HomeMy WebLinkAboutStaff Report 169-06City of Palo Alto
City Manager’s Report
TO:
FROM:
DATE:
SUBJECT:
HONORABLE CITY COUNCIL
CITY MANAGER DEPARTMENT: UTILITIES
APRIL 17, 2006 CMR: 169:06
LONG-TERM ELECTRIC ACQUISITION PLAN (LEAP) UPDATE AND
REVISED 2006 LEAP IMPLEMENTATION TASKS WITH A REQUEST
FOR APPROVAL TO REDIRECT LOCAL GENERATION FEASIBILITY
STUDY EFFORTS TOWARD SMALL-SCALE DISTRIBUTED
GENERATION AND POWER GENERATION OWNERSHIP
ALTERNATIVES OUTSIDE OF PALO ALTO.
RECOMMENDATION
This report requests that City Council approve the Local Generation Feasibility Study Phase I
recommendation to redirect the feasibility study efforts to focus on local small-scale distributed
generation and potential power plant alternatives outside of Palo Alto.
PROJECT DESCRIPTION
The LEAP Objectives and Guidelines set long-term directions for staff in planning and managing
the electric supply portfolio. Many of the implementation tasks in the 2003 Implementation Plan
have been completed or mostly completed. The final status update for the 2003 LEAP
Implementation Plan and the revised and updated 2006 LEAP Implementation Tasks are
presented in the attached UAC report (Attachment A). Implementation tasks that require Council
action will be taken to Council for approval as they develop.
BOARD/COMMISSION REVIEW AND RECOMMENDATIONS
There was discussion surrounding several of the information items of the revised LEAP
Implementation tasks, highlighted in the meeting minutes (Attachment B). The UAC voted
unanimously to recommend approval of the staff recommendation to redirect the local generation
feasibility study efforts toward small-scale distributed generation and power generation
ownership opportunities outside of Palo Alto.
CMR:169:06 Page 1 of 2
RESOURCE IMPACT
Funding for the Local Generation Feasibility Study is included in CIP Project EL-06004 and is
described in the attached UAC Report.
POLICY IMPLICATIONS
This recommendation is consistent with the Council-approved Utilities Strategic Plan to enhance
customer satisfaction and utility infrastructure, employ balanced environmental solutions, and
provide fair and reasonable returns for the City and competitive rates to customers through
municipal ownership.
ATTACHMENTS
A: UAC Report: Item 3 March 1, 2006
B: Draft UAC meeting minutes excerpts March 1, 2006
PREPARED BY:
Karl E. Knapp ~
Senior Research Planner
DEPARTMENT APPROVAL:
CITY MANAGER APPROVAL:
CARL
Assistant City Manager
CMR: 169:06 Page 2 of 2
Attachment A
TO:
FROM:
UTILITIES ADVISORY COMMISSION
UTILITIES DEPARTMENT
3
DATE:
TITLE:
MARCH 1, 2006
LONG-TERM ELECTRIC ACQUISITION PLAN (LEAP) UPDATE
AND REVISED 2006 LEAP IMPLEMENTATION TASKS WITH A
REQUEST FOR APPROVAL TO REDIRECT LOCAL
GENERATION FEASIBILITY STUDY EFFORTS TOWARD
SMALL-SCALE DISTRIBUTED GENERATION AND POWER
GENERATION OWNERSHIP ALTERNATIVES OUTSIDE OF
PALO ALTO.
REQUEST
This report requests the UAC recommend that CiS’ Council approves the Local Generation
Feasibility Study Phase I recommendation to redirect the feasibility study efforts to focus on
local small-scale distributed cogeneration and potential power plant alternatives outside of Palo
Alto. The report is otherwise an information repor~ summarizing the progress on the Long-term
Electric Acquisition Plan (LEAP) and describing revised 2006 LEAP Implementation Tasks
(Attachment A).
BACKGROUND
Council approved Palo Alto’s Long-term Electric Acquisition Plan (LEAP) Objectives and
Guidelines (Attachment B) in 2001 and 2002 (CMR:425:01 and CMR:398:02), and the first
LEAP Implementation Plan (Attachment C) in August 2003 (CMR:354:03). LEAP was
developed and approved in preparation for the change in energy supply requirements that started
in January 2005, triggered by the ending of two large contracts with Western Area Power
Administration (Western) and PG&E. Staff has kept the Council and the UAC apprised of the
progress of the Implementation Plan through periodic updates (CMR: 198:05 of April 2005, and
CMR: 370:04 of August 2004).
The LEAP Objectives and Guidelines set long-term directions for staff in planning and managing
the electric supply portfolio. Many of the implementation tasks in the 2003 Implementation Plan
have been completed or mostly completed. The final status update for the 2003 LEAP
Implementation Plan and the revised and updated 2006 LEAP Implementation Tasks are
presented in this report. Implementation tasks that require Council action will be taken to
Council for approval as they develop.
Page 1 of 16
DISCUSSION
Palo Alto’s electric retail load is primarily met with hydroelectric generation from Western and
Calaveras, and renewable energy resources, with contract terms ranging from 15 to 23 years. The
remainder of the load, 25% to 35% during an average hydro year, is currently met with market
purchases made up to 3 years in advance. The Northern California Power Agency (NCPA)
ensures that the City’s varying load is met in the short term by utilizing these resources in
combination with short-term energy market transactions to balance loads and resources in real
time. The City’s annual electrical energy and transmission budget in FY 06-07 is projected to be
$62.6 million. However, this annual purchase budget could fluctuate by up to +/-$17 million
dollars depending on hydroelectric production conditions, with the total cost being lower in a wet
year and higher in a dry year. Cost variability and uncertainty also stems from other aspects such
as volatile energy prices, transmission congestion cost, local capacity cost, credit, legal and
regulatory uncertainties, and others. The City maintains a rate stabilization reserve to dampen
this electric supply cost variation and to stabilize rates for retail customers. The total energy
supply component of the residential electric bill is approximately 7¢ per kilowatt-hour and
accounts for 60 to 70% of an average residential electric bill.
Staff recommends that Council approve that the local generation feasibility study efforts be
redirected, in essence concluding that the Phase I Feasibility Study recommendation as
contemplated in CMR:247:04 is to not go forward with a Phase II study of power plant sites
inside Palo Alto. Staff recommends that the efforts should instead be applied to (a) development
and implementation of a comprehensive plan to facilitate and implement clean high-efficiency
distributed small-scale cogeneration, also know as combined heat, power and cooling, and (b)
evaluation of power plant ownership oppommities outside of Palo Alto, but within or near the
Greater Bay Area.
The key 2003 LEAP Implementation task accomplishments are highlighted in Table 1, with
additional discussion in the body of this section. The new 2006 LEAP Implementation Tasks are
sttmmarized in Attachment A, and highlighted in Table 2 including updated goals and target
completion dates. Each element of 2006 LEAP Implementation Tasks supports one or more of
the LEAP Objectives and Guidelines approved by the Council. The implementation tasks have
been ordered to reflect the resource priority inherent in California’s Senate Bill 1037 "loading
order", with efficiency first, followed by renewable resources, and then followed by
conventional generation. Most elements of the 2006 LEAP Implementation Tasks are within the
City Manager’s authority and responsibility to approve, for which most of the description herein
serves as an information report.
Page 2 of 16
1.Renewable Resource
Acquisition Targets
2.Implement Palo Alto
Green
Implementation of Public
Benefits Program
4.Implementation of
Additional Cost Effective
Energy Efficiency
Programs (Not Currently
in Public Benefits
Program)
5.Investment in Natural Gas
Fired Generation
6. Distributed Generation
¯ Approved three long-term contracts that will add
eligible renewables10-11% by 2007
¯ Approved two additional long-term contracts to
add an additional 6-8%
¯ Ameresco Santa Cruz landfill generator began
commercial operation (1% of supply)
¯Surpassed 13% participation threshold
¯Near 14% threshold (13.9%)
¯Continue to implement a nationally recognized
program
¯ Public Benefits Plan 2005-07 presented to UAC
¯ Implement program
¯ Customer-interactive interval metering
(MeterLinks)
¯ RMI evaluation and recommendations completed.
(UAC presentation Nov 2005)
¯ Contract awarded to develop integrated efficiency
program design and reporting tool.
¯ Participated in joint efforts with other public power
providers via NCPA to develop consistent
efficiency program reporting.
¯ RMI assessment of local cogeneration potential
completed (UAC presentation Nov 2005)
¯ Summary assessment completed (Navigant)
comparing local renewables, cogeneration and
conventional generation alternatives.
¯ CPAU joined USEPA’s Combined Heat and
Power Partnership
¯ Participated in joint efforts with other municipal
utilities to screen potential power plant
ownership opportunities.
¯ Distribution generation valuation project
completed.
¯ CEC Report finalized
¯ RMI local cogeneration potential study and
integration study completed. Also supports
Tasks #4 and #5.
¯ Small-scale cogeneration Initial feasibility study
completed by the US EPA for Roche Palo Alto.
¯ Nov 2004 and
Jan 2005
¯ Aug 2005 and
Oct2005
¯ Feb 2006
¯ Oct2005
¯ Jan 2006
¯ Ongoing
¯Jan 2005
¯Ongoing
¯Ongoing
¯ Dec 2005
¯ July 2005
¯ Ongoing
¯ Oct 2005
¯ Sep 2005
Dec 2005
Ongoing
¯ Fall2004
¯Feb 2005
¯Dec 2005
¯ Dec 2005
Page 3 of 16
7.¯ Fall 2005Investigation of New Risk
Management Tools
Pursue Low-Cost, High
Value Supply
Opportunities
9.Continue to Refine
Analytical Tools
¯ Analyzed hydro exchange and other hydro risk
reduction products. CHEX and insurance
product costs were greater than value.
¯Evaluating tolling agreements.
¯Update Risk Management Policy
¯Software modeling tool to manage transmission
cost under evaluation.
¯ Ongoing portfolio optimization activity.
¯ Evaluated several power plant opportunities that
developed, and recommend further evaluation
of one in 2006 Plan. Also supports task #5.
¯ Analysis of Calaveras layoff completed. - layoff is
not recommended.
¯ Revamped portfolio models
¯ Transaction database implemented for gas and
electricity
¯ Developed multiple scenarios for evaluating and
reporting robustness of electric portfolio
¯ Developed alternative hydro generation
projections based on Western forecasts.
¯ Legislative priorities reviewed with UAC Continue
to be actively involved with other Bay Area
municipalities.
¯Council approved reserves guidelines
¯Guidelines reviewed with UAC
¯Spring 2006
¯Feb 2006
¯2006
12. Block Energy Purchases
13. Electric Master
Agreements (EMA)
Approval & Delegation of
Authority
14. Development of Short-
term Hedging Strategies
15. Evaluation and Design of
Demand Response
Program
¯Ongoing
¯Spring 2006
¯Spring 2006
¯June 04, ongoing
¯June 2004
¯Fall2005
¯Spring 2006
10.Influence Legislative and ¯ Jan 2005
Regulatory Initiatives and ¯ On goingpursue Transmission
11 .Maintenance of Adequate ¯ Dec 2003
Supply Rate Stabilization ¯ Apr 2005Reserves
¯DONE: Energy purchases made ¯ Jun 2004
¯ DONE: EMA with 4 suppliers completed, Council ¯ Feb 2004
has delegated authority
¯Jun 2004¯ DONE: Short-Term Electric Asset Management
guidelines Implemented
¯Program economic evaluation completed
¯Customer survey conducted
¯RMI evaluation completed
¯ Expand the installation of interval metering, and
evaluation of control equipment.
¯Ju12004
¯Sep 2004
¯Dec 2005
¯Fiscal05/06
Page 4 of 16
Table 2. 2006 LEAP Implementation Task Highlights and Goals Summary
2006 LEAP Implementation StatusTask
1. Climate Action
2.Public Benefits
3.Efficiency Portfolio
4. Renewable Portfolio
5.PaloAItoGreen
6.Clean Distributed
Generation
7.Natural Gas-Fired
Generation
8.Greater Bay Area
Contracts
Completion Date
¯ 2006¯ Complete CA Climate Action Registry process for
reporting and certifying greenhouse gas
emissions.
¯Develop Climate Action Plan
¯Coordinate Public Benefits program
enhancements with efficiency portfolio plan
development (Task #3)
¯Develop long-term resource efficiency portfolio
plan to pursue efficiency enhancements as a
supply resource.
¯Complete the installation of interval metering and
Automated Meter Reading systems.
¯ Revise or develop optional time-differentiated
retail rates.
¯ Leverage joint efforts with other public power
providers via NCPA efficiency initiative and
Public Benefits Committee.
¯ Maintain voluntary demand reduction program
and customer-interactive interval metering
(MeterLinks)
¯Participate in NCPA "Green Pool" joint
procurement initiative to meet remaining needs.
¯ Strive to meet 2015 goals by 20!0 (20%).
¯Include Palo Alto Green needs in Task #-4
activities where feasible.
¯ Evaluate options to meet solar portion (3%) with
in-town solar resources.
¯ Develop long-term cogeneration implementation
plan.
¯Evaluate interested large industrial customers
(Roche Palo Alto) for potential pilot project.
¯ Establish standardized interconnection rules and
process.
¯ Evaluate joint agency efforts to evaluate power
plant ownership alternatives outside of Palo
Alto.
¯ Issue RFP to solicit firm energy and capacity from
generators within the Greater Bay Area,
including renewables, cogeneration and
conventional generation.
¯Continue to implement laddering strategy with
diversified products.
¯ Continue to refine analytical tools to track, report,
and improve portfolio performance.
¯2007
¯Fall 2006
¯ Fall 2006
¯ 2007
¯ 2006/2007
¯ Ongoing
¯ Ongoing
¯ Summer 2006
¯ Summer 2006
¯Spring 2007
¯Fall 2006
¯ Summer 2006
¯Summer 2006
¯2006
¯ Summer 2006
9.Portfolio Management ¯ Ongoing
¯ Ongoing
Page 5 of 16
2006 LEAP Implementation I
Task Status Completion Date
10. Risk Management ¯ Sep 2006
11. Local Interconnection
12.Legislation and
Regulation
¯ Complete the last of the Utilities Risk
Management Audit recommendations
¯ Develop improved transparent and streamlined
Back Office process (contract administration
and settlements)
¯ Clarify authorities for wholesale sales of surplus
energy commodities.
¯ Maintain financial reserves as primarily hydro risk
cushion.
¯ Periodically review appropriate level of financial
reserves
¯ Investigate transmission connection increase
from 115 to 230 kV
¯ Investigate redundant transmission connection to
west side.
¯Influence and track market design.
¯Support Bay Area transmission upgrades.
¯ Define policy to meet potential mandatory
resource adequacy requirements.
¯ Summer 2006
¯ Fall 2006
¯ Ongoing
¯Summer 2006
¯Fall 2006
¯ Fall 2006
¯ Ongoing
¯ Ongoing
¯ Summer 2006
2006 Implementation Task #!: Climate Action (2006 #1) (NEW)
This implementation task captures activities previously masked in the background of
other tasks. Palo Alto has numerous multi-department efforts in the sustainability arena.
As provider of the electricity and natural gas to all Palo Alto customers, CPAU is the
logical group to inventory and certify greenhouse gas emissions related to utility
operations, and communicate the energy use implications to its customers. CPAU will
also support City efforts to report greenhouse gas inventories for City government
operations, as the data is needed to obtain an accurate accounting for the Utilities
Department. The City has joined the California Climate Action Registry, which has
established the standardized reporting and certification process for greenhouse gases
being used by most utilities and government agencies. CPAU will develop a Climate
Action Plan to define an approach to addressing greenhouse gas risks relating to utility
operations.
Public Benefits (2003 #3, 2006 #2)
The electric public benefits program is funded by a fee equal to 2.85% of the electric retail rate.
The funds are partially used to demonstrate renewable resources or alternative technologies and
to assist customers in pursuing efficiency improvements. The public benefits plan for 2005-2007
was presented to Council in January 2005, and regular updates are included in each UAC
quarterly report. There are no new implementation plans specific to implementing the existing
Public Benefits programs at this time except to the extent that efforts overlap with the "efficiency
portfolio" efforts described below. On February 13, 2006, Council approved the final element of
Page 6 of 16
the City’s $2.8 million Photovoltaic Demonstration project, which will incorporate ten
rectangular two-axis tracking systems that fol!ow the sun during the course of the day. The
project is being managed by the Public Works Department, and is funded 50% by the US DOE
and 50% by CPAU Public Benefits. The project will total approximately 300 kW at three sites,
producing approximately 600,000 kWh per year, which is approximately 50% of the solar
portion of the PaloAltoGreen demand.
This year, coordination between municipal utilities has been improved through increased activity
in the NCPA’s Public Benefits committee, which is coordinating efforts to ensure consistent
reporting of energy efficiency program spending and accomplishments. "Apples to apples"
consistency will be important in reporting accomplishments and progress to the community and
to regulatory agencies. These continuing joint efforts will also dovetail with the new "efficiency
portfolio" efforts.
2006 Implementation Task #2: Public Benefits
Continue implementation of electric public benefits programs, which is fimded by
collecting a fee equal to 2.85% of the electric retail rate. These funds are partially used to
demonstrate renewable resources or alternative technologies and to assist customers in
pursuing efficiency improvements. Coordinate Public Benefits program enhancements
with efficiency portfolio plan development (Task #3)
Cost-Effective Energ~ Efficiency (2003 #4, 2006 #3) & Demand Response (2003 #14. 2006 #3)
The Rocky Mountain Institute assisted CPAU in reviewing CPAU’s resource plan, including
evaluating the energy efficiency potential and demand response options in Palo Alto. Their initial
results were presented to the UAC in November 2005, and the project Final Report Executive
Summary is provided as Attachment D.
RMI recommended that additional efforts in price-driven demand response are not likely to
achieve substantially more participation than the current voluntary program, which is capable of
lowering short-term electric demand by 3-5 MW. Quoting directly from the report,
While there may be potential to expand demand response programs to include smaller
customers, dynamic pricing, and/or automated control technology, several factors likely limit
the cost-effectiveness of such potential:
¯CPA U’s loadprofile is relativelyflat, with relatively little ability to shift load from
peak to off-peak,"
¯Becauseoftheverymildclimate, CPAUdoesnotexperienceasteepon-peakload
spike compared to inland areas that have higher loads from commercial and
especially residential air conditioning;
¯Due to the above two factors, the demand response yield, in terms ofkW/customer
shifted, would be relatively low, which would make the cost, in terms of $/kW shifted,
relatively high;
¯CPA U has relatively.flexible supply resources because of the availability of hydro
power from Western and Calaveras;
Page 7 of 16
Much of the largest and most cost-effective demand response opportuniO, with large
customers is already being realized via voluntary CPA U programs;
Lastly, ptvgram costs to serve small customers can be partieularly high, and issues
regarding split incentives between tenants and owners can cause additional barriers
to implementation.
RMI estimated that implementing all remaining cost-effective energy efficiency measures by all
CPAU customers could reduce long-term electric resource needs by up to 70 GWh per year
(-7% of load) at a cost less than 5 C/kWh, and up to 95 GWh per year (-10% of load) at a
levelized cost of less than 8 C/kWh. If, through careful program design and implementation, half
of this potential could be achieved over a ten-year time horizon, historical electric demand
growth of-0.3% per year could potentially be met entirely with energy efficiency.
Energy and Environmental Economics, Inc has been contracted to develop an efficiency program
design tool tailored for CPAU to integrate electric, gas and water efficiency, and to include
program labor and overhead costs in estimating program cost effectiveness. The tool will provide
cost-effectiveness tests from several perspectives: utility, participant, community, and non-
participant, and will also tie into systems used for tracking and reporting expenditures and
estimated savings. This tool is expected to be in use by summer 2006, and will play a key role in
developing a long-term multi-commodity integrated efficiency program plan.
2006 Implementation Task #3: Efficiency PorOrolio
¯ Energy efficiency and load management efforts have been combined into one "Efficiency
Portfolio" implementation task. The primary task is to develop a long-term (10-year)
resource efficiency portfolio plan with a 2 year funding plan (to match budget cycle) to
pursue efficiency and load management enhancements that recognizes cost-effective
energy efficiency and load management as priority resources in the "loading order" for
energy resources. Design efficiency programs to account for the combined benefits of
electric, gas, and water efficiency savings (e.g. a horizontal clothes washer saves
electricity, water and gas), and consider both end-use efficiency (from the retail meter to
customer end use) and delivery efficiency (reducing system losses in generation,
transmission, and distribution). Devise and initiate a measurement, verification, and
reporting process to improve communication with the public and meet requirements of
SB 1037, which includes specific mandatory reporting requirements for energy efficiency
programs starting January 1, 2007. Incorporate RMI efficiency potential study insights.
Leverage joint efforts with other public power providers via NCPA efficiency initiative
and Public Benefits Committee. Maintain the existing voluntary demand reduction
program and customer-interactive interval metering (MeterLinks), and develop retail rate
options that provide price signals to customers that encourage efficiency. As appropriate,
additional funding for cost-effective efficiency programs will be recommended to
complement and enhance the existing Public Benefits efficiency programs.
Renewable Portfolio Investments (2003 #1, 2006 #4)
Palo Alto adopted a goal in October 2002 to purchase 10% of electric energy supplies from new
eligible renewable resources for 10% ofload by 2008 and 20% by 2015, with an allowable rate
Page 8 of 16
impact up to ½ C/kWh. This criteria translates to an allowable purchase price of up to $25/MWh
(2.5 C/kWh) above the market price without raiding public benefits funds. Through two separate
RFP’s, one via NCPA and one by CPAU, Palo Alto has signed $252 million worth of contracts
for wind and landfill gas supplies with terms ~om 15-24 years, that are expected to add 15-19%
of new renewable resources by 2007, depending on the final installed capacity of the remaining
projects. The most recent addition was the Ameresco Santa Cruz project at the Buena Vista
Landfill, which successfully completed its acceptance tests on early February, 2006. The project
is a 3 MW generator, with the output sold 50% to CPAU and 50% to Alameda, and will provide
1% of CPAU’s electricity supply. The table below summarizes all five contracts and their current
status, in order of the Council approval dates.
CPAU Renewable Electric Energy Supply Contracts Summary
Supplier
Project Name
Contract Status
Fuel Type
Product Type
Location
Site Owner
Project Status
Other Parties
Projected/Actual Start Date
Term Years
Contract Amount
Price $/MWh
/kverage Cost S/year
Project Capacity
F’alo Alto Share
IPalo Alto Energy MWh/year
% of CPAU Load
CMR
Council Date
PPM
High Winds I
Executed
Wind
Da~-Ahead Firm
Solano County
FPL
Operating
Alameda 33%
Dec-04
23-1/2 years
$78.4 million
$57.60 fixed
$3.3 million
162 MW
12.35%
58,000
5.60%
CMR:424:04
8-Nov-04
Ameresco
Santa Cruz
Executed
Landfill Gas
Unit Contingent Firm
Watsonville
County of Santa Cruz
Operating
Alameda 50%
Feb-06
20 ~,ears
$13.9 million
$51/MWh
+ 1.5%/year
$0.7 million
3.2 MW
5O%
11,800
1.10%
CMR:461:04
8-Nov-04
Ameresco
Half Moon Bay
Executed
Landfill Gas
Unit Contingent Firm
Half Moon Bay
BFI
Permittin9Alameda 50%
Dec-06
20 years
$26.0-$61.8 million
$52/MWh
+ 1.5%/year
$3.1 million
5.7-13.4 MW
5O%
21,600 to 51,300
2.1% - 4.9%
CMR:100:05
18-Jano05
Ameresco
Keller Canyon
Executed
Landfill Gas
Unit Contingent Firm
Pittsburg
BFI
Permitting
Alameda 50%
Dec-06
20 years
$15.6-$22.8 million
$59IMWh
+ 1.5%/year
$1.1 million
2.8-4.1 MW
5O%
1’0,300 to 15,100
1.0% - 1.4%
CMR:350:05
8-Aug-05
PPM
Shiloh
Executed
Wind
Month-Ahead Firm
Solano County
PPM
Under Construction
none
Nov-06
15 years
$50-$75 million
$62.95 fixed
$3.3 to $5 million
100-150 MW
16.66%
49,900 to 74,8’00
4.7%-7.1%
CMR:386:05
11-Oct-05
2006 Implementation Tasks #4: Renewable Portfolio
Staff is working to accelerate efforts in order to meet the 2015 goal by 2010. Staff will
work closely with the suppliers to ensure the completion and start-up of projects still
being developed (two landfill generation and one wind project). Palo Alto will participate
in a new joint effort via NCPA termed the "Green Pool" for the remaining renewable
power supply needs, including power to meet Palo Alto Green demand. Staff will also
maintain "all-source" procurement perspective when seeking additional supplies, so that
cost-effective renewable energy supplies are included whenever they can meet the
technical requirements.
Palo Alto Green (2003 #2, 2006 #5)
Nearly 14% of CPAU customers participate by paying an extra 1.5 C/kWh for 97.5% wind/2.5%
solar supply, which represents -3% of the total annual energy load. These purchase are
voluntary, and are not include in the Renewable Portfolio Investment goals. Palo Alto Green is a
Green-e certified, multiple award-winning program. Recognition awarded to Palo Alto Green
include:
1. US EPA Green Power Leadership Award; 2004.
2. The Innovation Group Outstanding Achievement in Local Government; June 2005.
Page 9 of 16
3. Acterra Business Environmental Award; April 2005
4. American Public Power Association DEED Energy Innovator Award; 2005.
2006 Implementation Task #5: PaloAltoGreen
¯ Goals for the coming year are to achieve 15% participation rate, and as mentioned above,
to purchase sufficient supplies to meet total renewables demand. Evaluate alternatives to
meet the solar portion of the Palo Alto Green demand with in-town solar power.
Natural Gas Fired Generation (2003 #5, 2006 #7) and Distributed Generation (2003 #6, 2006 #6)
The Local Generation Feasibility Study was approved by Council in May, 2004 (CMR:247:04).
Staff presented a summary of electric supply alternatives to Council in a study session on
October 12, 2004, and progress has been reported in each UAC quarterly report and in periodic
LEAP Update reports to the UAC and Council (CMR:370:04 and CMR:198:05). Staff also
presented a summary of electric supply alternatives to Council in a study session on October 12,
2004. Upper management and other departments have been kept abreast of progress by providing
monthly updates at each Land Use Committee meeting.
Development of a generation facility inside Palo Alto is expected to be more expensive than
other areas in the Bay Area, where there are larger tracts of truly industrially-zoned potential
sites that are favorably located near natural gas, electric transmission, and reclaimed water
resources necessary for technical and economic feasibility. There are numerous comprehensive
plan and various master development plans that restrict the design, layout, and operation of such
a facility that further add to the pot?ntial cost. Furthermore, there are limited potential locations
suitable for a power plant in Palo Alto, even for a modest 25-30 MW facility, and the areas that
do have reasonable access to the necessary infrastructure to be economic are mostly either in or
adjacent to dedicated parkland, open space, or residential communities.
Generation in town would save about $8/MWh today, or 0.8 cents/kWh, in transmission charges
compared to generation in the Bay Area but not within Palo Alto. These avoided costs are
anticipated to increase over time. To achieve the combination of conversion efficiency and initial
capital cost to achieve net financial savings, a generation facility needs to be much larger than
the 25-50 MW range of Palo Alto’s needs recommended in the LEAP Implementation Plan.
Because these smaller power plants are less efficient and require higher capital cost per kW than
larger generators, the transmission savings are overcome by their higher operating costs. In order
to realize cost savings, such a facility would need to be substantially larger, and therefore a
shared effort with other interested utilities or partners. NCPA and other municipal partners have
expressed such interest, and have in parallel identified other opportunities that are more attractive
to them than a power plant located in Palo Alto.
Other oppommities such as distribution system modifications to provide a high-voltage
connection to the transmission grid (230kV), may be preferable on reliability grounds, and would
reduce the potential transmission avoided costs by up to 60%. That is, some of the key economic
benefits associated with local generation would not come to fruition if other potentially
important infrastructure opportunities are completed (see Local Interconnection Task #11).
Page 10 of 16
A key task in the RMI resource planning studies was a screening analysis conducted to estimate
the potential for customer-sited cogeneration opportunities, and to contrast cogeneration with
conventional generation and energy efficiency potential in an integrated framework. RMI
identified up to 40 MW of technical potential, and five customers whose monthly gas and
electric load patterns were consistent with facilities that may be able to support cost-effective
combined heat, power and cooling. Two of the five have expressed sincere interest in further
exploring the opportunity, as it has potential to simultaneously reduce costs and achieve
environmental corporate objectives for customers as well as for CPAU. The economic potential
that could be cost-effective from thi~ group is estimated to be 3-12 MW. In light of the high
customer interest and potentially favorable economics, staffrecommends a more detailed
feasibility and engineering analysis, with Roche Palo Alto as the first test pilot case.
RMI also concluded, in addition to pursuing energy efficiency and cogeneration potential in Palo
Alto, that, "CPA U should also continue to study local central generation sources, based on
either combined cycle or simple combustion turbines, as well as the possibility of a large
cogeneration plant ira suitable heat load exists". No large thermal load, such as a large
industrial manufacturing facility or a district heating or cooling system, currently exists in Palo
Alto, and staff recommends looking outside of Palo Alto.
Navigant Consulting, a prominent electric power consulting firm with strong expertise in both
conventional and distributed generation and cogeneration as well as renewable energy resources,
independently evaluated the costs and trade-offs for customer-sited cogeneration and central
station cogenerafion and generation alternatives inside and outside ofPalo Alt6. The key
features of the various gas-fired generation alternatives that could be employed to meet a portion
ofPalo Alto’s electricity needs are summarized in the table below, contrasted with market
purchases as a default benchmark. The results support the RMI studies and indicate that small-
scale distributed cogeneration is a potentially attractive avenue to meet a portion ofPalo Alto’s
energy needs.
Page 11 of 16
PALO ALTO NEEDS:
Dispatchable Resources
Up to 35 MW
Reliable Low Cost Power
Environmental Stewardship
Expected Efficiency (Heat Rate)
Finar~in~; a~d (~w~ers~p Structure
Dev~opm~t S~ed~e (mon~)
Tr~ssion Upside
Water (1~0 $~/day)
Sing ~d Ne~ (aer~)- ~pi~l
Potenfi~ l~ations
Other
C~pit~
initial investment for 25 MW averag~
All-in ($/kWh) ($6
Customer-Sited Cogenerafion
MICRO
Ga~ Fired Turbin(
or Engine < 2 MW
>50%
CPAU/Cus~omer
< 12 months
none
<I
SMALL MEDILVM
Gas Fired Turbine 25-50 MW
or Engine >5MW Cogeneration
> 60%>60%
CPAU/Customer CPAU
< 12 months 12-18 months
1-10 MW+moderate
>20 100-300
<2 (distributed)3-6
Central Station in or ne~ Palo Alto
MEDIUM
25-50 MW
Comb. Cycle
>50%
CPAU
12-18 months
moderate
150-300
3-6
LARGEMEDIUM
25-50 MW 25-50 MW Share
of 150 MW+Peeker Plant Comb.
35%> 50%
CPAU CPAU/Other Muni
12-18 months 18-36 months
moderate major
100200 up to 1,000
14 5-12
numerous several few few few very few
Them are numerous additional siting concerns. They are similar in nature for the various gas-fired alternatives,
and generally are site-s[:md fic and increase with scale - e.g. noise, total emissions, biological resources, cultural
$1100-1600
S28-$40 million
$.07-.0B
$600-5800
515-$20 million
$.08-.09
$1500-$3000
$38-$75 million
$.07-.10
Contractual,
Host Thermal Load
Cost
Major Constraining Factor in Palo Alto Siting Siting N/A
51200-$1700 $1100-1600
$30-$42 million $28-$40 million
$.06-.09 $.07-.08
Contractual,Contractual,Host ThermalHost Thermal Load Loads
High overall
effidency
Neuh’al impacts to
non-participants
Consolidated
customer
demand
Highest overall
efficiency
Highly effidant
electrical
~roduction
Dispersed
~peratiorml and
"~nandal risk and
benefits
Small customer
support
Good overall
effidency
Small unit footprint
Highly
dispatchable
Fast response
Local ~d
support
$100(%1300
$25-$33 million
$0.06-0.07
Siting,
Partners
Low co~ffkW for
high-effidency
~upply.
Regional grid
~uppor~
Market
35-40% Average
N/A
none
N/A
N/A
N/A
N/A
$0
$ .05 - .08
Simple
No land needed.
No initial
investment.
Needed for
,fficient operation.
Needed for sales of
~urplus power
NCPA and staff from CPAU and other municipal utilities investigated several power plant
alternatives that arose during the year. These included "Resource 500" (500 MW), Oakland
(180- MW peaking plant), Lodi Combined Cycle (250 MW) and Los Esteros Combined Cycle
(150 MW). Staffrecommends that at this time only the Los Esteros option wan’ants further
investigation, jointly with Santa Clara and others. Except for Resource 500, none of these
potential facilities would be on line in less than five years.
2006 Implementation #6: Clean Distributed Generation
Develop a long-term cogeneration implementation plan to capitalize on environmentally
friendly and cost-effective high-efficiency combined heat, power and cooling (CHPC)
opportunities at large customer sites that are compatible with the Comprehensive Plan.
Assist motivated large customers in evaluating technical and economic feasibility of
CHPC combined with energy efficiency, and in implementing cost-effective and
environmentally sound prospects. Establish standardized distributed generation
interconnection standards and procedures that leverage the groundwork of California
Public Utilities Commission Rule 21, and update retail electric and gas rates for small-
scale clean distributed generation. Continue to monitor technology costs and
opportunities for smaller renewable technologies, cogeneration and other low-impact
generation that can be located within Palo Alto.
2006 Implementation #7: Natural Gas-Fired Generation
*Redirect the local generation feasibility study CIP to focus on clean small-scale
distributed generation within Palo Alto (Task #6) and power plant oppommities outside
Page 12 of 16
of Palo Alto. Given regulatory uncertainty related to local capacity rules and uncertainty
of control area constraints, evaluate joint efforts toward power plant ownership
oppommities within and near the Greater Bay Area (consistent with levels listed in LEAP
Guideline #3B (25-50 MW).
2006 Implementation #8: Greater Bay Area Power Purchase Agreements
¯ Some contractual alternatives may be able to provide benefits sirnilar to power plant
ownership. There are cogeneration facilities and other "qualifying facilities" that that are
bale to sell output to Palo Alto rather than to others. In parallel with Task #7, pursue firm
energy and capacity supply contracts within the Greater Bay Area on either medium or
long-term basis. Conduct a Request for Proposals to solicit firm energy and capacity
offers from all sources within the Greater Bay Area, including renewables, cogeneration
and conventional generation.
High Value Oppommities (2003 #8, 2006 #9), Analytical Tools (2003 #9, 2006 #9)
Block Purchases (2003 #12, DONE - Laddering now established as element of#9),
Master Agreements (2003 #13 DONE- Laddering established as element of#9), and
Short Term Hedging Strategies STEAM (2003 #14 DONE - Now part of#9)
The block purchases, master agreements and short term hedging strategy development tasks were
all completed. In support of the Natural Gas-fired Generation task, staff worked with NCPA and
other public power agencies evaluating several power plant opportunities that developed during
the past year, at least one of which appears to have potential to achieve net benefits for Palo Alto
customers. Staff completed analysis of reducing P alo Alto’s interest in the Calaveras
hydroelectric facility, concluding that further consideration of a Calaveras layoff would be
premature, at least until more clarity on California’s market design rules and the resulting value
of Calaveras to Palo Alto is resolved. Staffrevamped its computer portfolio simulation models,
facilitating improved analysis of hydro and market price scenarios, their potential impacts on
resulting costs, and the robustness of different portfolio altematives to those scenarios. A
transaction database was implemented to improve tracking of market purchases and for sharing
information between the portfolio management and risk management functions. Staff also
developed sotb,vare to refine the hydro generation projections based on Western forecasts. Hydro
hedging alternatives including CHEX, weather insurance, and layoffs were all presented to the
UAC, with the result that financial reserves are a preferred means to manage the risks of large
retail rate fluctuations caused by low hydroelectric generation due to drought (now part of Task
#10)
2006 Implementation #9: Portfolio Management
¯ Continue to diversify energy purchases using the "STEAM" laddering strategy to
meet load, while continuing to remain cognizant of any cost-savings oppommities
that arise from time to time. Staff will continue to develop and maintain expertise and
analytic tools, models and other efforts to evaluate scenarios, new resource
opportunities, and impact of uncertainties on portfolio position and performance, with
an eye toward developing a mix of resources that balance cost, risk, reliability, and
the environment.
Page 13 of 16
Risk Mana,~ement (2003 #7, 2006 #10) and Reserves (2003 #11, 2006 #10)
CPAU Risk Management Policies have been updated (UAC September 2005, CMR:128:06), and
regular Quarterly Risk Management reports are now standard procedure for the UAC and
Council (CMR: 127:06). Internal infrastructure has been developed, and continues to evolve, for
more automatically tracking market transactions, market position, mark-to-market, credit
exposure, and other risks. Third party software and services for maintaining close tabs on
CPAU’s suppliers is in regular use, and the results including in the quarterly risk management
reports. Rate Stabilization Reserve policies were reviewed with the UAC in April 2005. The
impact of the frequency of changes in retail rate on reducing the amount of financial reserves
needed was discussed with the UAC in September 2005. UAC preferences were to maintain the
less frequent (annual) rate adjustment process, which favors higher reserves over more frequent
rate changes. Staffhas completed all but two of the 24 Audit recommendations related to utilities
risk management.
2006 Implementation #10: Risk Management
¯ Complete the last of the Utilities Risk Management Audit recommendations. Develop
improved transparent and streamlined Back Office process (contract administration
and settlements). Clarify surplus power wholesale sales procedures to ensure
transparency and the appropriateness of smplus energy commodity sales transactions
that are necessary to meet varying loads with varying and dispatchable electric
supplies. Maintain adequate reserves by recognizing the degree of uncertainty the
City faces in the future and periodically review and recommend appropriate level of
financial reserves.
Legislative, Regulatory and Transmission (2003 #10, 2006 #11 and #12)
Key legislative and regulatory issues are regularly updated in the UAC Quarterly Report. The
majority of bills concerning electric utilities failed to pass the Legislature in 2005, although
many will continue through 2006 as two-year bills. Two significant bills that were signed into
law in 2005 are AB 380 that deals with resource adequacy requirements, and SB 1037 that
mandates the loading order for energy efficiency programs. AB 380, by setting minimum
resource adequacy requirements based on WECC standards, has provided a potential stand-in to
the resource adequacy provisions proposed by the California Independent System Operator
(CAISO). Prior to SB 1037, the RMI evaluation of CPAU’s resource plan and recommendations
for further energy efficiency programs were completed and presented to the UAC, and a contract
has been awarded to E3, Inc. develop and integrated efficiency program design and reporting
tool. Further measures in compliance with the goals of SB 1037 are addressed in Task #3.
Anticipated for 2006 are legislative bills to increase renewable portfolio standards, extend
control over the energy efficiency programs of publicly owned utilities, andreduce greenhouse
gas emissions. Regulatory proceedings and decisions potentially affecting Palo Alto include the
California Solar Initiative (D.06-01-024), and greenhouse gas emissions reduction targets (R.04-
04-003).
Participation in the CAISO’s market restructuring stakeholder proceedings are coordinated with
NCPA, the Bay Area Municipal Transmission Group (BAMx), and the California Municipal
Page 14 of 16
Utilities Association (CMUA). Progress is being made in mitigating the financial and operating
impacts of the proposed market design, although much needs to be settled before the November
2007 implementation date of the CAISO’s Market Restructuring and Technology Update
CPAU and PG&E staff are close to finalizing a Facilities Study Plan for the evaluation of an
upgrade to 230 kV of CPAU’s connection to PG&E, which would reduce grid connection costs
for the City. Also being evaluated is a second 230 kV connection to enhance reliability and
reduce grid connection costs.
2006 Implementation Task #11: Local Interconnection
Evaluate transmission system upgrades to reduce cost and enhance reliability.
Investigate transmission connection voltage increase from 115 to 230 kV, and the
potential for a redundant transmission connection to west side.
2006 Implementation Task #12: Legislation and Regulation
¯ Monitor and participate in regulatory and legislative initiatives related to transmission
market design and pursue alternatives to increase reliability at a reasonable cost.
Continue to advocate transmission upgrades in to the Bay Area to increase reliability.
Establish a policy to address mandatory resource adequacy requirements.
RESOURCE IMPACTS
As commitments are made in implementing the LEAP Implementation Tasks, financial and
policy decisions will be brought to Council for approval as needed. The estimated cost elements
of these projects have been included in City’s long-term electricity cost projections.
Funding for the Local Generation Feasibility Study is included in CIP Project EL-06004. The
original CIP amount of $500,000 comprises an estimated $150,000 for Phase I and $350,000 for
Phase II. To date the project has encumbered $95,000 and spent $45,000, broken down as
follows:
Public Participation (TetraTech EM, Inc.) $40,000 ($5,000 spent)
Cogeneration potential (Rocky Mountain Institute) $20,000 ($17,000 spent)
Generation Resources Analysis (Navigant Consulting) $35,000 ($23,000 spent).
The major task areas in developing a cogeneration program and evaluating joint power plant
opportunities include, but are not limited to:
Public Involvement (communications, public forums and workshops, web)
Legal and Planning (contract development, regulatory compliance, siting)
Technical Engineering (economic, engineering, environmental studies)
POLICY IMPLICATIONS
The 2006 LEAP Implementation Tasks conform to the Council approved LEAP Objectives and
Guidelines. The plan is also in accordance with the Utilities Strategic Plan, Energy Risk
Management Policies, and Comprehensive Plan Goal N-9.
Page 15 of 16
ATTACHMENTS
A: Proposed 2006 LEAP Implememation Plan
B: LEAP Objectives and Guidelines approved by the Council November 2001/October 2002.
C: LEAP Implementation Plan, approved by Council in August 2003
D: Rocky Mountain Institute Final Report Executive Summary
PREPARED BY:Karl E. Knapp
Shiva Swaminathan
Ipek Connolly
Lindsay Joye
Brian Ward
Tom Kabat
Monica Padilla
Debra Lloyd
Bruce Lesch
REVIEWED BY:
Girish Balachandran, Assistant Director of Utilities
Tom Auzenne, Assistant Director of Utilities
DEPARTMENT HEAD:
Dil~tor, AdministratiVe Sevices
Page 16 of 16
2006 LEAP Implementation Plan Attachment A
Attachment A: 2006 LEAP Implementation Tasks
o
°
o
Climate Action: Promote environmental stewardship by completing the California Climate
Action Registry process for reporting and certifying greenhouse gas emissions, developing a
Climate Action Plan for utilities, and supporting City efforts to address climate change and
other environmental issues.
Public Benefits: Continue implementation of electric public benefits programs, which is
funded by collecting a fee equal to 2.85% of the electric retail rate. These funds are partially
used to demonstrate renewable resources or alternative technologies and to assist customers
in pursuing efficiency improvements. Coordinate Public Benefits program enhancements
with efficiency portfolio plan development (Task #3)
Efficiency Portfolio: Enhance the existing efficiency progams by developing a long-term
integrated resource efficiency portfolio plan that recog-nizes cost-effective ener~r efficiency
and load management as priority resources in the "loading order" for energy resources.
Design efficiency programs to account for the combined benefits of electric, gas, and water
efficiency savings (e.g. a horizontal clothes washer saves electricity, water and gas).
Leverage joint efforts with other public power providers via NCPA’s efficiency initiatives
and Public Benefits Committee. Enhance system efficiency through generation efficiency
improvements and electric distribution system enhancements to lower system losses. As
appropriate, additional funding for cost-effective efficiency progams will be recommended
to complement and enhance the existing Public Benefits progams. Develop retail rate
options that provide price signals to customers that encourage efficiency.
Renewable Portfolio: Acquire renewable energy resources to meet LEAP Guideline 6.
Strive to meet 2015 goals by 2010. Work closely with suppliers to meet their contract
obligations and to ensure that projects under construction are completed in a timely manner.
Participate in NCPA "Green Pool" joint procurement initiative to meet remaining needs.
PaloAltoGreen: Continue implementation of the Palo Alto Green program, a green pricing
product available on a volunteer basis to customers who wish to purchase a greater fraction
of green resources. Where feasible, secure eligible renewable energy supplies to meet both
the renewable portfolio investments and the needs of the Palo Alto Green pro~am. Evaluate
potential strategies to meet the solar portion of PaloAltoGreen with local solar resources.
Clean Distributed Generation: Develop a long-term cogeneration implementation plan to
capitalize on environmentally friendly and cost-effective high-efficiency combined heat,
power and cooling (CHPC) opportunities at large customer sites that are compatible with the
Comprehensive Plan. Assist motivated large customers in evaluating technical and
economic feasibility of CHPC combined with energy efficiency, and in implementing cost-
effective and environmentally sound prospects. Establish standardized distributed generation
interconnection standards and procedures that leverage the goundwork of California Public
Utilities Commission Rule 21, and update retail and wholesale electric and gas rates for
small-scale clean distributed generation. Continue to monitor technology costs and
opportunities for smaller renewable technologies, cogeneration and other low-impact
generation that can be located within Palo Alto.
A-1
2006 LEAP Implementation Plan Attachment A
Natural Gas-Fired Generation: Redirect the local generation feasibility study CIP to focus
on clean small-scale distributed generation (Task #6) and power plant opportunities outside
of Palo Alto. Given regulatory uncertainty related to local capacity rules and uncertainty of
control area constraints, evaluate joint efforts toward power plant ownership opportunities
within and near the Greater Bay Area (consistent with levels listed in LEAP Guideline #3B
(25-50 MW).
Greater Bay Area Contracts: In parallel with Task #7, pursue firm energy and capacity
supply contracts within the Greater Bay Area on either medium or long-term basis. Conduct
a Request for Proposals to solicit firm energy and capacity offers from all sources within the
Greater Bay Area, including renewables, cogeneration and conventional generation.
Portfolio Management: Continue to diversify energy purchases to meet load. Continue to
develop and maintain expertise and analytic tools, models and other efforts to evaluate
scenarios, new resource opportunities, and impact of uncertainties on portfolio position and
performance.
10. Risk Management: Develop improved transparent and streamlined Back Office process
(contract administration and settlements). Clarify surplus power wholesale sales procedures
to ensure transparency and the appropriateness of surplus energy commodity sales
transactions that are necessary to meet varying loads with varying and dispatchable electric
supplies. Maintain adequate reserves by recognizing the degree of uncertainty the City faces
in the future and periodically review and recommend appropriate level of financial reserves.
11. Local Interconnection: Evaluate transmission system upgrades to reduce cost and enhance
reliability. Investigate transmission connection voltage increase from 115 to 230 kV, and the
potential for a redundant transmission connection to west side.
12. Legislation and Regulation: Monitor and participate in regulatory and legislative initiatives
related to transmission market design and pursue alternatives to increase reliability at a
reasonable cost. Continue to advocate transmission upgades in to the Bay Area to increase
reliability. Establish a policy to address mandatory resource adequacy requirements.
A-2
Attachment B
Attachment B: Council Approved Electric Supply Objectives and Guidelines
The Ci.ty Council approved four Primary_ Portfolio Planning Objectives on November 13.
2001 (CMR:425:01)
Objective 1 :Ensure low and stable electric supply rates for customers.
Objective 2:Provide superior financial performance to customers and the City by
maintaining a supply portfolio cost advantage compared to market cost
and the retail supply rate advantage compared to PG&E.
Objective 3:Enhance supply reliability to meet City and customer needs by pursuing
opportunities including transmission system upgrades and local
generation.
Objective 4:Balance environment, local reliability, rates and cost impacts when
considering renewable resource and energy efficiency investments.
The City Council approved seven LEAP Guidelines on October 21. 2002 (CMR:398:02).
Guideline 1:Electric Portfolio Dependence on Western
While maintaining the flexibility to adopt favorable ’custom products’ offered by
Western, manage a supply portfolio independent of Western beyond the Base
Resource Contract.
Guideline 2:Hydro Risk Management
Manage hydro production risk by:
A.Planning for an average hydro year on a long-term basis;
B.Diversifying to renewable and/or fossil generation technologies; and
C.Maintaining adequate supply rate stabilization reserve.
Guideline 3:Market Risk Management
Manage market risk by adopting a portfolio strategy for electric supply
procurement by:
A.Diversifying energy purchases across commitment date, start-date, duration,
suppliers, pricing terms and fuel sources;
B.Targeting additional thermal plant ownership/investment commitment at -25 MW but in
no event more than 50 MW;
C. Maintaining a prudent exposure to changing market prices by:
Procuring resources at fixed price for at most 90% of expected load for 2 or more years out,
assuming average hydro conditions; and
Procuring resources at fixed price for at most 75% of expected load for 5 or more years out,
assuming average hydro conditions; and
D.Avoiding contract-based fixed price energy purchases (except for contracts for
renewable resources) for durations greater than 10 years.
B-1
Attachment B
Guideline
A.
B.
C.
D.
4:Reliable and Cost Effective Transmission Services
Ensure the reliability of supply at fair and reasonable transmission cost by:
Supporting, through political and technical advocacy and/or direct investment, the
upgading of Bay Area transmission to improve reliability and relieve congestion;
Participating in transmission market desi~o-n to ensure that market design results in
workable competitive markets and equitable cost allocation;
Pursuing the option of forming and/or joining a Public Power Transmission Control
Area to increase control over transmission operations and related costs; and
Ensuring PG&E honors the Stanislaus Commitments by providing to us firm-
transmission rights or equivalent.
Guideline 5:
Guideline 6:
Guideline 7:
Local Generation
Monitor the potential of local generation options to meet customer needs,
improve local reliability, minimize congestion and wheeling charges, and
stabilize/reduce costs.
Renewable Portfolio Investments
The City shall continue to offer a renewable resource-based retail rate for all
customers who want to voluntarily select an increased content of renewable
energy. In addition to the voluntary program, the City shall invest in new
renewable resources to meet the City’s sustainability goals while ensuring that the
retail rate impact does not exceed 0.5 C/kWh on average. Pursue a target level of
new renewable purchases of 10% of the expected portfolio load by 2008 and
move to a 20% target by 2015, contingent on economic viability. The contracts
for investment in renewable resources are not to exceed 30 years in term.
Electric Energy Efficiency Investments
Offer quality Public Benefits programs, utilizing funds collected through
the 2.85% Public Benefits charge embedded in electric retail rates, to meet
the resource efficiency needs of customers. Additional funding for cost-
effective programs will be recommended as appropriate. Pursue these
investments by:
A.Providing expertise, education and incentives to support cost-effective customer
efficiency improvements;
B.Demonstrating renewable and/or alternative generation technologies and new
efficiency alternatives; and
C.Providing rate assistance and efficiency pro~ams to low-income customers.
B-2
Attachment C
Attachment C:2003 LEAP Implementation Plan
Approved by Council August 2003 (CMR: 354:03)
Recommended Implementation Plan - Long-Term Portfolio
Acquire renewable energy resources to meet LEAP Guideline 6. The first step is to issue
a Request for Proposals (RFP) to potential suppliers. NCPA is coordinating this activity
as many of its members have an interest in acquiring new renewables for the post-2004
period. The RFP was issued on March 11, 2003 with responses due in mid-April.
Depending on the responses to the RFP, staffwill request UAC and Council approval to
execute long-term contracts for renewable supplies.
o
Implementation of the Palo Alto Green program, a green pricing product available on a
volunteer basis to customers who wish to purchase a greater fraction of green resources.
This program was reviewed and approved by the UAC at its February 2003 meeting and
was approved unanimously by the Council Finance Committee on March 4, 2003. It is
expected to go to the Council for approval on April 21, 2003
Continue implementation of Public Benefits programs, which is funded by collecting a
fee equal to 2.85% of the electric retail rate. These funds are partially used to
demonstrate renewable resources or alternative technologies and to assist customers in
pursuing efficiency improvements.
Staff will continue to evaluate additional opportunities for investment in efficiency
improvements. As appropriate, additional funding for cost-effective efficiency progams
will be recommended.
°While continuing to monitor opportunities for participation in gas-fired generation as
they arise through staff’s contacts in the market and at NCPA, prepare an RFP to
formally announce to the market Palo Alto’s interest in investing in thermal generation
resources or its "look alike" (i.e. tolling contracts).
°Monitor technology costs and opportunities for smaller renewable technologies,
cogeneration and gas-fired generation that can be located within Palo Alto and!or at
customer sites. A study funded by the California Energy Commission, Palo Alto, and
other municipal utilities is currently underway to identify sites within Palo Alto that have
high value to the electrical distribution system.
Continue to discuss gas tolling options with suppliers. Gas financial instruments will
allow staff to most effectively use tolling contracts, therefore, staff will investigate using
these products and, if attractive, will pursue approval from the Council to add these
products to the list of approved products in the Energy Risk Management Policies.
Pursue any low-cost, high value prospects to acquire supply-related resources that may
arise from time to time. Staff monitors on an ongoing basis any opportunities such as
C-1
Attachment C
availability of additional below-market hydroelectric production or access to additiona!
power or transmission due to ownership of existing assets.
Refine the analysis and collect additional market information to evaluate scenarios when
various portfolio elements would have value. Staff will solicit current market
information on specific products such as hydro hedges. Additional analysis will include
sensitivity analysis and stress testing of the portfolios.
10.Monitor and participate in regulatory and legislative initiatives related to transmission
market design, support Bay Area transmission upgrades, and pursue alternatives to
increase reliability at a reasonable cost
11 .Maintain adequate reserves by recognizing the degree of uncertainty the City faces in the
future. Evaluate modifying the policy or targets to make certain that the Supply Rate
Stabilization Reserve is adequate to ensure stable rates in an environment of uncertainty
and consider potential guidelines such as being able to maintain stable rates in the event
of two dry years in a row.
Recommended Implementation Plan - Short- and Medium-Term Portfolio
1.To reduce short-term cost variability and to ladder the purchase commitments, while
leaving sufficient flexibility to commit to long-term resources, three fixed-price block
purchases are recommended for execution in year 2003:
Block 1
(2005-2007)
Block 2
(2005-2006)
Block 3
(2005)
on-pk
off-pkX
on-pk
off-pk
on-pk
off-pk
Jan Feb
X X
X
Mar Apr May
X
X
Jun Jul Aug Sep Oct
X X
X X
X X
NOVx[ DeCx
X X
X X
X X X X X X X X X X X X
At current market prices, the expected cost of the first two blocks of power is as follows:
a. about $16.4 million for Block 1 (4.3 C/kWh);
b. about $4.5 million for Block 2 (5.57 C/kWh); and
c. about $6.3 million for Block 3 (5.1 C/kWh). This purchase will be completed as
a term transaction via the Northern California Power Agency (NCPA) under the
authority delegated to the City Manager by Council to execute transactions up to
$20 million per fiscal year in conformance with the NCPA Pooling Agreement
(CMR:135:03 on March 3, 2003).
2.Seek Council approval of a set of master agreements with suppliers by summer or fall
2003 with the authority to transact for terms of up to 3 years out. Any transactions
outside this limit will be brought to the UAC and Council for approval.
3. Develop short-term hedging strategies and operations plans with the objective of:
a. Clearly identifying and capturing supply needs and supply portfolio risks;
C-2
Attachment C
b. Whenever possible, utilizing simple tools to manage risks and utilizing NCPA
resources and expertise; and
c. Managing the electric portfolio to achieve the portfolio objectives with
streamlined operations to minimize overhead costs and to act expeditiously,
while maintaining the appropriate level of oversight and control.
o Evaluate, design, and pilot a customer demand-response program. If such a program
makes sense, develop and implement a customer demand-response program to protect
against high congestion costs and to be part of new capacity, reserve requirements that
are likely to be imposed.
(2-3
Attachment D
Executive Summary
Background
Prior to 2005, the City of Palo Alto Utilities (CPAU) purchased approximately 95% of the city’s
electricity supply needs from the Western Area Power Administration (Western). CPAU’s access
to this inexpensive, predictable and reliable source of energy changed significantly with the
expiration of its contracts with Western and PG&E on December 31, 2004. On this date, a new
contract entered into force, providing CPAU with a fixed percentage of Western’s hydroelectric
generation output, as opposed to a fixed amount of energy per year. This change led CPAU to
identify new electricity resources to replace the reduced Western allocation, which in turn led it
to undertake a new approach to comprehensive resource planning. CPAU developed and is
implementing its Long-Term Electric Acquisition Plan (LEAP).
Rocky Mountain Institute (RMI) was engaged in late 2004 to apply its Energy Resources
Investment Strategy (ERIS) methodology to evaluate the potential for CPAU to develop local
resources, including energy efficiency and local generation options. The ERIS approach builds
on the principles of integrated resource planning and seeks to realize the least-cost mix of energy
resources for a community. It starts with a detailed analysis of existing resources, as well as
forecasts of future costs and demand. It also identifies the costs and available potential for
various types of new generation capacity, as well as for improvements in end-use efficiency and
demand response. Energy savings through energy efficiency measures, or ’Negawatts,’ are
considered as an equivalent resource to new generation capacity, or ’Megawatts.’ These supply
and demand-side resources are then compared in a consistent economic framework and ranked
by cost-effectiveness.
The bottom-up approach of ERIS accounts for the local transmission and distribution (T&D) grid
costs, line losses, and potential savings associated with each resource option. It also considers the
time required to realize these investments. The results of the ERIS analysis provide guidance for
developing a portfolio composed of energy resources with the lowest overall cost, while also
adjusting for risks associated with each resource option. These risks include fuel prices, emission
costs, technology performance, etc.
RMI Analysis of CPAU’s Current Electric Resource Plan
RMI began by analyzing the current state of CPAU’s resource plan, including the Utilities
Strategic Plan and the LEAP objectives, guidelines and implementation plans. The LEAP
portfolio planning objectives comprise one of the clearest "mission statements" for a utility that
RMI has seen to date. It establishes the City’s least-cost planning criterion in terms of customer
rates, costs compared to PG&E and the power markets and, by inference, dependable transfers to
the General Fund. At the same time, it identifies other non-monetary (or difficult to monetize)
goals such as customer service, reliability, and environmental quality and health.
Minimizing future supply costs while balancing risk, reliability, and environmental stewardship,
the central tenets of LEAP, is a complex process, as CPAU is exposed to risks associated with
uncertainty of power market prices, gas prices, hydroelectric production and cost, transmission
congestion and resulting costs, technology performance and cost, regulatory changes in
5
Executive Summary
California and nationally, environmental regulations and costs, and other uncertainties. As
CPAU has already observed, managing costs in this uncertain environment demands a portfolio
approach, in order to diversify risks and to build in responsiveness to future uncertainty and
plausible departures from the business-as-usual course. In this project, RMI was tasked with
identifying robust solutions that balance cost, risk, reliability, and environmental stewardship,
and suggesting strategies to achieve this balance.
Results: Integrated Portfolio for CPAU
The Integrated Marginal Total Resource Cost Curve:
The principle way to summarize and display the results of an ERIS study is the integrated
marginal total resource cost curve, shown by Figure 1 for CPAU.
$0.09
$0.08
~ $0.07
,0.06
$o.os
i $0.04
so.oa
$0.02
$o.ol
$0.00
150
CPAU Integrated Marginal Cost Curve, 2015
$6,00 per MMBtu Gas
Integrated Marginal Cost Curve
¯Combined Cooling, Heating, and Power
¯Energy Efficiency
Bay Area Combined Cycle Plant: $0.07!/kWh
x Outside Bay Area Combined Cycle Plant: $0.067/kWh
--¯--Combined Cycle Plant in Palo Alto: $0.062/kWh
-~-- 25 MW Cogeneration Plant in Palo Alto: $0.060/kWh
300 450 600
Annual Electricity Saved or Generated (GWh)
Figure 1: CPAU integrated marginal cost curve (central generation alternatives assumed to
be 25 MW share owned by CPAU), based on -$6/MMBtu gas price
Figure 1 shows the result of combining estimates of cost and performance for both efficiency
potentia! and generation options, which were estimated in separate analyses (described below).
Figure 1 shows the estimated ultimate cumulative resources available to CPAU between now and
2015 l, sorted by levelized total resource cost.2
1 The accuracy of the results as shown is limited by the data available for the analysis. The results are RMI’s
estimates of potential resource performance and costs for CPAU; actual potential may be lower (due to difficulty in
realizing potential customer-sited efficiency measures or CCHP projects) or higher (due to improved technology), or
distributed differently along the marginal cost curve.2 The total resource cost (TRC) measures a supply or demand-side resource’s cost to all customers, including the
full cost of the technology, whether paid by the utility and/or participating customers, plus any additional utility
program administrative costs. The TRC does not account for utility-customer transfers such as incentive payments
Executive Summary
The results shown in Figure 1 assume a wholesale gas cost of approximately $6 per MMBtu. The
marginal cost results are highly sensitive to this assumption, as shown by the high-gas cost
scenario in Figure 2. With gas at $12/MMBtu, the relative ranking of the resources considered
changes only minimally, although the absolute costs of these generation options are considerably
higher (the dotted line in Figure 2 traces the marginal cost curve with $6/MMBtu gas for
comparison).
$0.14 F
$0.12
~$O.lO
$0.08
~. $0.06
$0.02
$0.00
CPAU Integrated Marginal Cost Curve, 2015
$12.00 per MMBtu Gas
150
J
I
!
I
I
t
300 450 600
Annual Electricity Saved or Generated [GWh)
750
Figure 2: CPAU integrated marginal cost curve, based on $12/MMBtu gas price.
As shown both in Figure 1 and Figure 2, CPAU’s least expensive resource potential resides in
the lowest-cost increments of energy efficiency potential. RMI estimates that approximately 70
GWh per year of efficiency potential are available at costs of$0.01/kWh - $0.05ikWh, lower
than the least-expensive new generation option. These energy savings amount to approximately
7% of CPAU’s total electric energy load, enough to keep Palo Alto’s total electric load constant
or slightly below current levels.
It should be noted that the efficiency potential shown is RMI’s estimate of today’s tota!
efficiency potential in CPAU territory, based on the energy end-uses and building types for
which we had detailed data. This total potential should be distinguished from achievable
potential, or the level of efficiency that CPAU could realistically capture during a given
and bill savings. Capital and operating costs are levelized on an annual basis and divided by the annual kWh
production or savings to arrive at a S/kWh value.
7
Executive Summary
timeframe. While it is unlikely that every CPAU customer would implement all efficiency3
measures under a given levelized cost, it is likely that other, slightly more costly measures
would be implemented by some customers as parts of more comprehensive efficiency upgrades,
or that additional savings would be realized in end-uses or buildings that we did not include
(such as R&D facilities). Additionally, the total existing efficiency potential is based only on
technologies that are currently commercially available. In coming years, additional technologies
will come to market that will both increase the total efficiency potential, and increase the
potential that is available at a given cost.
For these reasons, RMI considers achieving gains in efficiency in the neighborhood of 70 annual
GWh, at costs at or below $0.06ikWh, to be an achievable, albeit ambitious, target over ten
years. Achieving such a target will take time and well-designaed programs. This need for time to
implement programs is a primary reason for specifying 2015 as the endpoint year considered in
the analysis summarized in Figure 1. By then, ten years will have elapsed, giving CPAU
adequate time to implement energy efficiency programs to save this share of total load. Less total
potential is realistically achievable in earlier years.
After these lowest-cost increments of energy efficiency potential, approximately 23 MW of
combined cooling, heating and power (CCHP) systems, located at five of CPAU’s largest
customers’ sites, are the next lowest-cost resource, followed by the least-expensive central
generation option. In all cases, RMI’s analysis assumed utility ownership of generation
resources, including CC’2-1P sited at customer facilities. RMI estimates that up to 25% of CPAU’s
annual load, or approximately 270 GWh per year, could be served by this combination of
efficiency and customer-sited CCHP, at levelized total resource costs below $0.06/kWh.
The two least expensive central generation options, which we consider mutually exclusive, are a
conceptual 25 MW cogeneration plant and a 25 MW combined cycle plant, both assumed to be
located in or near Palo Alto, but with no specific location or specific potential thermal host loads
identified. The next least expensive resources are additional energy efficiency and CCHP
systems located at other, smaller customers’ sites. Above this cost level, marginal costs increase
very rapidly.
In all, approximately 600 annual GWh of local supply and demand-side resources are estimated
to be available over the next ten years at costs at or below $0.062 per kWh. This total includes
roughly 90 GWh of cumulative efficiency, 300 GWh from 35 MW of CCHP, and up to 220
GWh from a 25 MW central eogeneration plant in Palo Alto or one of the other central
generation options4. Together, these local resources amount to about 60% of CPAU’s current
total annual load, and more than 50% of the projected 2015 load (before efficiency savings).
3 Note that the costs of efficiency resources shown in Figure 1 are the marginal costs of each individual measure.
The average costs of multiple measures, grouped by end-use or customer type, would be lower than the highest
margina! measure cost, and the average cost of all measures with a marginal cost less than $0.09/kWh would still
be less than $0.05/kWh. Thus, including some more costly measures to achieve a saving target should not diminish
overall economic performance substantially.4 Note that these annual energy totals include (mostly off-peak) market electricity that we assume CPAU will
purchase whenever local generation and/or CCHP are not operating at full output, in order to compare the costs of
providing an energy product of equivalent value.
Executive Summary
Least-Cost Integrated Resource Portfolio:
With the most cost-effective local resources identified, we explored the implications of adding
these resources to the CPAU portfolio between now and 2015. The existing plan can meet an
annual load of about 1,050 GWh with the following supply resources:s
°130 GWh/year (in an average year) from the Calaveras hydroelectric plant;
°380 GWh/year (in an average year) from Western Area Power Administration under
contract through 2024;
¯190-210 GWh/year (20% of supply, depending on the amount of efficiency that will be
implemented) of wind and other planned renewable sources; and
¯As of 2005, the remaining need for 330 GWh/year or more is being met by a combination
of long-term contracts and spot market purchases,
These planned resources, and the resulting resource deficits in three types of hydrological years6
(dry, normal, and wet), are shown in Figure 3.
Current CPAU Resource Portfo~o, 2015
90%
8O%
70%
60%
50%
4o~o
30%
20%
lO%
D%
’
I!
Dry Average Wet
Year Type
~_lDefidt
I Renewables
~, Cala vera s
Western
Figure 3: Current resource portfolios for CPAU in 2015, for a range of hydrologic
conditions
Figure 4 shows the result of adding the most cost-effective efficiency and CCHP resources to
this 2015 portfolio, to form the least-cost integrated resource portfolio. No new central
generation resource is assumed in Figure 4. Specifically, Figure 4 assumes that CPAU
s This load is assumed to be growing at less than 0.5% per year before considering savings from new efficiency
Programs.
The dry year’s hydroelectric production is exceeded in 90% of all years, the normal year’s in 50%, and the wet
year’s in 10%.
Executive Summary
implements demand-side programs to capture 70 GWE!y of the least expensive energy efficiency
potential, and installs approximately 23 MW of local CCHP systems that would produce a total
of approximately 180 GWh/y of net electricity] If more detailed analyses show CCHP systems
to not be feasible, it may be appropriate to consider one of the larger, central resource options.
Under this portfolio, in a normal year the remaining deficit that would need to be met by market
purchases is only about 110 GWh/y or 10% of total load, while in a dry year it increases to about
300 GWh/y or 30% of the total. In a wet year, local resources are sufficient such that any
resulting surplus could be exported into the electricity market.8
120%
Electricity Resources, 2015
lOO%
~0%
40% " --
; - 30%
FDDeficIt
!,~:Surplus CCHP
Large Customer CCHP
Efficiency
Renewables
Calaveras
Western
O%
Dr7 Average Wet:
Year’l~pe
Figure 4: Integrated resource portfolios for CPAU in 2015, for a range of hydrologic
conditions, showing the contributions of existing and planned new renewable sources,
together with potential least-cost energy efficiency and large customer CCHP resources
The best way to provide for the need that would remain in drier-than-average years is not
obvious. Neither long-term market purchase contracts nor capital-intensive local resources (such
as a local combined cycle plant) would be ideal, although the advantages improve if CPAU were
to reduce its dependence on hydro supplies (such as a reduced interest in Calaveras). On the
other hand, exposure to spot market prices in dry years could be costly. This hydrologic risk is
currently managed with financial reserves.
7 This value does not include any off-peak market purchases when the CCHP systems would not be running.8 This annual balance does not account for the variations in monthly patterns or differences in on peak and offpeak
periods. For example, even with a perfect balance between annual energy demand and supply, Palo Alto would
exhibit surplus energy approximately half the year and deficit the other half, and surplus power in some months
during offpeak periods but deficit in on peak periods.
10
Executive Summary
One local option with a relatively low capital cost would be a local peaking combustion turbine
plant, which would provide capacity but not many annual GWh. Although its relatively high heat
rate (lower efficiency) would result in higher costs per kWh produced, it might still be less costly
than generic market power, particularly during dry years when shortages of hydro power may
push market prices higher. This higher heat rate would also result in higher levels of emissions
on a per-unit energy basis, as compared to a combined-cycle or cogeneration plant, though the
carbon intensity would still be slightly lower than the average carbon intensity of market power
in California, and could result in lower total emissions compared to other infrequently dispatched
resources that will be needed to fill Palo Alto’s time-varying power deficit. Thus, operating such
a plant at a capacity factor of 0-30% could be cost-effective and still sensitive to the
environment, particularly if CPAU needs additional capacity, but not energy, to meet future
resource adequacy standards of the California ISO.
If CPAU were to implement the most cost-effective resources that RMI has identified, i.e., about
600 GWh/y of central and local supply and demand-side resources with total resource costs
under $0.062/kWh, CPAU could supplement its hydroelectric and other planned renewable
sources with local resources only and meet its full 2015 load, even in a dry year. This scale of
investment in local resources would lead to energy surpluses in most years, requiring CPAU to
let resources stand idle or sell into the market even when prices may not be favorable. There
appear to be less expensive options to manage supply risk, including carrying adequate financial
reserves to ride out the cost variations in dry years, or possibly partnering with another utility
with a complementary need.
Carbon Dioxide Emissions:
Electricity generated by most of the local resources considered for the integrated resource
portfolio would produce relatively lower levels of carbon dioxide emissions than the plants
generating electricity for purchase on the market. Of course, energy efficiency provides energy
savings with no direct emissions, and although CCHP relies on natural gas fuel, it produces
electricity with a lower COn emission intensity than other fossil fuel-fired generation sources,
due to the improvement in net heat rate (efficiency) from boiler fuel savings and cooling
electricity savings (see Table 1).
Table 1: Carbon intensities of CPAU suppl
Resource
Average Market Carbon Intensity
Outside Bay Area Combined Cycle Plant
Bay Area Combined Cycle Plant
Combined Cycle Plant in Palo Alto
Combustion Turbine Plant in Palo Alto
Central 25 MW Cogeneration Plant in Palo Alto
Large Customer CCHP 4.5 MW
Mid-Sized Customer CCHP 12 MW
Small Customer CCHP 6 MW
Energy Efficiency
,-side resource options
Carbon
Intensity
(short
tCO2/MWh)
0.62
0.46
0.46
0.46
0.58
0.40
0.35
0.38
0.44
0.00
Cost Impact of
Emissions at
$8.2/short tC02
($/MWh)
$5.07
$3.78
$3.78
$3.73
$4.75
$3,29
$2.86
$3.09
$3.60
$0.0o
11
Executive Summary
CO2 emissions from the local supply and demand side resources added into the integrated
resource portfolio are about 66% less than the emissions from market electricity, which has an
average carbon intensity of 0.62 short tons per MWh of electricity purchased.9 Note that,
throughout the economic analysis, the model assigned a cost of $30 per short ton-Carbon ($8.20
per short ton-CO2) tO each generation resource. 10 This ’,adder" is based on the financial risk from
the uncertain future potential regulation of CO2 emissions, not an environmental externality. This
adder affects the relative positions of resources on the marginal total resource cost curve only
slightly, as in the fuel price sensitivity case. It improves the relative economic performance of
customer-sited CCHP systems slightly more than that of central generation options, due to the
lower net heat rates of CCHP.
Since the remainder of CPAU’s annual load could be met by existing hydro and other renewable
sources of power, the full integrated portfolio emissions would be 81% less than emissions from
market electricity in a normal year, as shown in Table 2. At $8.2/ton-CO~, the cost of offsetting
carbon emissions associated with the balance of CPAU electric supply would be about $1
million/year. Dry year emissions would still be 63% less than market energy, and wet year
emissions would be almost zero, except for the generation needed to balance supply and demand
within the month and in real time, and any emissions from running CCHP systems, the energy
from which would nearly always be surplus and sold to the market.
Table 2:CO2 emissions from CPAU resource portfolios in 2015
Resource
Western
Calaveras
Renewables
Efficiency
Large Customer CCI-IP
Market Purchases or Local
Combustion Turbine
Total Emissions:
Emissions at Market Carbon Intensity
Reduction by CPAU (as a % of
emissions from 100% market purchases)
Dry (10%) Year Normal Year Wet (90%) Year
CO2 emissions (thousand short tons per year)
0
0
0
0
6O
180-190
240-250
0
0
0
0
60
60-70
120-130
700
o
0
0
0
3
0
63%81%100%
9 USDOE/EIA "Carbon Dioxide Emissions from the Generation of Eleca’ic Power in the United States," July 2000,
Washington, DC, htm.:l/www.eia.doe,gov/cneaf/electrici~./page/co2 report/co2emiss.pdf. This emission intensity
value is for the Pacific region, and it includes generation outside of Northern California. The reason for using this
value, rather than an average intensity for just the PG&E territory, which would be lower due to PG&E’s greater
reliance on hydro and nuclear sources, is twofold. First, power market purchases are supplied by the entire western
pool, not just the nearest utility with which the transmission connection is made. Second, emission changes resulting
from cogeneration or energy efficiency are based on the intensity of the marginal generation resources, which are
mostly gas-fired sources and would never be hydro or nuclear. An intensity of 0.62 ton-CO2/MWh corresponds to
that of a combustion turbine with a heat rate of 10,750, and thus it is a realistic value for both the marginal and the
average emission intensity of the default alternative electricity resource.
10 On April 7, 2005, the CPUC adopted the final imputed costs for CO2 emissions to be used by the utilities as the
"greenhouse gas adder" in long-term planning and procurement: a net present value of $8 per ton CO~, escalating at
5%/year, based on a cost stream of $5 per ton CO2 in the near term, $12.50 per ton CO2by 2008, and $17.50 per ton
CO2by 2013 (CPUC Decision 05-04-024, Conclusion of Law 7).
12
Executive Summary
Details on Demand-Side Resources
As a fast step in assisting CPAU to identify high-impact strategies for improving the
effectiveness of efficiency investments, RMI conducted top-down estimates of efficiency
potential in CPAU territory for gas and electric end uses in both residential and commercial
sectors. RMI also conducted a study on efficiency program design, identifying best practice
programs from utilities across the country, and suggesting elements of program design that
would be appropriate for CPAU (the full report from this study is included as Appendix 1).
Additionally, RM1 facilitated a workshop with CPAU staff to address the question of what
economic criteria are most appropriate for evaluating the cost-effectiveness of efficiency
programs. Details on this workshop are included in Appendix 2 of this document.
Intensified investment in energy efficiency within CPAU territory appears beneficial for several
reasons. The costs and risks of conventional and alternative supply sources are increasing due to
the expiration of CPAU’s previous contacts for fn’m power from Western and PG&E, the
increasing volatility in the power, fuel and emissions markets, and ongoing regulatory change.
Additionally, efficiency limits the dependence upon, and therefore the environmental impacts of,
all supply resources. Cost-effective efficiency programs aim to reduce customer bills, despite a
possible small increase in average rates.
Efficiency Potential."
Table 3 summarizes the building types and energy end uses with the most significant efficiency
potential, as determined by RMI’s analysis.
Table 3: Summary of recommended areas of focus for efficiency programs
Sector Recommended Areas of Focus
Commercial Electric
Residential Electric
Commercial Gas
Residential Gas
Interior lighting in office buildings
Refrigeration in grocery stores
Interior lighting
Pool pumps and motors
Heating in office buildings
Cooking in restaurants
Water heating in all building types
Water heating in older (pre-1979 construction)
houses; both multi-family and single-family
Space heating in older single-family houses
In all, over 600 measures targeting electric efficiency in the commercial sector were evaluated,
along with just fewer than 100 in the residential sector. For gas efficiency, RMI evaluated over
250 measures in the commercial sector and over 100 in the residential sector. These measures,
their relative efficiency potential and costs, are based on a series of reports by Kema-Xenergy,
Inc~ ~. Table 4 lists the "top ten" electric efficiency measures with the highest estimated
efficiency potential and costs at or below $0.06 per kWh.
11 The studies were all produced by Kema-Xenergy, Inc. of Oakland, CA: California’s Secret Energy Surplus: The
Potential for Energy Efficiency, 2002, California Statewide Residential Sector Energy Efficiency Potential Study,
2003, and California Statewide Commercia! Sector Natural Gas Energy Efficiency Potential Study, 2003
13
Executive Summary
Table 4: Top ten electric efficiency measures at or below $0.06/kWh, ranked by savings
potential (40% of the total efficiency potential at or below this cost)
Rank [ Efficiency Sector Building End Use Measure Description!Potential Type Targeted
1
2
3
4
5
6
7
8
9
G Wh/year
7.9
4.3
2.5
2.5
2.0
2.0
1.8
1.8
1.7
1.7
28
Residential
Residential
Commercial
Commercial
Commercial
Commercial
Residential
Commercial
Residential
Commercial10
TOTAL
Existing Lighting CFL, 2.5 hr/day
Existing Lighting CFL, 6.0 hr/day
Grocery Refrigeration High-efficiency fan
motors
Office Network PowerOfficeEquipmentManagement Enabling
Interior Retrofit 2-1amp 8-ftOfficeLightingfixture, lamps and ballast
Interior Retrofit 4-1amp 4-ftOfficeLightingfixture lamps and ballast
Existing Pool High Efficiency Pool
Pump and Motor
Office Cooling Centrifugal Chiller, 0.51
kW/ton, 300 tons
Double Pane Clear
Cooling Windows to DoubleExisting(central)Pane, Med Low-E
Coating
Interior Retrofit 2-1amp 4-ftOfficeLightingfixture laint and ballast
Levd~ed
Cost
S/kWh
$0.026
$0.034
$0.034
$0.009
$0.060
$0.034
$0.026
$0.0t7
$0.017
$0.060
Table 5: CPAU cumulative efficiency potential by sector
Levelled Total Resource
Cost(S/kWh saved)
$0.03
$0.04
$0.05
$0.06
$0.O7
Total
Residential
9.2
17.1
17.3
19.4
19.8
82.8
Commercial
32.4
41.1
54.0
54.9
70.9
253.3
Total
41.6
58.2
71.3
74.3
90.7
336.1
14
Executive Summary
CPAU Cumulative Efficiency Pote~Ual by Sector, at Various lqarginal Costs
< $0.03 < So.04 <
Le~ellzed Total Resaurc, e C~ (S/kWh)< $0.07
Figure 5: CPAU cumulative efficiency potential by sector
¯Comml~rclal
Total
As previously mentioned, RMI estimates that some 70 GWh of annual electric efficiency
potential exist in CPAU territory at levelized total resource costs below $0.06 per kWh. Table 5
Figure 5 shows the estimated electric efficiency potential available to CPAU, by sector, at
various marginal levelized total resource costs.
We also estimate that there are 4.5 million annual therms of gas efficiency potential at costs
below $0.65 per therm and 5.6 million annual therms at costs below $1.00 per therm, as shown
in Figure 6. Table 6 lists the "top ten" gas efficiency measures with the highest estimated
efficiency potential and costs at or below $1.00 per therm.
15
Executive Summary
CPAU Gas Efficiency Marginal Cost Curves
Efficiency Measures With Costs Below $1.00 / Therm
$1.00
$0.80
,0.4o
$0.20
Figure 6: CPAU gas efficiency levelized marginal total resource cost curve
Table 6: Top ten gas efficiency measures at or below $1/therm, ranked by savings potential
(49% of total 5.6 million therms of efficiency potential at or below this cost)
Rank
1
2
3
4
5
6
7
8
9
lO
TOTAL
Efficiency r
Potential
~erm~yr
620,000
482,000
302,000
285,000
234,000
221,000
177,000
169t000
154,000
151,000
~79~000
Sector
Commercial
Commercial
Residential
Residential
Commercial
Commercial
Commercial
Residential
Residential
Commercial
Building
Type
Office
Office
SF pre-79
MF pre-79
Hospital
Restaurant
Restaurant
MF pre-79
SF pre-79
Other
End Us~
Targeted
Heating
Heating
Water
Heating
Space
Heating
Water
Heating
Cooking
Cooking
Water
Heating
Space
Heatin9Water
Heating
Measure
Double Pane Low
Emissivity
High Efficiency
Furnace/Boiler 95% Elf
SE Horizontal Axis CW
Tier 2 (EF=3.25)
Wall 2x4 R-0 to Blow -
In R-13 Insulation (.86)
Solar Domestic Hot
Water System, Active
InFrared Fryer
Infrared Conveyer Oven
SE Horizontal Axis CW
Tier 2 (EF=3.25)
Wall 2x4 R-0 to Blow -
In R-13 Insulation (.86)
Solar Domestic Hot
Water System, Active
Levelized
Cost
$/therm
$o.o5
$0.24
$0.98
$0.63
$O.lS
$0.22
$0.90
$o.1o
$0.82
$0.29
16
Executive Summary
Efficiency Program Design:
Innovative design and effective implementation of efficiency programs will be crucial to
realizing CPAU’s efficiency potential. RMI’s analysis of best-practice programs around the
country (Appendix 1) yielded the following recommendations for specific program design
elements that appear to offer high value for CPAU:
¯Continue to enhance on-going CPA Uprograms.
°Consider commissioning and building operator training programs.
°Develop integrated programs to target a specific sector within a rate class.
¯Coordinate/partner with neighboring utilities to leverage marketing efforts.
¯Consider gas efficiency and combined resource (including water) programs.
¯Create an integrated package of services, (i.e. site audit, technical assistance, and
financial assistance) to lower perceived barriers and encourage implementation.
¯Consider innovativefinaneing strategies such as on-bill financing and performance
contracting.
¯Develop a "building as a system" approach to implementing efficiency projects.
¯Treat low-income efficiency programs as alternatives to increased subsidies of energy
purchases by these customers.
Economic Criteria for Efficiency Investments:
CPAU’s Strategic Plan identifies low and stable rates and low customer bills as important goals,
as well as the preservation of a supply cost advantage compared to the market place and
delivering valued products and services.
Least-cost plarming principles would suggest maximizing efficiency improvements up to the full
long-run marginal supply costs. Cost-effective efficiency from this "Total Resource Cost"
perspective reduces the average customer bill but can often cause a slight increase in rates
associated with the utility’s fixed costs. Typically, the "least-rate" approach tends to
underestimate economic efficiency potential from a total resource cost, or total community
viewpoint, which aims to reduce total customer bills, and to forego efficiency investments that
cost less than the marginal cost of supply resources. The CPAU strategic plan dictates low rates,
but does NOT exclude small rate increases for efficiency investments that lead to lower bills. For
efficiency programs, it can be very hard to get zero rate impact, but it is relatively easy to avoid a
significant rate impact.
Thus, for efficiency program design, we recommend using the total resource test as the criterion
for measure and program cost effectiveness. On the supply side, it is important to account
comprehensively for avoided costs, including transmission and distribution costs, line losses,
reserve capacity, and future emission costs. Efficiency programs should be designed to be as
inclusive as possible, so that there are relatively few customers who are non-participants that
absorb fixed program costs without benefiting from savings. Lastly, The Utility Cost, Participant,
and Rate Impact perspectives should be balanced to ensure lower average bills and sufficient
incentives to achieve participation, but not so much as to encourage free riders, to prevent any
undue burden on customers, and to promote equity.
17
Executive Summary
Demand response:
CPAU is already implementing demand response based on voluntary curtailments by certain
large customers. While there may be potential to expand demand response programs to include
smaller customers, dynamic pricing, and/or automated control technology, several factors likely
limit the cost-effectiveness of such potential:
¯CPAU’s load profile is relatively flat, with relatively little ability to shift load from peak
to off-peak;
¯Because of the very mild climate, CPAU does not experience a steep on-peak load spike
compared to inland areas that have higher loads from commercial and especially
residential air conditioning;
¯Due to the above two factors, the demand response yield, in terms ofkW/customer
shifted, woutd be relatively low, which would make the cost, in terms of $/kW shifted,
relatively high;
¯CPAU has relatively flexible supply resources because of the availability of hydro power
from Western and Calaveras;
¯Much of the largest and most cost-effective demand response opportunity with large
customers is already being realized via voluntary CPAU programs;
¯Lastly, program costs to serve small customers can be particularly high, and issues
regarding split incentives between tenants and owners can cause additional barriers to
implementation.
For these reasons, RMI did not undertake a rigorous analysis of demand response potential in
CPAU territory.
Details on Supply-Side Resources
RMI’s analysis estimates that the least expensive new generation options available to CPAU
consist of approximately 23 MW of combined cooling, heating and power (CCHP) units located
at five of the utility’s largest customers’ sites (see Section 6 for a comparison ofa CCI-t:P system
with both a cogeneration system and separate heat and power system). The estimated levelized
total resource costs of these units are between $0.05 and $0.06 per kWh. CCHP potential
increases to 35 MW for CPAU’s 13 largest customers. The maximum estimated CCHP potential
for CPAU customers if potential for the remaining medium to large commercial customers is
included is 50 MW. Based on RMI’s economic and technical assessments of multiple customer
sites, the range of 30-40 MW appears to be the practical maximum cost effective potential.
CPAU’s sites with CCHP potential are shown, ranked by increasing levelized total resource cost,
in Table 7. In all cases, this analysis assumes City ownership of these generation resources. The
most cost-competitive central generation resources analyzed were a conceptual 25 MW
cogeneration plant or a 25 MW share of a combined cycle gas turbine plant located in or near
Palo Alto. These resources are estimated to have levelized total resource costs of about
$0.06/kWh (at ~$6/MMBtu gas). Note that the economics of the cogeneration plant depend on
adequate utilization of its waste heat, which is especially uncertain for a large plank
18
Executive Summary
Table 7: CPAU Customer-Sited CCHP Potential, Ranked by Levelized Cost
Cost ResourceRank i
Customer 1
4.5 MW CCHP
Customer 224.5 MW CCHP
3 Customer 3
4.5 NW CCHP
Customer 444,5 MW CCHP
Customer 554.5 MW CCHP
12 MW Mid-size
6 Customers (8 x
average 1,5 MW)
6 MW Small
7 Customers (15 x
average 400 kW)
Annual Cumulative
Energy Energy
Delivered
GWh/GWh/yearyear
40 40
40 80
40 120
40 160
40 200
Total
Delivered
Cost
Million
S/year
$2.0 M
$2.2 N
$2.3 M
Levelized Total
Resource Cost of
Energy
Gas $6/MMBtu
S/kWh
$o.o51
$0.056
$0.059
$0.059
$0.060
$0.062100 300 $6,5 M
50 350 $4.6 M $0,087 $0.140
Levelized Total
Resource Cost of
Energy
Gas $12/MMBtu
S/kWh
$0.088
$0.098
$0.102
$0.103
$0.105
$0.108
The large customers’ sites, which make up the five least-expensive resources in Table 7, are all
assumed to be 4.5 MW systems with heat recovery for heating and cooling needs (using an
absorption chiller).12 The technology performance is based on the Mercury 50 turbine from
Caterpillar’s Solar Turbines division. This turbine is reasonably efficient, dispatchable, very low
in NOx emissions, compatible with heat recovery and thermally-activated cooling, and
competitive in terms of capital and operating costs, and several such systems are performing well
in commercial operatiom In addition, several such systems are performing well in commercial
operation. There are many other manufacturer’s models that may work well, also. Each of these
five customers appears to have sufficient potential thermal loads (including heat and cooling) for
CPAU to generate 4 - 6 MW of power while utilizing most or all of the generator waste heat.
As previously mentioned, RMI’s analysis of potential CPAU customer-sited CCHP resources
assumes City ownership of all systems. When the same systems were analyzed under customer
ownership, every realistic case looked unattractive from the customer’s economic perspective
under current retail rates. This unfavorable outlook is consistent with RMI’s observation that,
while several cogeneration developers evaluated prospects at CPAU customer sites, no deals
were closed. The primary reason for this lack of progress with CCHP in the past is simply that
customers demand a higher financial return and, specific to Palo Alto compared to PG&E, retail
electric tariffs are too low to make the savings from cogeneration worth the customer investment.
Under utility ownership, however, there is more oppommity. The utility’s lower cost of capital
and discount rate are important factors, but the key is that the utility sees the full marginal
avoided costs of electric supply, which has increased since the expiration of CPAU’s previous
~z Achieving the potentia! indicated above requires the use of waste heat for both cooling and heating. Use of waste
heat for heating only reduces cogeneration potential by 40%.
19
Executive Summary
contract with Western, along with the rest of the electricity market. There is also some flexibility
in how the utility recovers the costs for thermal energy derived from the waste heat of the
cogeneration process provided to host customers. We assume that the price of this thermal
energy (usually in the form of steam) is a fraction of the retail price of the equivalent energy
from natural gas. This value could be adjusted for each customer to balance the economic
performance from both the utility and customer perspectives under utility ownership.
Conclusion
Based on RMI’s evaluation of CPAU local resource potential, there appears to be significant
potential for cost-effective energy efficiency programs and CCHP production at customer sites.
Based on our initial screening, we recommend that CPAU complete detailed feasibility studies
for producing power locally from CCHP systems installed at large CPAU customer sites, based
on a financial model with utility ownership of the generation assets. Of course, CPAU can also
maintain the option for customers to install and operate CCHP systems on their own if they
choose. CPAU should also continue to study local central generation sources, based on either
combined cycle or simple combustion turbines, as well as the possibility of a large cogeneration
plant if a suitable heat load exists, such as at the wastewater treatment plant should operating
patterns change to allow greater use of medium temperature heat.
To capture the potential to expand efficiency investments, especia!ly in the commercial sector,
up to the full marginal supply costs, CPAU should augment program design a!ong the lines of
the recommendations listed above. With reasonably aggressive demand-side programs, CPAU
should be able to achieve up to 60-70 GWh in annual efficiency savings by 2015, which should
be enough to offset any load growth during that time. Cost-effective efficiency programs reduce
customer bills but can increase average rates. To capture the cost-effective efficiency potential,
CPAU should consider establishing a policy to reflect a true least-cost planning criterion to
reduce total costs and customer bills, while ensuring that efficiency programs are offered to the
broadest possible set of customers, so that all customers have the opportunity to participate.
20
Attachment B D R A F T
UTILITIES ADVISORY COMMISSION
DRAFT MINUTES OF MARCH 1, 2006: LEAP Excerpts
ITEM 3: LONG-TERM ELECTRIC ACQUISITION PLAN UPDATE (LEAP) -ACTION
Girish Balachandran gave a presentation on LEAP. We will not continue investigating a power
plant in Palo Alto. Commissioner Melton said in the original plan, which included investigating
generation in Palo Alto, his impression was that we made it through Phase I and based on that are
cutting it off. Melton asked Girish to talk about what staff found out. Balachandran said based on
what we found out doing our studies in Palo Alto, the infeasibility of siting large but efficient power
plants given that park lands are not available, the conclusion reached was to terminate studying
mid-size to large-size power plants in Palo Alto.
Dawes said he is surprised we are dumping NCPA opportunities. It seemed as though the
conditions were favorable. Dawes asked if this is related to the issue of having to contract within
the Greater Bay Area? Balachandran said the regulatory rules on capacity are not defined yet The
economics of getting power to the ISO and then to us is unknown. There are problems of how
transmission allocation costs get distributed. Commissioner Dawes was surprised that NCPA
would be making these decisions when these costs are not known and asked why are they
pursuing this so rapidly if we don’t have facts at our disposal to know to participate or not?
Balachandran said it’s all about risks. Timing is also a problem. Better timing would possibly be 2
years from now.
Greater Bay Area capacity issue: could be looking at a $6- $10 million hit on our resource costs.
We are fully resourced now, this would be additional capacity we would be expected to sell off on
the market. If everybody does it, there would be a lot of surplus on the market. How does this
impact our decision on siting and timing of our power plant? Balachandran said we have
generation split off from transmission. The rules could affect Palo Alto disproportionately.
Balachandran said we should be lobbying the people who make the rules to make Lodi part of our
local area and are being worked on right now. We do it through NCPA, TANC and Bay Area
municipal utilities. Given the alternatives we have right now, it does not make sense for us to enter
into a 30-year commitment given the uncertainties of the rules. You have to tag your energy back
to a defined area, the unknowns are where most of the capacity is not going to be counted. There
is no one in charge of actually building the California energy infrastructure. This continues to be a
dysfunctional market. There are different proceedings in place to deal with the situation and rules
today are better than they were 5 years ago but still not what they should be. The result is we are
going to delay on the plant investment and instead fill in the energy gap with contracts and issue an
RFP for local bay area resources. Commissioner Dawes thinks we should be more pro-active.
This is what we have to do given our situation.
Chairman Bechtel said we do have a proposal to deal with energy, the 2006 LEAP implementation
task.
Utilities Advisory Commission Draft Minutes from 3/1/06
Item 3 - LEAP Excerpts
Page 1 of 2
Attachment B D R A F T
Commissioner Melton asked if we are going to participate within the Greater Bay Area - how much
is there? Balachandran replied in the Greater Bay Area load is approximately 10,000 MW with
about 6,000 MW capacity in the Greater Bay Area. Together with the City of Santa Clara, we have
been looking at the feasibility of acquiring the Los Esteros plant.
Chairman Bechtel stated we should a better job of using Public Benefit monies to lobby in
government (through NCPA or CMUA) maybe have a position that does this. Chairman Bechtel
mentioned the Utilities web site needs a lot of improvement. He said he is hoping this information
will also get on the web site and talk about what Palo Alto is doing energy wise. It should be a big
deal as opposed to a bunch of links. His concern is we do not get saddled with extra costs just
because the legislature does not think we are doing enough. Yeats said part of the Oversight
Committee and the Long Range Plan wil! be a public communication program - it is not free but we
take on the responsibility of doing these projects. Balachandran said at meetings this month both
Simitian and Ruskin recognized us by name, saying they do not have an issue with Palo Alto, we
are doing a great job. There is a great threat in removing local control in public benefits. We
continue to work public relations, will continue to improve the web and work with other agencies.
Commissioner Dawes asked about Item 3, Efficiency Portfolio, Rocky Mountain Institute. The
Executive Summary has trotted out the same old list of stuff we have been working on for years.
We should not hang our hat on these very general things, we should be looking more seriously at
obtaining more supply generation capacity. Balachandran said efficiency is just a part of our
strategy. Commissioner Dawes said he does not see the meat in their report. Balachandran said
actual realistic targets will be set and will be brought back to the UAC in the Long Range Plan.
Chairman Bechtel referred to page 17 - we want low rates, sometimes if you can lower your bill
with a higher rate that is what we should push. Efficiency programs should include everyone -
including low income customers. LADWP is largest in state and may not be the best model for
US.
Commissioner Rosenbaum made the Motion to recommend that City Council approve the Local
Generation Feasibility Study Phase I recommendation to redirect the feasibility study efforts to
focus on local small-scale distributed cogeneration and potential power plant alternatives outside of
Palo Alto. Commissioner Dawes seconded. Motion passed: Unanimous.
Balachandran recognized everyone who contributed to this report.
Utilities Advisory Commission Draft Minutes from 3/1/06
Item 3 - LEAP Excerpts
Page 2 of 2