HomeMy WebLinkAboutStaff Report 406-06City of Palo Alto
City Manager’s Report
TO:
FROM:
DATE:
SUBJECT:
HONORABLE CITY COUNCIL
CITY MANAGER
NOVEMBER 6, 2006
UTILITIES ADVISORY
APPROVE ULTRA-CLEAN LOCAL
INCENTIVE PROGRAM GUIDELINES
DEPARTMENT:UTILITIES
CMR: 406:06
COMMISSION RECOMMENDATION .TO
DISTRIBUTED GENERATION
RECOMMENDATION
This report requests that City Council approve the program design guidelines for PLUG-In:
Power from Local Ultra-Clean Generation Incentive program, and direct staff to develop
incentives, rates, and rules for customer-sited small-scale distributed generation.
PROJECT DESCRIPTION
The Long-term Electric Acquisition Plan (LEAP) objectives and guidelines set the direction for
staff in planning and managing the electric supply portfolio. Council approved the LEAP
Objectives and Guidelines in 2001 and 2002 (CMR:425:01 and CMR:398:02). Staff updates the
Council at least annually on progress in implementing LEAP. The LEAP implementation tasks
were most recently updated in April 2006 (CMR: 169:06), including Council approval to redirect
the local generation feasibility study efforts toward development and implementation of a
comprehensive plan to facilitate and implement clean high-efficiency distributed small-scale
cogeneration, and evaluation of power plant ownership opportunities outside of Palo Alto, but
within or near the Greater Bay Area. The PLUG-In program will address the first element by
establishing incentives, rates, and rules for customer-sited small-scale distributed generation and
cogeneration, with an anticipated start date of July 1, 2007. The motivation, principles, and
proposed program guidelines are described in the attached UAC report.
BOARD/COMMISSION REVIEW AND RECOMMENDATIONS
The UAC discussion focused on the program purpose and the specific implementation process.
Key recommendations were to design the implementation plan to ensure equity in rate impacts
between customer classes, and to achieve as much net benefit as possible within the financial and
technical limits set by the guidelines. Staff will incorporate these recommendations in the
program design and implementation. The UAC voted unanimously to recommend approval of
the program design guidelines.
CMR:406:06 Page 1 of 3
RESOURCE IMPACT
The recommended program budget funding for incentives of $5 million over ten years would be
funded through electric rates as part of the commodity charge, and projects that qualify as
renewable or as R&D demonstration projects would be partly funded by Public Benefits funds of
up to $1 million out of the $5 million total. The incentives would be paid initially out of supply
rate stabilization reserves, and recovered slowly by the City’s portion of shared savings due to
avoided transmission and market power purchase costs. Ongoing costs will be accounted for and
reflected in the applicable electric and gas rates. The program is designed to achieve a modest
rate reduction over the long run, but in the worst case that the program became fully subscribed
but cost savings are not realized, the average $500,000 annual budget would translate to a rate
impact of approximately 0.05 cents per kWh, or about one-half of one percent. All projected
costs, savings and revenues of the PLUG-In program will be incorporated into future budgets,
starting with fiscal year 07/08.
POLICY IMPLICATIONS
This recommendation is consistent with LEAP Implementation Task #6: Clean Distributed
Generation, and also supports Tasks #1 (Climate Action Plan), #7 (Natural Gas-Fired
Generation), #8 (Greater Bay Area Contracts), #9 (Portfolio Management), and #10 (Risk
Management). The plan is also in accordance with the Utilities Strategic Plan, Energy Risk
Management Policies, the City’s Sustainability Policy, the Green Government Pledge, and
Comprehensive Plan Goal N-9 and Policy N-44 and N-47.
The program supports the California Publicly Owned Electric Utilities’ Principles Addressing
Greenhouse Gas Reduction Goals endorsed by Council (CMR:315:06).
In addition, the program supports several California and U.S. energy policies that encourage
greater utilization of high-efficiency distributed generation.
NEXT STEPS
Key next steps and anticipated timeline are as follows:
a. Finalize program design and implementation details, including eligibility, incentives,
rates, funding, agreements, forms, and process description: Winter 2006/2007.
b. Recommend Council approval of program implementation plan: Spring 2007.
c. Update zoning requirements to accommodate PLUG-In facilities: Early 2007.
d. Implement program: July 1, 2007.
ATTACHMENTS
A: UAC Report: Item 2 October 4, 2006
B: Draft UAC meeting minutes excerpts October 4, 2006
PREPARED BY:
KARL E. KNAPP
Senior Resource Planner
CMR:406:06 Page 2 of 3
DEPARTMENT APPROVAL:
CITY MANAGER APPROVAL:
VALEI~[IE O~. FONG
Director, Utilities
EMILY H~
Assistant City Manager
CMR:406:06 Page 3 of 3
ATTACHMENT A
MEMORANDUM
TO:UTILITIES ADVISORY COMMISSION
FROM:UTILITIES DEPARTMENT
DATE:OCTOBER 4, 2006
TITLE:APPROVAL OF ULTRA-CLEAN LOCAL DISTRIBUTED
GENERATION INCENTIVE PROGRAM GUIDELINES
REQUEST
Staff requests that the UAC recommend that City Council approve the program design guide!ines
for "PLUG-In": Power from Local Ultra-clean Generation Incentive program. The program will
establish incentives, rates, and rules for customer-sited small-scale distributed generation.
BACKGROUND
Council approved Palo Alto’s Long-term Electric Acquisition Plan (LEAP) Objectives and
Guidelines (Attachment A) in 2001 and 2002 (CMR:425:01 and CMR:398:02). The LEAP
Objectives and Guidelines set long-term directions for staff in planning and managing the
electric supply portfolio. The LEAP Implementation Tasks (Attachment B) were most recentiy
updated in April 2006 (CMR: 169:06), including Council approval to redirect the local generation
feasibility study efforts to (a) development and implementation of a comprehensive plan to
facilitate and implement clean high-efficiency distributed small-scale cogenerati0n, and (b)
evaluation of power plant ownership opportunities outside of Palo Alto, but within or near the
Greater Bay Area. This report addresses the first element.
The Rocky Mountain Institute (RMI) was engaged in 2005 to assist CPAU in evaluating its long-
term resource plans, which included a screening analysis conducted to estimate the potential for
customer-sited cogeneration opportm~ities, and to contrast cogeneration with conventional
generation and energy efficiency potential in an integrated framework. RMI presented its initial
results to the UAC in November 2005 and the final results were provided as an attachment to a
staff report to the UAC in March 2006. RMI identified up to 40 MW of technical potential, and
identified five customers whose monthly gas and electric load patterns were consistent with
facilities that may be able to support cost-effective CHPC. Two of the five have expressed
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 this group is estimated to be 3-12 MW, and
potentially up to 20 MW from all larger customers. Navigant Consulting independently
evaluated the costs and trade-offs for customer-sited cogeneration and central station
cogeneration and generation alternatives inside and outside of Palo Alto. Navigant’s results
Page 1 of 7
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.
DISCUSSION
Cogeneration is also known as combined heat and power (CHP). It is the practice of capturing
the heat from a generator that is otherwise wasted, in the form of steam, hot water, or hot air, and
applying it in some useful application, reducing the use of natural gas or other fuels that would
otherwise have been used to provide the same heat. Doing so can achieve very high overal!
efficiency. Cooling can also be achieved using heat-driven chillers (absorption or adsorption
chillers), reducing electric peak loads, and achieving even higher efficiencies. This practice is
often referred to as combined heat, power and cooling (CHPC), or "trigeneration".
Cogeneration achieves the highest overall efficiency and lowest net greenhouse gas emission of
any dispatchable power generation resource, achieves net cost savings, diversifies and reduces
electric portfolio price risk, enhances customer .and local reliability, reduces transmission and
distribution system losses, and facilitates attaining City and customer envircmmental goals. It is
small-scale enough to fit neatly into customer sites with negligible community impactsl Because
of their environmental advantages, cogeneration facilities smaller than 50 MW that meet
emission and noise criteria are explicitly granted a CEQA categorical exemption. Typical
applicable system sizes for the largest Palo Alto customers are in the 3-10 MW range.
California’s investor-owned utilities have operated a Self-Generation Incentive Program (SGIP)
since 2001, originally mandated by AB 970 (2000), which provides equipment rebates and
special retail rates to customers of investor-owned electric or gas utilities. CPAU customers are
not eligible, because both their electricity and gas are provided by the City. Notwithstanding this
lack of eligibility under California law, a decision of the California Public Utilities Commission
initially required wholesale gas customers such as the City to make contributions to Pacific Gas
and Electric Company’s SGIP program, effective July 1, 2005. The City successfully persuaded
the CPUC to modify its decision in order to exempt wholesale gas customers from the
contribution requirements of PG&E’s SGIP program. Thus, PG&E is now required to refund
approximately $90,000, including interest to the City. The City also avoids the obligation to
make future SGIP contributions of several hundreds of thousands of dollars. The requirement to
contribute, however, has not been completely extinguished; the CPUC’s Order states that it
"does not bar the possibility that PG&E’s wholesale customers maybe allocated SGIP costs in a
future Biennial Cost Allocation Proceeding." Implementation of the PLUG-In program could
serve to render unnecessary any future CPUC initiative to impose once again on the City the
obligation to make SGIP contributions.
The PLUG-In program is intended to achieve City and State policy objectives in a manner
similar to SGIP, building on the long stakeholder process used with SGIP and the lessons learned
from its development and evolution. The City’s program implementation will build on a
simplified version of the SGIP, but as proposed would incorporate additional features that are not
offered in SGIP. The fundamental guiding principles for the PLUG-In program and proposed
implementation approach in support of those principles are:
Page 2 of 7
1.Keep it Simple: Build on similar statewide programs; employ standard rates, rules and
agreements.
2.Foster Community Acceptance: Address visual, noise, other community concerns; keep
the public informed.
3. Cultivate Environmental Improvement: Require low net air emissions of pollutants and
greenhouse gases; offer bonus incentives for green certification and renewable energy
sources.
4.Achieve High Efficiency: Require stringent conversion efficiency standards; offer bonus
incentives for Energy Star and ultra-high-efficiency; conduct energy audits to identify
cost-effective demand-side efficiency measures.
5.Realize Cost Savings: Design rates to reflect full benefits and avoided costs, with shared
savings to the participant and the other utility customers; apply commodity pricing and
contracts policies in Rule and Regulation 5.
6. Mitigate Risk: Require adequate insurance, equipment warranty, and credit quality; limit
size of overall program and maximum size of any single facility; pay incentives based on
measured performance; design program to achieve resource diversity for the electric
portfolio.
7. Enhance Reliability: Apply clear interco~mection standards as defined in Rule and
Regulation 27. Provide capacity, dispatch rights, and emergency power redirection
capability. Added bonus for "islanding" capability (able to run in a blackout). Adhere to
NCPA and CAISO scheduling protocols.
8. Ensure Security and Safety: Adhere to intercolmection standards and City dispatch
procedures; owner to provide access to City staff to verify compliance.
9. Clear and Timely Reporting: Customer to meet all regulatory reporting requirements.
10. Encourage New Technologies: Added bonus for very high efficiency, low emissions,
peak reduction, pre-commercial technologies, environmental stewardship, or other
beneficial im~ovation.
The proposed basic guidelines to which PLUG-In detailed program design and implementation
should adhere are as follows:
Technical:
a. Eligible technologies include cogeneration, fuel cells, waste heat recovery, or
renewable energy conversion.
b. Eligible fuels include natural gas or renewable fuels as defined in Section 2805 of
the Public Utilities Code.
c. Cogeneration must meet and maintain FERC and State efficiency and thermal
’ energy utilization criteria.
d. All technologies must meet ultra-clean distributed generation efficiency and
emissions requirements established by the California State Air Resources Board.
e. Single system maximum size is 10 MW, and no larger than the greater of on-site
peak electric load or on-site peak thermal load.
f. Incremental water consumption from reclaimed or decontaminated groundwater.
Reliability
a. Owner shall provide "must-offer" obligation to CPAU. The City reserves the right
to instruct the generator to operate if it is off and available.
Page 3 of 7
o
b. City has the right to redirect power in an emergency.
c. Must comply with CPAU Rule and Regulation 27 - Interconnection Standards.
d. Ensure equipment availability and power generation performance acceptable to
the City.
Financial:
a. Ten-year program maximum is 20 MW or $5 million, whichever comes first.
b. Incentives shall be competitive with other programs available in the State, with
bonus incentives for high efficiency, low environmental impact, demonstration of
innovative new technologies, islanding capability, and electric demand reduction.
c. May be customer or third party owned.
d. Power may be sold to CPAU or net metered and surplus power sold to CPAU,
under the principle of full avoided cost with shared savings between CPAU and
host.
e. "Over-the-fence" transactions are not allowed (sale of energy to another CPAU
retail customer).
f. All rates and customer contracts shall adhere to Rule and Regulation 5 -
Contracts.
Procedural:
a. Satisfy all City zoning and permitting and other applicable requirements.
b. Owner must provide suitable access to the site, and comply with CPAU dispatch
requirements for safety and reliability
c. Must adhere to NCPA and CAISO power scheduling protocols.
d:Must comply with all data reporting regulations required of power generators.
e.Owner must maintain credit worthiness and insurance coverage during the term of
the agreement. -~
f. Equipment warranty of no less than 5 years.
g. Contract length no more than 20 years.
Legal: All aspects of the PLUG-In program, including but not limited to, the program’s
policies, procedures, guidelines, contracts, and forms, will be reviewed and approved
as to form by the City Attorney’ s Office.
Fuel cells, waste heat recovery, and renewable resources can also achieve many of the desired
benefits even without meeting the cogeneration definition, and are therefore also included in the
list of eligible technologies. Solar energy is the only in-town renewable resource with significant
technical potential to contribute to the electric supply needs in the near-term, and will continue to
be supported in the City’s solar programs separately from PLUG-In. Only generators using
natural gas or renewable fuels other than solar are eligible. A renewable fuel is a non-fossil
resource other than those defined as conventional in Section 2805 of the Public Utilities Code
that can be characterized as one of the following: solar, wind, gas derived from biomass, digester
gas, or landfill gas. Customer-sited projects utilizing wind or small hydroelectric resources are
not likely in Palo Alto.
As reported in the RMI study, small-scale cogeneration can achieve net greenhouse gas
emissions 25-30% lower than combined cycle power plants, and about half the state average
emissions per kWh, offering an effective means to lower greenhouse gas emissions associated
with electricity while also being cost-competitive with conventional alternatives. Even when
Page 4 of 7
using natural gas as a fuel, the reduced overall fossil fuel use due to reduced demand for power
from the grid combined with the efficient use of thermal energy results in a net reduction. Using
RMI’s estimates of net carbon intensities of 0.35 short tons/MWh for large customer CCHP and
0.62 for purchased market power, a 5 MW generator operating 75% of the time would generate
33,000 MWh per year, with a resulting reduction in carbon dioxide of 9,000 tons per year, equal
to the annual CO2 emissions from 775 average U.S. households (Source: U.S..EPA).
Staff recommends allowing and encouraging distributed cogeneration providers being able to sell
all electric output or any surplus power in excess of the on-site load to CPAU as part of its
diversified portfolio approach to electric supply. Inability to sell surplus power to the local utility
has been identified by the California Energy Commission and highlighted in the California
Integrated Energy Policy Report 2005 (page 77) as key means to expand the role of CHP in
meeting California’s power generation needs. These restrictions on surplus electric generation
also limit the ability to maximize efficiency of cogeneration equipment.
The 20 MW program limit corresponds to 14-17% of the City’s expected annual energy demand,
depending on the number of hours operating during the year. The current projected long-term
electric supply in a normal hydro year consists of 50% large hydro and 30-33% eligible
renewable resources, assuming that the remaining two landfill generators are completed and
NCPA is successful in purchasing the additional 15 MW authorized by Council (CM_R:296:06).
Should the PLUG-In program become fully subscribed, it would bring supply nearly in balance
with projected annual energy demand (which includes allowance for aggressive energy
efficiency efforts keeping energy demand growth flat).
To encourage ultra-clean energy technologies, staff recommends that applicable Palo Alto
zoning and permitting codes be updated to include small-scale cogeneration facilities in the
definition of resource conservation equipment in Section 18.04.030(86)c(i), which would exempt
such equipment from the Floor-to-Area Ratio (FAR) limits. Only enclosed equipment would be
subject to FAR, and staff recommends encouraging the use of enclosed equipment to reduce
noise and visual impacts without penalty. Planning Department staff is working to address codes
related to ultra-clean distributed generation in early to mid-2007 as part of the ongoing zoning
ordinance update work.
RESOURCE IMPACTS
The recommended program budget funding for incentives of $5 million over ten years would be
funded through electric rates as part of the commodity charge, and projects that qualify as
renewable or as R&D demonstration projects would be partly funded by Public Benefits funds of
up to $1 million out of the $5 million total. The incentives would be paid initially out of supply
rate stabilization reserves, and recovered slowly by the City’s portion of shared savings due to
avoided transmission and market power purchase costs. Ongoing costs will be accounted for and
reflected in the applicable electric and gas rates. The program is designed to achieve a modest
rate reduction over the long run, but in the worst case that the program became fully subscribed
but cost savings are not realized, the average $500,000 annual budget would translate to a rate
impact of approximately 0.05 cents per kWh, or about one-half of one percent. All projected
costs, savings and revenues of the program will be incorporated into future budgets, starting with
fiscal year 07/08.
Page 5 of 7
POLICY IMPLICATIONS
This recommendation is consistent with LEAP Implementation Task #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
enviromr~entally 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 !ow-impact
generation that can be located within Palo Alto.
In addition to LEAP Implementation Task #6, the PLUG-IN program also supports Tasks #1
(Climate Action Plan), #7 (Natural Gas-Fired Generation), #8 (Greater Bay Area Contracts), #9
(Portfolio Management), and #10 (Risk Management). The plan is also in accordance with the
Utilities Strategic Plan, Energy Risk Management Policies, the City’s Sustainability Policy, the
Green Government Pledge, and Comprehensive Plan Goal N-9 and Policy N-44 and N-47.
The program supports the California Publicly Owned Electric Utilities’ Principles Addressing
Greenhouse Gas Reduction Goals endorsed by Council (CMR:315:06).
In addition, Section 372 of California Public Utilities Code, "it is the policy of the state to
encourage and support the development of cogeneration as an efficient, environmentally
beneficial, competitive energy resource that will enhance the reliability of local generation
supply, and promote local business growth", and "to encourage the continued development,
installation, and interconnection of clean and efficient self-generation and cogeneration
resources, to improve system reliability for consumers by retaining existing generation and
encouraging new generation to connect to the electric grid, and to increase self-sufficiencY .of
consumers of electricity through the deployment of self-generation and cogeneration." The
proposed program fulfills the requirements Public Utilities Code Section 353.11, that a local
publicly owned utility review its rates, tariffs, and rules to identify barriers to and determine the
appropriate balance of costs and benefits of distributed energy resources in order to facilitate the
installation of these resources in the interests of their customer-owners and the state.
The program also supports the U.S. Energy Policy Act of 2005 requirements that electric utilities
deploy a mix of electric generation technologies with different fuel sources (PURPA Standard
12), and develop and implement a 10-year plan to increase the efficiency of its fossil fuel
generation (PURPA Standard 13).
Page 6 of 7
NEXT STEPS
Key next steps and anticipated timeline are as follows:
a. Council approval of PLUG-IN Guidelines - November 2006
b. Finalize recommended program design and implementation details, including
eligibility, incentives, rates, funding, agreements, forms, and process description.
c. Approval of program implementation plan: Spring 2007.
d. Zoning updates: Early 2007
e. Program into effect - July 1, 2007
ATTACHMENTS
A: LEAP Objectives and Guidelines approved by the Council November 2001/October 2002.
B: LEAP Implementation Plan Spring 2006
PREPARED BY: .
Karl E. Knapp
Senior Resource Plarmer, Utilities Resource Management
REVIEWED BY:
Girish Balachandran, Assistant Director of Utilities
Tom Auzerme, Assistant Director of Utilities
Tomm Marshall, Assistant Director of Utilities
Paul Dornell, Assistant Director of Utilities
DEPARTMENT HEAD:
Director,istrative Services
Page 7 of 7
Attachment A
Attachment A: Council Approved Electric Supply Objectives and Guidelines
The City 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:
1. Procuring resources at fixed price for at most 90% of expected load for 2 or
more years out, assuming average hydro conditions; and
2.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.
A-1
Attachment A
Guideline 4:Reliable and Cost Effective Transmission Services
Ensure the reliability of supply at fair and reasonable transmission cost by:
A.Supporting, through political and technical advocacy and!or direct investment, the
upgrading of Bay Area transmission to improve reliability and relieve congestion;
B.Participating in transmission market design to ensure that market design results in
workable competitive markets and equitable cost allocation;
C.Pursuing the option of forming and/or joining a Public Power Transmission Control
Area to increase control over transmission operations and related costs; and
. D.Ensuring PG&E honors the Stanislaus Commitments by providing to us firm-
transmission rights or equivalent.
Guideline 5: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.
Guideline 6: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 hot.to exceed 30 years in term.
Guideline 7:Electric Energy Efficiency Investments
Offer quality Public Benefits programs, utilizing fundscollected 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 programs to low-income customers.
A-2
2006 LEAP Implementation Plan Attachment B
Attachment B: 2006 LEAP Implementation Tasks
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 programs by developing a long-term
integrated resource efficiency portfolio plan 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).
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 programs will be recommended
to complement and enhance the existing Public Benefits programs. 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 program. 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 groundwork 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.
B-1
2006 LEAP Implementation Plan ,Attachment B
Natural Gas-Fired Generation: Redirect the local generation feasibility study C~ 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
(2S-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.
10.
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.
Risk Management: Devetop 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 upgrades in to the Bay Area to increase
reliability. Establish a policy to address mandatory resource adequacy requirements.
B-2
CMR 406:06 Attachment B Draft UAC Meeting Minutes Excerpts October 4, 2006
ATTACHMENT B
UTILITIES ADVISORY COMMISSION
MINUTES OF OCTOBER 4, 2006
Melton: Next item on the Agenda is the Approval of the Ultra Clean Local Distributed Generation and
Incentive Program. Karl has prepared some presentation on this.
Balachandran: I am going to start of with a couple of slides and then turn over to Karl Knapp. Dr. Knapp
will get credit for the acronym up there. I just wanted to go through a couple of slides just giving you an
overview. It is more of a reiteration of some concepts we talked about before. It is basically big picture
concept and motivation and then the rest of it including the recommendation will be handled by Karl. We
have come to you several times with the slide with what a long term resource plan looks like and we have a
long term shortfall in our energy situation. There are many uncertainties that still exist and will continue to
exist in the long term with our portfolio and the current market design, hydro uncertainty, transmission and
regulatory uncertainty. Our LEAP Plan is a diversified plan that looks at number of different elements. It
summarizes into 7 different elements that we look at and today we will be talking about the third element,
local cogeneration, actually one part of the third element. We have been coming to you over the last
several years the LEAP guidelines were approved by the Council in 2002. The Implementation Plan has
been updated as recently as in April 2006 was presented to the public through Utilities Advisory
Commission and the Council and we have been reporting on all the progress of the different areas-twice a
year. You have seen this basic long-term load-resource balance has been updated to assume that the
NCPA Green Power Pool project which was approved by the Council back in July is in place, assuming that
we actually get the 15 megawatts that we signed up from NCPA and so this shows our energy balance in
different kinds of hydro years in the long term. The policy motivations I did mention Clean Distributed
Generation is also supported by several other implementation tasks. We have several City Policies right
from Greenhouse Gas Principles which were adopted by the City Council to the Comprehensive Plan which
has several elements which support this initiative. The state-wide level and also Federal level have policies
which support.this program. With that I am goingto turn over to Karl Knapp to get into more details on the
program and make a recommendation.
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Melton: Before Karl starts I would like to just ask an overview question which was not clear to me in
reading the material. This is called the title of this is Approval of a Local Distributed Generation Incentive
Program, My question is really about the word ’Incentive’ and I am looking at this from the corporate
perspective. We have corporate customers out there who are going to work with us to do these
cogeneration plants on their site. They will do that if it makes economic sense, There is pretty long history
on gen. This is not rocket science anymore. What we are leading up to here a financial incentive program
to get companies to do this? Why on earth would we need to tap an incentive program? Because it seems
to me that this makes sense without any inceritive from us.
Knapp: Actually it is a financial incentive program and it is the combination of rates, rules and incentives.
Actual incentive is a small piece of it. The largest companies don’t need as much of an incentive upfront.
This is not only for just one or two customers but it is to provide the ability to and to make it economic for
them to do when there is an upfront cost that is pretty big. It becomes a big hurdle for not only small
companies but large companies. Without specific retail rates, the design for the kind of load shape that the
cogeneration system has, or incentives for innovative technologies like fuel cells or renewable supplies,
those other innovative technologies don’t take place. There are some other benefits similar to what we
have with energy efficiency in cogeneration that warrant an incentive especially since most of these
incentives paid upfront allows us to avoid transmission cost for the duration of the project. The idea is to
actually have it pay off to us in’the long run by paying upa little upfront to make it cost-effective for
customers but we also save money.
Melton: I guess I am not convinced that if it really is a cost-effective win-win situation that companies won’t
step up to it. If they are going to save money and if they got a good return on investment, we don’t have
to .....
Balachandran: We have a tag team on this. He gets to think while I talk, I think you are right on the face
of it. The companies should be doing what is in their economic best interest. There are additional benefits
that we get that we wouldn’t normally see and it enhances the reliability of the distribution system, We
have certain policy goals on greenhouse gas emissions which from their point of view, they would not
necessarily see some of the benefits of that. In addition to the answer that Karl gave that this program is
not purely a financially incentive program. It is also a program that would include the kind price signals
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through rates. That would incent them to put up their own capital. So the program that is going to be in
place which will include rates that would incent them to do it. But at the end of the day when you look at
the benefits for actually installing a distributor generator in customer facility there may be some net savings
where there could be split benefits for both parties. Maybe some of those will get clearer there, Karl does
have some slides which shows how the economic works to the benefits of both parties and how it gets split.
That gets into some pretty heavy details and maybe we can get to that later on in the presentation after we
get through the slides.
Knapp: Maybe a simpler answer, we will save money if our customers do it. Sharing some of the savings
to make it cost-effective for them, that is the incentive part. They may not save money while we would, and
by sharing what we will save, we can get them do it. That is good for everybody.
This is a repeat. I am pretty much following what is in the report but not in the same order. This is a list of
benefits that were highlighted, by Joel Swisher who was here back in November and again in the LEAP up
date in March. So cogeneration is going to achieve higher over efficiency and reduce emissions. I will not
read all the bullets. One key piece is near the bottom, it is just not the city but also some of our customers
have environmental goals of not only reducing gas (002) emissions but also eliminating refrigerants from
other facilities because those are also fairly important Greenhouse gases and we found in our local
generation feasibilities study that small scale system are those that might actually be feasible to help us
meet some of our resources locally that can provide reliability and transmission cost avoidance. The typical
sizes for the Palo Alto customers that were identified in that feasibility study somewhere between three and
10 megawatts that were each estimated at 4 ½ megawatts. When we got into more details what those
really look like, it depends strongly if you look at the monthly average gas bills as opposed to what is your
peak gas load during the day. So if you are trying to match your daily steam requirements during the day,
you might have slightly larger system to match that. That is the kind of range we are looking at. Also it is
just not cogeneration but there a lot of non cogeneration technologies like fuel cells. There are not many
renewable resources in Palo Alto that we can really deploy other than solar and solar is not going to be a
part of this program; that is really going to be rolled into the other solar programs. But if somebody wants
to get a windmill site in Palo Alto they can do it: That would be great. We would like to facilitate that but I
do not think we are going to try to build a wind farm in Palo Alto. We don’t know what is going to be around
in five years. So we want to make it available for people who can. There is a longer list of tables and some
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program principles that we developed over with people from several other different departments and
divisions as well as some large customers and some of thevendors who sent us information in resporise to
a Request for Information. These seem obvious in hind site but it took a while to develop some of the
details on how you might keep it simple by copying or building some other similar programs and using
standard rates and interconnection standards. We felt that community acceptance, cultivating
environmental improvement, achieving the high efficiency, realizing cost effectiveness and reducing risk,
benefits to reliability and security and safety are all im.portant. There are lots of reporting requirements that
are now coming out of the California Energy Commission and it goes all the way down to one megawatt
size power plant. We want to make sure that does not become an administrative burden for us by having
the data require~t for these generators from customers. So we have to make sure that they are going to
help us by doing the reporting as required. We also want to encourage these new technologies and kept
them out so that people can see and find out how it really works. The proposed guidelines that are in the
report have a lot more details than this..But basically just fell into 5 fundamental categories. There are the
technical guidelines meaning what kind of system is going to count, what fuels, make sure you meet high
efficiency and environmental standards and how big can they be and one of the issues that came up from
the other departments was not to have any water load to the system if it requires clean water. In terms of
reliability there are some guidelines which are listed in terms on how it gets operated: what is the
availability going to be, uptime, interconnection, the city having ability to call that it is not running, to ensure
that it actually provides reliability benefits that we listed on the slides (2 slides ago). Under the financial
section, how much you spend and make sure you have enough different systems: setting limits on the
maximum size not only the program and individual systems, also try to make sure we maintain
competitiveness, who owns it, rules on can customer use it to meet their load or they have too much to sell
it I~ack to utilities which we would like to encourage. What rules you have to follow for retail rates? We
already have rules and regulations having to do with customer contracts. Procedural gets into some of the
nitty gritty of everything from California ISO scheduling protocols to our own inter-connection standards and
contract length to warranty insurance. These may seem a little nitty gritty but we wanted to make a list of
guidelines that were general enough to give some flexibility to design but specific enough to design an
implementation plan. If it met these guidelines it would be pretty easy to implement. Of course all the
materials would be reviewed by City Attorney’S office. We are trying to make it so that there aren’t too
many of those but there are going to be some agreements that are required to do a program like this you
need 5, 10, 15 year agreements sometimes. To get to the Resource Impacts. This is just a bulleted form
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of the last paragraph in the report. But we are looking at potentially 5 million dollar incentive program over
10 years. About $500,000 a year program and we have.identified that out of the 5 million perhaps one
million dollar be funded through public benefits forthose R&D or renewable projects which are legitimately
public benefits funded. So anything from fuel cells to renewables, and right now the idea is that the
incentives may be paid initially out of supply reserves but also we are looking at the performance basis
incentives, which we are also looking at for solar rather than paying up all front you pay overtime based on
how it actually performs. The idea is that the incentives are paid out of the savings realized from avoided
transmission costs. So it is either paid upfront and paid back out of savings or you actually pay slowly
overtime out of your savings. Of course the on-going cost would be reflected in the applicable electric and
gas rates that you will all see on a regular budgetary cycle basis and that is where f the rules how you
quality will show up is in the rate and not in much complicated programs manual (1 am hoping). The worst
case would be if you spend all these five millions dollars and you did not realize any savings at all, that
would translate to .05 cents per kilowatt hour rate impact. It is worth at least looking at the extreme. About
½ percent. We hope to have all this together to start in the FY 07-08 so we will be working to get the
program in place so we can start by July. So that is the end of my presentation and I figured that I could
open up to questions. I would like to take approval of these guidelines to Council in November and so I am
asking the UAC to do is to recommend approval of these guidelines for the program which will then allow
us to finalize exactly what the program design should be to meet these guidelines. We got a start on it but
we kind of want to wait to make sure what the guidelines would be. Then approve it sometime in spring. In
parallel, which I mentioned in the report but not in the presentation, one of the recommendation is to update
the zoning ordinance to include in addition to what is now in there under Resource Conversation they have
thermal energy storage some other exemptions from the floor area ratio is to include cogeneration and
systems that would qualifyfor this program also under that. Because in order to maintain the noise low you
have to put an enclosure. Once there is an enclosure it could count against floor area issues. We would
like to encourage quiet ultra clean cogeneration by including that in the zoning ordinance so the Building
and Planning Department are planning to work on doing that as part of the zoning ordinance update and
get the program effective by July. So now I am open to questions.
Melton: Questions comments from Commissioners.
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Rosenbaum: Karl 1 always appreciate your presentation and plans and I have developed a fair amount of
confidence that you know what you are doing based on .past performance. There seems to be some
arbitrary elements here and perhaps you can comment on the 5 million dollars, 20 megawatts, on an
average 250 dollars a kilowatt is that what you are contemplating with. Where do these numbers come
from?
Knapp: The 20 megawatt came from that is the actual size of that red block in the center of the first slide
meaning there is our long term positions. If this program got fully subscribed 20 megawatts would make us
exactly 100 percent balanced on annual basis so this seems to be a good limit. Don’t buy more than we
need in a normal hydro year. The 5 million actually came from taking a look at what the Rocky Mountain
Institute did and trying to estimate what we actually expect people to sign up for this and so it came from
say one 9 or 10 megawatt system, a couple of 4 megawatts systems, half a kilowatt of fuel cells, perhaps
500 hundred kilowatts of smaller system that worked out. Using the current rebate levels that IOU’s used
similar programs called SGIP, that works out for the 5 million dollars. So if it is comparable to the incentive
programs that are elsewhere in the state that would be a 5 million dollar program what we want to set as a
limit not as the minimum .......
Rosenbaum: Maybe that is the answer. This SGIP Program is this PG&E’s?
Knapp: It is all of the investor-owned utilities.
Rosenbaum: All right. They are essentially offering up to 250 kilowatt incentive.
Knapp: It depends on which type of technology. Fuel cells are $2.50 a watt or 2500 dollars a kilowatt. The
cogeneration systems are 600 dollars a kilowatt. It ranges but there is a cap at one megawatt - so if you
put in a 5 megawatt system, you only get one megawatt worth of incentive.
Rosenbaum: What is the incentive to go from 1 to 5.
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Karl: The economy of scale makes it, It is mainly for the smaller systems that aren’t quite as cost effective.
It pushes them over the edge. It encourages the smaller distributed generation to get implemented it is a
higher percentage of the cost.
Rosenbaum: You speak of this as a 10 year program. How do you think that the money would actually go
out? Why couldn’t all five million dollars be spent in the first year.?
Knapp: Theoretically, I don~t think anyone other than one large customer got it seriously. It would
necessarily be a 500 hundred thousand dollars per year for 10 years straight line. If you could get this
done in 10 years would be great but if it is done in two years instead fine too,
Rosenbaum: Why is the 10 year mentioned why not call it a five million dollar program and when the 5
million dollar is up we should have our 20 megawatts and independent for how long it takes. I promised to
have a 10 year cogeneration plant so it you could call it 10 or more.
Rosenbaum: So the money will go out as money goes out. The $500,000 is just a sort of an average
annual commitment for 10 years.
Knapp: The idea is also to have a sunset date. So you don’t have an infinite potential program that goes
on forever after 10 years. Someone will have to take action to renew the program,
Rosenbaum: Now in terms of the expected energy to be generated you are talking about 20 megawatts
and 14 to 17 percent of the city’s energy needs which on the order of 160 thousand megawatt hours.
Knapp: 17% would be pushing it.
Rosenbaum: It seems to me that would be required running 20 megawatts 24 hours a day, Is that your
anticipation of how these would be used?
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Knapp: 14 % is closer to a little under 80 percent capacity factor. Some do run 100 percent. So it is close
to 100 percent. It is possible that you could get into 20 megawatt as running over 95% capacity factors.
But more realistically, it would be closer to 75 or 80 which is where the 14 percent number comes from.
Rosenbaum: To the extent where the cogeneration makes sense when you have processes going on to
these industrial processes that we have here in Palo Alto really run 24 hours a day 7 days a week.
Knapp: I think it would be closer to 75 percent, closer to 14 percent number
Rosenbaum: 75 % is 18 hours a day for 7 days a week is that iealistic?
Knapp: Correct. Although some of the smaller biotech companies turn out to have a pretty steady, 24
hours 7 days a week thermal load. I am not exactly sure what they are doing. Growing bugs. It depends
on who ends up doing in. Also once you have a cogen system people tend to change how they operate to
make a better use once you have the better equipment. It is more efficient.
Rosenbaum: Do you think you will be able to control how this money goes out so that it ends up with 20
megawatts. If you got a whole bunch of fuel cells proposals or are we going to use up five million dollars
and produce a good deal less than 20 megawatts, you would say ’No’ how are you going to work that out?
Knapp: I think that is the limit on the subsidy portion being about a million dollars is once that part is gone;
it will be a different amount of money for the different technologies. We haven’t actually set that part as yet.
It wouldn’t all go to one technology.
Rosenbaum: Maybe that was a poor example but conceivably the five million dollars could be spent before
you got 20 megawatts of generation. Depending on what choices are made. Is that going to be
acceptable? Or are you going to pick and choose. Is that going to be acceptable or somehow you are
going to pick and choose and say ’No’ to people because there is not enough bank for the incentive buck
what they are proposing,
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¯ Knapp: I think the idea is to set the incentives so that you are saving money. At least breaking even
regardless of what size it is. Instead of 5 million dollars you got 10 megawatts instead Of 20. You are still
saving money then it may be time to expand the program. I think if we follow the guidelines, the intent of
sharing the cost savings to pay for the incentive you may not get the 20 megawatts. But to get the 20
megawatts or 5 million dollars first, you stop.
Rosenbaum: So we are not necessarily going to get 20 megawatts,
Knapp: Right, I cannot guarantee that.
Rosenbaum: Maybe that wasn’t clear in the report. Because you want to get 14 to 17 percent of our load
that requires 20 megawatts and we are supposed to spend five million dollars and now you are telling me
well we may only get 7 to 10% of our load for 5 million dollars. That does not sound good. My question is
how can you control some of the projects will probably require a smaller incentive to get it to work than
others, Are you going to influence those decisions in some ways so that we will get what is setting out to
get.
Knapp: I think we can control the outflow of the money so that it is actually net inflow. Primary goal is not
to get 20 megawatt but to get as much as internal generation from ultra clean distributed generation as you
can spending the 5 million dollars in a cost effective way.
Rosenbaum: Alright, Thank you.
Bechtel: Karl this seems to be a very complex program to put together and administer and so on. Have
you looked at the internal staffing requirements or external staffing requirements going to be required to
administer these programs? I looked at the list of permitting on procedural access dispatch, safety
scheduling, reporting credit insurance warranty and all of those factors I see. I feel to deal with our state
bureaucy created by our deregulation, I see many many hours of staff. Am I right or wrong? What is it
going to take to minister the program?
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Knapp: Actually doing the ISO piece is the scheduling which would be done through NCPA. Luckily we
have some experience with their day-to-day scheduling protocols which they deal with. Everything from
small one megawatt, landfill i generators up to Calaveras. Whoever owns the generator follow these
procedures and they are not that complicated: let people know when you are going to shut your equipment
down, when it is going to run tomorrow. If it goes down you have to notify within half an hour. That is not
Palo Alto staff. That is whoever owns the generator.
We can facilitate that because we have a SCADA system, because we have a UCC dispatch center that is
manned 24 hours a day. The other rules like dispatch have to deal more with communications with people
who are already on staff because when dispatch is going to shut off a switch for example near Stanford
Research Park and you’ve got a generator running you need to know it is time to turn it off. It is more
coordinating with our Utility Control Centers for most of the other safety and reliability issues. Staff time it
turns out does not look like it is going to be much more than it takes to manage a new large photovoltaic
rebate type of program. Because the on-going operation would have to be taken on by either the company
or the third party that would actually put a system in for them. The larger systems would probably be more
like Chevron Energy Solutions, or Real Energy or Fuel Cell energy, who own cogeneration systems all over
the country. In this building we dea! more with a month ahead and our day-to-day goes through operations
and NCPA and they seem to think it is not a big deal. We are also expected to 4 or 5, not hundreds of
cogeneration systems.
Bechtel: So that is 4 or 5 and you divide 4 and 5 into 20 megawatts and those are pretty good size (co
bug) systems.
Knapp: I do not think we will have four 5 megawatt systems. We might have two that are over megawatt
and a couple of small ones. The small ones that are under megawatt you do not have to do any of the
scheduling. It is just like behind the meter.
Bechtel: Distribution system in which you are pumping power in when there are various pumps it may not
be a big deal. It seems to me though it is goingto take a lot of work. From the way you are answering the
questions it sounds like you thought thru all these requirements. In regard to what stages and our focus
passing down for local generation I am trying to catch up with that are we going to be satisfying some
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requirements that are ready. Are we ultimately going to do this anyway in terms of local generation?
Where are we now in requirement to have local generation?
Knapp: We have actually two requirements that I listed. One is the Public Utility Code requires that we
have a public hearing and we review our rates, rules, and regulations on facilitating distribution generation.
But you are not required just necessarily have it. So part of this program is to actually facilitate those who
want to do clean distribution generation to do so. But actually having to put it in is not part of the law. The
Energy Policy Act has two sections that we are supposed to be doing which is increase the efficiency of our
fossil fuel generation which we don’t have any. So any fossil fuel generation that we do get on line would
be extremely high efficiency if it is this. I forgot the other epact standard. I think I have listed this
for you. Standard 12 having to do with diversity and that for me is having power purchase agreements with
couple of co-generators accomplishes many of the same goals of buying say a tolling contract or gas power
plant contract outside Palo Alto So you get the same type of diversification of your resources as you would
if you just did a spot purchase from the market. You get a little bit of natural gas component of your
portfolio. So those are kind of general requirements as opposed to being specific. There are a few others
and nothing mandates that we have self-generation incentive programs. It was a discussion in there about
as already being billed for not having one and getting the money back.
Bechtel: Lastly, what are we looking at in terms of cost for let’s say one of our customer puts in 5
megawatt generator or some sort can you give me a range of $ per megawatt.
Knapp: Around $2000 per kilowatt. So you look at up to 10 million dollars for 5 megawatts system.
You can also go from 5 to 10 and you will only go from like maybe 8 or 11 million dollars. There is a large
difference in dollars per ki.lowatt as you jump from 4 up to 10 megawatts.
Bechtel: If someone installs lets say 5 megawatts I don’t know what the total load would be right on the top
of my head, what would be their annual electricity bill.
Knapp: Someone who has 10 megawatts, probably around 3 million bucks?
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Bechtel: I am just trying to get a scale of what kind of dollars we are looking at for this particular...
Rosenbaum: 10 megawatts is 80 thousand megawatts hours. That 80 dollars of megawatt per hour ...it is
6.4 million dollars a year.
Bechtel: So if the bill is about 6.4 they are going to be paying let say about 10 for something like that so
okay. At least from the scale point of view and so on the numbers ran the right range so this is serious
stuff.
Knapp: Most of the savings actually comes from the reduced use of gas and the boiler.
Bechtel: What I was getting at is what is the likely hood what if you had to go to your boss and you have to
go to division headquarters or corporate headquarters for approval of a project like this you want to have
big numbers that you can toss around about what kind of a scale you are talking about here. Thank you.
Beecham: John, I need to go. I apologize.
Keller: I have a couple of questions. My understanding which may not be right is that commercial,
industrial customers tend to be subsidizing residential customers base. Is that true here?
Lucy: ’No’
Keller: It use to be true in PG&E land 10 years ago. I am all for cogeneration. I.am puzzled by if you
encourage more cogen and somehow it has been subsidized which is a little over my head here, are you
also losing some of the subsides that provides for residential base. Is that something that would continue
on forever, is that something that would continue on forever. Has that being compensated for in these
rates that you will be developing? Does that make any sense?
Knapp: I do not know if I can answer that subsidy question. Most of the people have very similar rates.
The goal of the guideline as I stated here is not have any cross subsidy and that is basically they would pay
for the gas just like they are any other customer with a load shape that a co-generator would have.
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Keller: I don’t mean the difference between cogen and non cogen, Is this industry commercial vs
residential aren’t the rates different? Aren’t they such that the residential rates are lower because of the
presence of the industrial and commercial ratepayers. That is how it was an experience that I had before,
Balachar~dran: The way the rates are done is done on cost of service basis. So to the extent that we have
a lot of industrial commercial customers with fiat loads. The overall cost for the entire system is lower
compared to if you had a load that was peaky. So you look at the total system cost then there is cost
allocation mechanism that happens on allocating those costs to customers. So overall system cost would
depend on the ratio of commercial customers to residential customers but more important is the load shape
that would matter,
Keller: What I am thinking about is my manager was describing at Dust borough if you start losing
commercial and industrial customers and the residential rates have to go up they are start losing them to
other this is when deregulation was hitting and this is what was described. So my question is if that is the
case which perhaps not appropriate here, how do you compensate for that loss to the residential side if the
cogen plants are successful to last 20 years or whatever. Are you saying that is not the issue on this case?
Knapp: The commercial distribution rates in Palo Alto are lower than residential rates.
Keller: Are we losing some of our loads by encouraging cogen where they produce their own power and
you do not have them as customer anymore.
Knapp: All of the customers that we have spoken to prefer are basically to continue to buy electricity from
Palo Alto and sell electricity directly to Palo Alto from cogen unit. I will explain that. Their gas requirements
actually goes up by using cogen but their overall bills ends up going down. What happens is it is basically
is a power purchase agreement between the utility and cogeneration unit, They buy the mix so what
happens is nearly half of their load is coming from Western (37%). Our avoiding cost is the market price
which is pretty high : 8 cents these days. But our average cost is very low. So they are better of taking the
retail rate and selling it at wholesale than they are self producing. They don’t really want to be in the
generation business either. So it is a kind of funny position of our avoided cost being higher th~n our
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average cost and so we have a unique opportunity to have someone who owns a generator basically to sell
power to the city and they buy it back. So it is not necessarily a loss of revenue. For those customers who
do want to have behind their meters they are certain non-bypassable charges that you would have. You
still pay for the public benefits on the total load and not just on your net load and a couple of things that I
thought would be included for the smaller systems.
Melton: So can I jump in to get a clarification on that because it was one of the questions I was going to ask
anyway. You madea point in here that the access on line load, excess load, generation capacity they sell
back to us at what rate?
Knapp: I will let you know when Lucy is done with her cost of service study that includes cogeneration.
She has a consultant working on that now to figure out what would you have as a cogen gas rate, what
would you have as an electricity buy back rate, and how you would tie them together. Because one could
be a fixed price but may actually be a multiple of gas price. Like a tolling contract.
Melton: My question was really simpler than that. Maybe all that I am looking for is the word ’wholesale’ or
’retail’ I read somewhere in order to incentivize people to put in systems like this or photovoltaic the sell
back rate to the Utility has been the retailed rate, has been the directed things so that if a company
produces power and puts it back on the grid they get credit at the retail rate. That does not make any
sense for us if that is the plan is it.
Knapp: That is only true for solar and wind. Qualifying facilities which is the fancy word for cogeneration or
other facilities, SRAC which is a sort run of avoided cost which is big long formulae which is basically gas
price times the heat rate. For PG&E it is not the retail rate, it is basically the wholesale avoided cost. That
is how we want to design ours is to reflect our total avoided cost with some shared savings and how much
we are saving on transmission. It is not just cost of NP-15 electricity in Bakersfield but all the losses from
Colorado to wherever you are generating it. We have fairly high losses in Stanford Research Park for
example so there are few bonuses that we get for every one Kilowatt we don’t buy say at HP or something,
it is 1.1 kilowatts we are not buying in Colorado. So when we add all those up. That is the cost that we
would like to be paying for that electricity and no more.
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CMR 406:06 Attachment 13 Draft UAC Meeting Minutes Excerpts October 4, 2006
Keller: ! have one very small point. Would we be ever be required to buy back the power? PG&E was
required to buy back when they were dumping power. Palo Alto has never been that position with the
cogen?
Knapp: Actually as I understand it,. we would be required now if someone put in a co-generator and said 1
want to sell you the power.
Keller: Would we be required to buy it.
Knapp: The host utility is required to buy at their short run avoided cost, then you get to define what that is.
Keller: Would there ever be a scenario when you will not want to buy that power?
Knapp: You are not required to buy it if you do not need it.
Keller: We are always required to purchase it when the co-generator wants to sell it to us.
Knapp: Until the California ISO has a two-day ahead market and then PURPA is being changed right now.
The Public Utilities Regulatory Policy’s Act having to do with just that issue right now which is they are
redefining what is useful thermal energy and redefining when does the utility have to buy back. So there is
a possibility that we wouldn’t have to. But we like to because we get all these other benefits like reliability,
we can actually save some money.
Melton: Any other questions? Can I have a motion?
Rosenbaum: Mr. Chairman, This is a pretty complicated proposal but I was quite serious when I said I
have a lot of faith in Karl based on (you too Carl Yeats) but in this case Karl Knapp based on his past
performance and I am sure he anticipated these sorts of questions that we have raised so I will be happy to
move the staff recommendation which is that we recommend to the City that the City Council approve the
program designed guidelines for Plug-In power from the Local Ultra clean Generation Incentive Program.
Bechtel: second
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CMR 406:06 Attachment B Draft UAC Meeting Minutes Excerpts October 4, 2006
Motioned by Rosenbaum and second by Bechtel and all in favor say ’Aye’
Bechtel ’Aye’ Keller ’Aye’, Melton ’Aye’ Rosenbaum ’Aye’ carried unanimously.
Respectfully submitted,
Jennie Castelino
City of Palo Alto Utilities
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