDG&E's rates are currently regulated, meaning that these rates are
reviewed, and if they are determined to be reasonable, SDG&E is allowed to pass these costs on
to its customers. The CPUC has jurisdiction over the rates associated with distribution, public
purpose programs, nuclear decommissioning, the competition transition charge (CTC), and the
trust transfer amount. The FERC has jurisdiction over transmission rates. The generation
component of rates is unregulated and subject to market forces, although the California
Legislature has imposed a cap of 6.5 cents per kWh for this component of SDG&E customers'
rates for residential and small commercial customers, as shown in the figure below. In addition,
other'customers may Opt into this rate stabilization program under certain circumstances. Each of
these components of SDG&E's rates is discussed in greater detail below.
0
Residential and Small Commercial Customers Other Customers
· Transmission Rates - This component covers the costs associated with SDG&E's
transmission system and is regulated by FERC.
· Distribution Rates - This component covers the costs associated with SDG&E's distribution
system and is regulated by the CPUC.
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· Nuclear Decommissioning - This component covers the costs associated with the future
decommissioning of SDG&E's share of the SONGS nuclear plant and is regulated by the
CPUC.
· Public Purpose Programs - This component covers the costs associated with public purpose
programs (e.g., energy conservation incentives) and is regulated by the CPUC.
· Trust Transfer Amount - This component covers the costs associated with the bonds that
were issued to reduce rates by 10% for residential and small commercial customers as
approved by the California State Legislature.
· Competition Transition Charge - This component covers the costs associated with the above-
market costs of long-term contracts between SDG&E and qualifying facilities (QFs).
· Generation - This component is currently unregulated. In order to gtabilize rates, however,
the California State Legislature capped this rate at 6.5 cents per kWh for residential and small
commercial customers in SDG&E's service territory. Other customers who do not opt into
the rate stabilization plan pay market-based rates. Prior to deregulation, the cost of generation
included the fuel and operating costs of power plants, in addition to the capital costs
associated with their construction and a return for the utilities for their investments. With
deregulation, the price for generation is no longer regulated and the price paid by customers
is determined by the interaction of supply and demand and, in the current environment, is
based upon "what the market will bear."
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APPENDIX D
REGULATORY ISSUES FOR SITING A MAJOR POWER PLANT
The CEC Siting Process
Califomia has relatively strict rules concerning the siting of new power plants, designed to
minimize environmental impacts and disruption to local communities. Any entity wishing to
construct new thermal generation (>50 MW) must be certified by the California Energy
Commission (CEC). The CEC grants certification only to projects whose applicants demonstrate
that adverse impacts are minimal or can be sufficiently mitigated.35 Construction on a new plant
can only begin after certification is complete, usually more than a year after an application is
filed?
Among the issues the CEC considers in the siting prochss are:
· project costs
· electric system reliability impacts
· community quality of life impacts
· health and safety impacts
· socioeconomic impacts (including environmental justice)
· environmental impacts.
In practice, a significant amount of data and information must be collected even before an
application is filed. The CEC siting process usually consists of the following six phases:
1. Prefiling Review: The period of planning and preparation before an applicant submits a
formal Application for Certification (AFC) to the CEC.
2. Data Adequacy: Review process used to determine that the AFC is sufficiently complete
based on the information required in the Commission's regulations. When the Application for
Certification is accepted as "data adequate," the one-year mandatory timeline begins.
3. Discovery: Public information hearings, workshops, and site visits during a period of data
acquisition by CFC staff, other agencies, and outside "intervenors."
4. Analysis: CEC staff, agencies, and participants hold workshops to analyze the project and its
various issues. Staff prepare a Preliminary Staff Assessment, and later, the Final Staff
Assessment Report_
5. Hearings: To make a decision "based on the facts," formal hearings are held by the CEC to
take written, oral and documentary testimony from involved parties.
35 A "project" may include transmission lines and other facilities accompany/rig construction of the power plant
itself.
36 Under the CEC's standard siting process, the timeline for review is a mandatory 12 months. The CEC recently
developed rules for an expedited siting process lasting only 6 months, but projects submitted for "fast track"
approval must provide more data in their initial applications.
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6. Decision Phase: A determination to approve or deny the AFC.
Because the CEC siting process .takes at least a year, and construction can take another year, the
earliest Chula Vista might see a new plant online would be 2003. This time could be reduced if
the Cit?' decides to build a plant under 50 MW (e.g, a small peaking plant), in ~vhich case formal
siting review is not required, or submits an application for expedited review.
Plant Operations and Scheduling Requirements
If the City decides to build a power plant for anything other than dedicated, over-~e-fence sales,
it will need to schedule power deliveries with the California Independent System Operator (ISO).
It can do this by either hiring a certified "Scheduling Coordinator," or by registering as a
Scheduling Coordinator itself. Scheduling Coordinators are entities established under
California's restructuring law that submit schedules of electric generation and demand directly to
the ISO, usually on behalf of multiple generators and end-users. Becoming a certified Scheduling
Coordinator requires subm!tting an application to the ISO, completing various contractual
agreements, meeting various technical requirements related to data transmission_ and undergoing
training and testing. Acting as a Scheduling Coordinator would also require the City. to dedicate
staff for this function. Because of these administrative burdens, a better option for the City may
be to contract out scheduling functions.
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